Edgar Filing: ARIZONA PUBLIC SERVICE CO

e10vq

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, 2006


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

For the transition period from to


Commission File Number	Exact Name of Each Registrant as specified in its charter; State of Incorporation; Address;	IRS Employer Identification No.

	and Telephone Number

1-8962	PINNACLE WEST CAPITAL CORPORATION	86-0512431
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, Arizona 85072-3999
	(602) 250-1000
1-4473	ARIZONA PUBLIC SERVICE COMPANY	86-0011170
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, Arizona 85072-3999
	(602) 250-1000

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


PINNACLE WEST CAPITAL CORPORATION	Yes þ	No o
ARIZONA PUBLIC SERVICE COMPANY	Yes þ	No o

Indicate by check mark whether the registrant 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 filer þ Accelerated filer o Non-accelerated filer o

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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


PINNACLE WEST CAPITAL CORPORATION	Yes o	No þ
ARIZONA PUBLIC SERVICE COMPANY	Yes o	No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.


PINNACLE WEST CAPITAL CORPORATION		Number of shares of common stock, no par value, outstanding as of November 3, 2006: 99,847,829

ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of November 3, 2006: 71,264,947

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

This combined Form 10-Q is separately 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.

TABLE OF CONTENTS


			Page

Glossary				2
Part I				4
	Item 1.	Financial Statements		4
		Pinnacle West Capital Corporation		4
		Arizona Public Service Company		35
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		45
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		71
	Item 4.	Controls and Procedures		71

Part II				72
	Item 1.	Legal Proceedings		72
	Item 1A.	Risk Factors		72
	Item 5.	Other Information		72
	Item 6.	Exhibits		74
Signatures				76
EX-10.1
EX-12.1
EX-12.2
EX-12.3
EX-31.1
EX-31.2
EX-31.3
EX-31.4
EX-32.1
EX-32.1
EX-99.1
EX-99.2

GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – Administrative Law Judge

APB – Accounting Principles Board

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

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

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

EITF – FASB’s Emerging Issues Task Force

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

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

IRS – United States Internal Revenue Service

kWh – kilowatt-hour

Moody’s – Moody’s Investors Service

MWh – megawatt-hour, one million watts per hour

NAC – collectively, NAC Holding Inc. and NAC International Inc., subsidiaries of El Dorado that were sold in November 2004

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

NPC – Nevada Power Company

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned 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

PRP – potentially responsible party

PSA – power supply adjustor

PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3

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, a 570-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles north of Las Vegas, Nevada

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

SunCor – SunCor Development Company, a subsidiary of the Company

Sundance Plant – 450-megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

Trading – energy-related activities entered into with the objective of generating profits on changes in market prices

2005 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2005

VIE – variable interest entity

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,
	2006			2005
OPERATING REVENUES
Regulated electricity segment	$	886,979		$	753,428
Marketing and trading segment		84,425			107,031
Real estate segment		97,871			78,755
Other revenues		7,167			16,369

Total		1,076,442			955,583

OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		314,150			203,519
Marketing and trading segment fuel and purchased power		80,906			86,945
Operations and maintenance		164,396			158,940
Real estate segment operations		78,853			67,508
Depreciation and amortization		90,390			85,763
Taxes other than income taxes		31,697			34,325
Other expense		5,610			13,521
Regulatory disallowance		—			143,217

Total		766,002			793,738

OPERATING INCOME		310,440			161,845

OTHER
Allowance for equity funds used during construction		3,178			2,852
Other income (Note 14)		18,055			8,694
Other expense (Note 14)		(3,693	)		(4,915	)

Total		17,540			6,631

INTEREST EXPENSE
Interest charges		50,577			46,778
Capitalized interest		(5,612	)		(3,301	)

Total		44,965			43,477

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		283,015			124,999
INCOME TAXES		98,836			40,305

INCOME FROM CONTINUING OPERATIONS		184,179			84,694
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense of $3 and $12,407 (Note 17)		(12	)		19,043

NET INCOME	$	184,167		$	103,737

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		99,491			98,697
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		99,973			98,816

EARNINGS PER WEIGHTED – AVERAGE
COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	1.85		$	0.86
Net income – basic		1.85			1.05
Income from continuing operations – diluted		1.84			0.86
Net income – diluted		1.84			1.05
DIVIDENDS DECLARED PER SHARE	$	0.50		$	0.475

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,
	2006			2005
OPERATING REVENUES
Regulated electricity segment	$	2,065,823		$	1,749,110
Marketing and trading segment		259,352			267,460
Real estate segment		318,328			232,950
Other revenues		28,173			46,763

Total		2,671,676			2,296,283

OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		735,489			442,532
Marketing and trading segment fuel and purchased power		227,797			215,347
Operations and maintenance		511,155			467,121
Real estate segment operations		248,595			190,555
Depreciation and amortization		267,308			262,030
Taxes other than income taxes		99,970			103,528
Other expenses		22,562			39,451
Regulatory disallowance		—			143,217

Total		2,112,876			1,863,781

OPERATING INCOME		558,800			432,502

OTHER
Allowance for equity funds used during construction		10,612			8,407
Other income (Note 14)		34,448			18,019
Other expense (Note 14)		(12,953	)		(12,985	)

Total		32,107			13,441

INTEREST EXPENSE
Interest charges		143,985			142,820
Capitalized interest		(14,595	)		(10,134	)

Total		129,390			132,686

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		461,517			313,257
INCOME TAXES		154,900			113,863

INCOME FROM CONTINUING OPERATIONS		306,617			199,394
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $1,415 and $(28,586) (Note 17)		2,159			(44,474	)

NET INCOME	$	308,776		$	154,920

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		99,277			95,642
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		99,723			95,755

EARNINGS PER WEIGHTED – AVERAGE
COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	3.09		$	2.08
Net income – basic		3.11			1.62
Income from continuing operations – diluted		3.07			2.08
Net income – diluted		3.10			1.62
DIVIDENDS DECLARED PER SHARE	$	1.50		$	1.425

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,
	2006			2005
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	128,222		$	154,003
Investment in debt securities		203,317			—
Customer and other receivables		576,107			502,681
Allowance for doubtful accounts		(5,536	)		(4,979	)
Materials and supplies (at average cost)		116,867			109,736
Fossil fuel (at average cost)		21,679			23,658
Assets from risk management and trading activities (Note 10)		617,440			827,779
Assets held for sale (Note 17)		22,575			202,645
Other current assets		81,145			75,869

Total current assets		1,761,816			1,891,392


INVESTMENTS AND OTHER ASSETS
Real estate investments – net		495,965			390,702
Assets from long-term risk management and trading activities (Note 10)		216,129			597,831
Decommissioning trust accounts (Note 18)		326,318			293,943
Other assets		127,153			111,931

Total investments and other assets		1,165,565			1,394,407


PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		11,077,611			10,727,695
Less accumulated depreciation and amortization		3,778,560			3,622,884

Total		7,299,051			7,104,811
Construction work in progress		349,603			327,172
Intangible assets, net of accumulated amortization		93,868			90,916
Nuclear fuel, net of accumulated amortization		64,780			54,184

Net property, plant and equipment		7,807,302			7,577,083


DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		209,017			172,756
Other regulatory assets		188,368			151,123
Other deferred debits		125,131			135,884

Total deferred debits		522,516			459,763


TOTAL ASSETS	$	11,257,199		$	11,322,645

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,
	2006			2005
LIABILITIES AND COMMON STOCK EQUITY

CURRENT LIABILITIES
Accounts payable	$	315,027		$	377,107
Accrued taxes		416,401			289,235
Accrued interest		43,839			31,774
Short-term borrowings		57,400			15,673
Current maturities of long-term debt		85,440			384,947
Customer deposits		69,088			60,509
Deferred income taxes		12,389			94,710
Liabilities from risk management and trading activities (Note 10)		523,797			720,693
Other current liabilities (Note 10)		157,889			297,425

Total current liabilities		1,681,270			2,272,073


LONG-TERM DEBT LESS CURRENT MATURITIES		3,237,423			2,608,455


DEFERRED CREDITS AND OTHER
Deferred income taxes		1,174,003			1,225,253
Regulatory liabilities		588,957			592,494
Liability for asset retirements		282,060			269,011
Pension liability		267,744			264,476
Liabilities from long-term risk management and trading activities (Note 10)		194,196			256,413
Unamortized gain – sale of utility plant		42,325			45,757
Other		394,149			363,749

Total deferred credits and other		2,943,434			3,017,153


COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13 and 15)

COMMON STOCK EQUITY
Common stock, no par value		2,094,942			2,067,377
Treasury stock		(406	)		(1,245	)

Total common stock		2,094,536			2,066,132

Accumulated other comprehensive income (loss) (Note 11):
Minimum pension liability adjustment		(97,277	)		(97,277	)
Derivative instruments		44,200			262,397

Total accumulated other comprehensive income (loss)		(53,077	)		165,120

Retained earnings		1,353,613			1,193,712

Total common stock equity		3,395,072			3,424,964


TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,257,199		$	11,322,645

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,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	308,776		$	154,920
Adjustments to reconcile net income to net cash provided by operating activities:
Silverhawk impairment loss		—			91,057
Regulatory disallowance		—			143,217
Depreciation and amortization including nuclear fuel		288,065			292,190
Deferred fuel and purchased power		(231,388	)		(142,806	)
Deferred fuel and purchased power amortization		195,127			—
Allowance for equity funds used during construction		(10,612	)		(8,407	)
Deferred income taxes		3,598			(51,045	)
Change in mark-to-market valuations		16,974			(29,785	)
Changes in current assets and liabilities:
Customer and other receivables		(72,154	)		(126,450	)
Materials, supplies and fossil fuel		135			(15,581	)
Other current assets		16,294			(33,750	)
Accounts payable		(69,608	)		7,505
Accrued taxes		130,137			137,853
Collateral		(176,110	)		229,746
Other current liabilities		35,647			21,829
Proceeds from the sale of real estate assets		27,144			15,020
Real estate investments		(94,533	)		(59,527	)
Change in risk management and trading – liabilities		(132,540	)		171,841
Change in other long-term assets		(6,609	)		(909	)
Change in other long-term liabilities		54,880			90,091

Net cash flow provided by operating activities		283,223			887,009


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(534,370	)		(471,274	)
Capitalized interest		(14,595	)		(10,134	)
Purchase of Sundance Plant		—			(185,046	)
Proceeds from the sale of Silverhawk		207,620			—
Proceeds from the sale of real estate investments		2,134			82,671
Proceeds from nuclear decommissioning trust sales		170,827			136,202
Investment in nuclear decommissioning trusts		(186,383	)		(149,440	)
Purchases of investment securities		(739,996	)		(2,567,237	)
Proceeds from sale of investment securities		536,679			2,679,691
Other		(2,246	)		132

Net cash flow used for investing activities		(560,330	)		(484,435	)


CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		703,283			911,815
Repayment of long-term debt		(384,800	)		(734,163	)
Short-term borrowings and payments – net		41,659			(19,975	)
Dividends paid on common stock		(148,876	)		(137,234	)
Common stock equity issuance		24,574			290,542
Other		15,486			(5,672	)

Net cash flow provided by financing activities		251,326			305,313


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(25,781	)		707,887

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		154,003			163,366


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	128,222		$	871,253


Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	71,901		$	52,433
Interest paid, net of amounts capitalized	$	113,408		$	119,670

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 wholly-owned subsidiaries: APS, Pinnacle West Energy (dissolved as of August 31, 2006), APS Energy Services, SunCor and El Dorado. 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. We have reclassified our prior year cash flow amounts related to our decommissioning trust activity to reflect the proceeds and investments separately versus a net presentation.

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 to condensed consolidated financial statements be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2005 Form 10-K.

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

In January 2006, Pinnacle West infused $210 million of the proceeds from the sale of Silverhawk into APS. See “Equity Infusions” in Note 5 for more information.

On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).

On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

2006, to fund its construction program and for other general corporate purposes. A portion of the proceeds may also be used to pay any liability determined to be payable as a result of the review by the IRS of a tax refund the Company received in 2002.

On September 28, 2006, APS put in place an additional $500 million revolving credit facility that terminates in September 2011. APS may increase the amount of the facility up to a maximum facility of $600 million upon the satisfaction of certain conditions. APS will use the facility for general corporate purposes. The facility can also be used for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.

The following table shows principal payments due on Pinnacle West’s (on a consolidated basis) and APS’ total long-term debt and capitalized lease requirements (dollars in millions) as of September 30, 2006:


Year	Pinnacle West		APS
2006	$	85	$	84
2007		4		1
2008		175		1
2009		8		1
2010		225		224
Thereafter		2,836		2,661

Total	$	3,333	$	2,972

Pinnacle West and APS hold investments in debt securities (auction-rate securities) for purposes other than trading. We believe that the carrying amounts of these investments represent reasonable estimates of their fair values at September 30, 2006 due to the short-term reset of interest rates.

5. Regulatory Matters

APS General Rate Case

APS Request. On October 4, 2006, APS filed with the ACC its rejoinder testimony in the general rate case it originally filed on November 4, 2005 and updated on January 31, 2006. In the rejoinder filing, APS modified the rate request to reflect a 20.4%, or $434.6 million, increase in its annual retail electricity revenues. Hearings in the general rate case began on October 10, 2006.

The updated requested rate increase is designed to recover the following (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


							January 31, 2006
	October 4, 2006 Filing						Filing
	Annual						Annual
	Revenue			Percentage			Revenue			Percentage
	Increase			Increase			Increase			Increase
Increased fuel and purchased power	$	314.4			14.8	%	$	299.0			14.0	%
Capital structure update		98.3			4.6	%		98.3			4.6	%
Rate base update, including acquisition of Sundance Plant		46.2			2.2	%		46.2			2.2	%
Pension funding		41.3			1.9	%		41.3			1.9	%
Other items		(65.6	)		(3.1	)%		(30.9	)		(1.4	)%


Total increase	$	434.6			20.4	%	$	453.9			21.3	%

The request is based on (a) a rate base of $4.5 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.0325 per kWh based on estimated 2007 prices; and (c) a capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity).

The updated request does not include the PSA annual adjustor rate increase of approximately 5% that took effect February 1, 2006, the PSA surcharge increase of approximately 0.7% that took effect May 1, 2006, or APS’ pending application for a 1.9% PSA surcharge rate increase. See “Power Supply Adjustor” below. If the ACC approves the requested base rate increase for fuel and purchased power costs (see clause (b) of the preceding paragraph), subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs are likely to be recovered in base rates.

APS has also suggested three additional measures for the ACC’s consideration to improve APS’ financial metrics while benefiting APS’ customers in the long run:

	•		Allowing accelerated depreciation to address the large imbalance between APS’ capital expenditures (estimated to average more than $900 million per year from 2007 through 2009) and its recovery of those expenses (in discussing this measure, APS assumed an increase of $50 million per year in allowed depreciation expense, which would increase APS’ revenue requirement by that same amount );

	•		Placing generation and distribution construction work in progress (“CWIP”) in rate base (in discussing this measure, APS assumed the inclusion of its June 30, 2006 CWIP balance of $261 million in rate base, which would increase APS’ revenue requirement by about $33 million); and

	•		Approving an “attrition adjustment” to provide APS a reasonable opportunity to earn an authorized return on equity given overall cost increases and higher

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

levels of construction needed to accommodate ongoing customer growth (APS suggested a minimum attrition adjustment that would increase the allowed return on equity by 1.7% to 4.1%).

ACC Staff Recommendations. On August 18, 2006, the ACC staff and other rate case intervenors filed their initial written testimony with the ACC. Through subsequently filed testimony, the ACC staff recommends that the ACC increase APS’ annual retail electricity revenues by $195.8 million, which would result in a rate increase of approximately 9.2%. The principal components of the increase recommended by the ACC staff are $193.5 million, or a 9.1% increase, for increased fuel and purchased power costs; a $2.0 million rate reduction (0.1%) for non-fuel costs; and $4.3 million, or a 0.2% increase, for costs related to the ACC’s environmental portfolio standard.

In arriving at its recommendations, the ACC staff proposed, among other things, that the ACC:

	•		Increase the base fuel amount (from which PSA deferrals are calculated) from the current $0.020743 per kWh to $0.027975 per kWh;

	•		Approve a weighted-average cost of capital of 8.05% based on a return on common equity of 10.25% and APS’ requested capital structure of 45% long-term debt and 55% common equity;

	•		Retain the PSA with the modifications discussed herein;

	•		Approve additions to rate base, including the Sundance Power Plant; and

	•		Establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.

Other Intervenors’ Recommendations. Other intervenors in the rate case include the Arizona Residential Utility Consumer Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; Arizonans for Electric Choice and Competition (“AECC”), a business coalition that advocates on behalf of retail electric customers in Arizona; and Phelps Dodge Mining Company (“Phelps Dodge”). In its filed testimony, RUCO recommended that the ACC increase APS’ annual retail electricity revenues by $232 million, which would result in a rate increase of approximately 10.89%. In jointly-filed testimony, AECC and Phelps Dodge recommended that the ACC reduce APS’ requested annual increase by at least $131 million, which would result in a rate increase of not more than $303 million, or 14%.

Interim Rate Increase

On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006. APS later reduced this request to $232 million, or approximately 11%, due to a decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase was

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

solely to address APS’ under-collection of higher annual fuel and purchased power costs. On May 2, 2006, the ACC approved an order in this matter that, among other things:

	•		authorized an interim PSA adjustor, effective May 1, 2006, that resulted in an interim retail rate increase of approximately 8.3% designed to recover approximately $138 million of fuel and purchased power costs incurred in 2006 (this interim adjustor, combined with the $15 million PSA surcharge approved by the ACC (see “Surcharge for Certain 2005 PSA Deferrals” below), resulted in a rate increase of approximately 9.0% designed to recover approximately $149 million of fuel and purchased power costs during 2006);

	•		provided that amounts collected through the interim PSA adjustor “remain subject to a prudency review at the appropriate time” and that “all unplanned Palo Verde outage costs for 2006 should undergo a prudence audit by [the ACC] Staff” (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below);

	•		encouraged parties to APS’ general rate case to “propose modifications to the PSA that will address on a permanent basis, the issues with timing of recovery when deferrals are large and growing”;

	•		affirmed APS’ ability to defer fuel and purchased power costs above the prior annual cap of $776.2 million until the ACC decides the general rate case; and

	•		encouraged APS to diversify its resources “through large scale, sustained energy efficiency programs, [using] low cost renewable energy resources as a hedge against high fossil fuel costs.”

Power Supply Adjustor

PSA Provisions

The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for adjustment of retail rates to reflect variations in retail fuel and purchased power costs. Such adjustments are to be implemented by use of a PSA adjustor and PSA surcharges. On January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, 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 amount (currently $0.020743 per kWh);

	•		the deferrals are 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 amount and may retain 10% of the benefit from the retail fuel and purchased power costs that are below the base fuel amount;

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	•		amounts to be recovered or refunded through the PSA adjustor are limited to (a) a cumulative plus or minus $0.004 per kWh from the base fuel amount over the life of the PSA and (b) a maximum plus or minus $0.004 change in the adjustor rate in any one year;

	•		the recoverable amount of annual retail fuel and purchased power costs through current base rates and the PSA was originally capped at $776.2 million; however, the ACC has removed the cap pending the ACC’s final ruling on APS’ pending request in the general rate case to have the cap eliminated or substantially raised;

	•		the PSA will remain in effect for a minimum five-year period, but the ACC may eliminate the PSA at any time, if appropriate, in the event APS files a rate case before the expiration of the five-year period (which APS did by filing the general rate case noted above) or if APS does not comply with the terms of the PSA; and

	•		APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor rate has been set each year. The amount available for potential PSA surcharges will be limited to the amount of accumulated deferrals through the prior year-end, which are not expected to be recovered through the annual adjustor or any PSA surcharges previously approved by the ACC.

PSA Annual Adjustor The annual adjustor rate will be set for twelve-month periods beginning February 1 of each year. The current PSA annual adjustor rate was set at the maximum $0.004 per kWh effective February 1, 2006. The change in the adjustor rate represented a retail rate increase of approximately 5% designed to recover $110 million of deferred fuel and purchased power costs over the twelve-month period that began February 1, 2006.

Surcharge for Certain 2005 PSA Deferrals On April 12, 2006, the ACC approved APS’ request to recover $15 million of 2005 PSA deferrals over a twelve-month period beginning May 2, 2006, representing a temporary rate increase of approximately 0.7%. Approximately $45 million of 2005 PSA deferrals remain subject to a pending application (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below); the balance of the 2005 PSA deferrals is being recovered under the 2006 PSA annual adjustor described in the preceding paragraph.

PSA Deferrals Related to Unplanned Palo Verde Outages On February 2, 2006, APS filed with the ACC an application to recover approximately $45 million over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. On August 17, 2006, the ACC staff filed a report with the ACC recommending that the ACC disallow approximately $17.4 million ($10 million after income taxes) of the $45 million request. The report alleges that four of the eleven Palo Verde outages in 2005 were “avoidable,” three of which resulted in the recommended disallowance. The report also finds, among other things, that:

•

Three of the outages were due to “faulty or defective vendor supplied equipment” and concludes that APS’ actions were not imprudent in connection with these outages. The report recommends, however, that the ACC evaluate “the degree to which APS has sought appropriate legal or other remedies” in connection with these outages and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

that APS “be given the opportunity to demonstrate the steps that it has taken in this regard.”

•

“Additional investigation will be needed to determine the cause of and responsibility for” the Palo Verde Unit 1 outage resulting from vibration levels in one of the Unit’s shutdown cooling lines.

The report also recommends that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.

APS disagrees with, and will contest, the report’s recommendation that the ACC disallow a portion of the $45 million of PSA deferrals. Under ACC regulations, prudent investments are those “which under ordinary circumstances would be deemed reasonable and not dishonest or obviously wasteful” and “investments [are] presumed to have been prudently made, and such presumptions may be set aside only by clear and convincing evidence that such investments were imprudent.” APS believes the expenses in question were prudently incurred and, therefore, are recoverable. At the request of the ACC staff, this matter will be addressed by the ACC as part of APS’ general rate case.

As noted under “Interim Rate Increase” above, the ACC has directed the ACC staff to conduct a “prudence audit” on unplanned 2006 Palo Verde outage costs. PSA deferrals related to these 2006 outages are estimated to be about $78 million. APS believes these expenses were prudently incurred and, therefore, are recoverable.

Proposed Modifications to PSA (Requested In General Rate Case)

In its pending general rate case, APS has requested the following modifications to the PSA:

	•		The cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 kWh limit to changes in the adjustor rate in any one year would remain in effect;

	•		The $776.2 million annual limit on the retail fuel and purchased power costs under APS’ current base rates and the PSA would be removed or increased (although APS may defer fuel and purchased power costs above $776.2 million per year pending the ACC’s final ruling on APS’ pending request to have the cap eliminated or substantially raised);

	•		The current provision that APS is required to file a surcharge application with the ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100 million would be eliminated, thereby giving APS flexibility in determining when a surcharge filing should be made; and

	•		The costs of renewable energy and capacity costs attributable to purchased power obtained through competitive procurement would be excluded from the existing 90/10 sharing arrangement under which APS absorbs 10% of the retail fuel and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

purchased power costs above the base fuel amount and retains 10% of the benefit from retail fuel and purchased power costs that are below the base fuel amount.

In its prefiled testimony the ACC staff recommended the following potential changes to the PSA:

	•		Establishing the PSA annual adjustor, beginning in 2007, based on projected fuel costs rather than historical fuel costs; and

	•		Removing the existing limitations on fuel cost recovery.

Equity Infusions

On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006 (see Note 17). Pinnacle West has made these equity infusions into APS.

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.

FERC Order

On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to its 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’ market-based rate authority in the APS control area (the “FERC Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the APS control area to allow the FERC to make a determination about the 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As a result of the FERC Order, the Pinnacle West Companies must charge cost-based rates, rather than market-based rates, in the APS control area for sales occurring after the date of the order, April 17, 2006. The Pinnacle West Companies are required to refund any amounts collected that exceed the default cost-based rates for all market rate sales within the APS control area from February 27, 2005 to April 17, 2006.

The Pinnacle West Companies filed a rehearing request of the FERC Order on May 17, 2006 and submitted a supplemental compliance filing on July 31, 2006. Based upon an analysis of the FERC Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the FERC Order will have a material adverse effect on its financial position, results of operations or cash flows.

FERC Application

On September 21, 2006, Pinnacle West and Pinnacle West Marketing & Trading Co., LLC (“PW Trading”), a newly-formed Pinnacle West subsidiary, filed an application with the FERC seeking authorization for Pinnacle West to transfer its market rate tariff and FERC-jurisdictional service agreements to PW Trading, effective as of January 1, 2007. This application is pending at the FERC. Once implemented, Pinnacle West would no longer be considered a public utility under the Federal Power Act, which would permit Pinnacle West to issue securities and incur long-term debt without the need for authorization from the FERC under Section 204 of the Federal Power Act. Pinnacle West is currently authorized to issue a broad range of debt and equity securities pursuant to an order issued by the FERC on May 3, 2006.

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, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plan. The market-related value of our plan assets is their fair value at the measurement date.

The following table provides details of the plans’ benefit costs for the three months and nine months ended September 30, 2006 and 2005. 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):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Pension Benefits												Other Benefits
	Three Months						Nine Months						Three Months						Nine Months
	Ended						Ended						Ended						Ended
	September 30,						September 30,						September 30,						September 30,
	2006			2005			2006			2005			2006			2005			2006			2005
Service cost-benefits earned during the period	$	12		$	11		$	36		$	34		$	5		$	5		$	16		$	16
Interest cost on benefit obligation		23			22			69			66			10			9			27			26
Expected return on plan assets		(24	)		(22	)		(72	)		(67	)		(10	)		(8	)		(29	)		(23	)
Amortization of:
Transition (asset) obligation		(1	)		(1	)		(1	)		(3	)		1			1			2			2
Prior service cost		1			1			2			2			—			—			—			—
Net actuarial loss		6			5			18			15			2			2			7			7

Net periodic benefit cost	$	17		$	16		$	52		$	47		$	8		$	9		$	23		$	28

Portion of cost charged to expense	$	7		$	7		$	22		$	20		$	3		$	4		$	10		$	12

APS’ share of costs charged to expense	$	7		$	6		$	20		$	18		$	3		$	4		$	9		$	11

In September 2006, the FASB issued FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” See Note 19 for further details on this guidance.

Contributions

Our 2006 pension contribution of $46.5 million has been made for the year. The contribution to our other postretirement benefit plan in 2006 is estimated to be approximately $29 million. APS and other subsidiaries fund their shares of contributions. APS’ share is approximately 97% of both plans.

7. Business Segments

We have three principal business segments (determined by products, services and the regulatory environment):

	•		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;

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

	•		our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Financial data for the three months and nine months ended September 30, 2006 and 2005 and at September 30, 2006 and December 31, 2005 by business segment is provided as follows (dollars in millions):


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006		2005
Operating Revenues:
Regulated electricity	$	887		$	754	$	2,066	$	1,749
Real estate		98			79		319		233
Marketing and trading		84			107		259		267
Other		7			16		28		47

Total	$	1,076		$	956	$	2,672	$	2,296


Net Income (Loss):
Regulated electricity (a)	$	170		$	70	$	252	$	152
Real estate		17			21		49		42
Marketing and trading (b)		(4	)		8		7		(46	)
Other (c)		1			5		1		7

Total	$	184		$	104	$	309	$	155


(a)		2005 periods include an $87 million after-tax regulatory disallowance of plant costs in accordance with the APS retail rate case settlement relating to its 2003 general rate case.

(b)		The nine months ended September 30, 2005 includes a $64 million after-tax loss in discontinued operations related to the sale of Silverhawk.

(c)		The three months and nine months ended September 30, 2005 includes a $4 million after-tax gain related to the 2004 sale of NAC.


	As of		As of
	September 30, 2006		December 31, 2005
Assets:
Regulated electricity	$	10,281	$	9,732
Real estate		607		483
Marketing and trading		336		1,070
Other		33		38

Total	$	11,257	$	11,323

8. Stock-Based Compensation

Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and our subsidiaries.

The 2002 Long-Term Incentive Plan (“2002 Plan”) allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. We have reserved 6 million shares of common stock for

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

issuance under the 2002 Plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The terms of the options cannot be longer than 10 years and the options cannot be repriced.

Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year period based upon Pinnacle West’s earnings per share growth rate during that three-year period compared to the earnings per share growth rate of all relevant companies in a specified utilities index. The number of shares of common stock a recipient is entitled to receive is determined by Pinnacle West’s relative percentile ranking during the three-year period.

The 1994 Long-Term Incentive Plan (“1994 Plan”) includes outstanding options but no new options may be granted under the plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.

In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25, “Accounting for Stock Issued to Employees.”

Effective January 1, 2006, we prospectively adopted SFAS No. 123(R), “Share-Based Payment.” Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements.

The compensation cost that has been charged against income for stock-based compensation plans was $1.6 million and $3.8 million for the three months and nine months ended September 30, 2006, respectively, compared to $2.1 million and $4.3 million for the three months and nine months ended September 30, 2005, respectively. The total income tax benefit recognized in the condensed consolidated income statement for share-based compensation arrangements was $0.6 million and $1.5 million for the three months and nine months ended September 30, 2006, respectively, compared to $0.8 million and $1.7 million for the three months and nine months ended September 30, 2005, respectively.

The following table is a summary of option activity under our equity incentive plans as of September 30, 2006 and changes during the nine months ended on that date:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


					Weighted-
					Average		Aggregate
					Remaining		Intrinsic Value
	Shares		Weighted-Average		Contractual Term		(dollars in
Options	(in thousands)		Exercise Price		(Years)		thousands)
Outstanding at January 1, 2006		1,696	$	39.65
Exercised		326		35.12
Forfeited or expired		20		43.23

Outstanding at September 30, 2006		1,350		40.66		4.2	$	6,182

Exercisable at September 30, 2006		1,344		40.68		4.2		6,141

There were no options granted during the nine months ended September 30, 2006 and 2005. The intrinsic value of options exercised during the three months ended September 30, 2006 and 2005 was $2.6 million and $2.7 million, respectively. The intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005 was $2.8 million and $3.8 million, respectively.

The following table is a summary of the status of stock compensation awards, other than options, as of September 30, 2006 and changes during the nine months ended on that date:


	Shares			Weighted-Average Grant-Date
Nonvested shares	(in thousands)			Fair Value
Nonvested at January 1, 2006		528		$	38.23
Granted		274			41.50
Vested		(13	)		44.13
Forfeited		(228	)		36.17

Nonvested at September 30, 2006		561			40.53

As of September 30, 2006, there was $7.0 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 1.7 years. No shares vested during the three months ended September 30, 2006 and 2005. The total fair value of shares vested during the nine months ended September 30, 2006 and 2005 was $0.5 million and $2.9 million, respectively.

Cash received from options exercised under our share-based payment arrangements was $10.5 million and $11.4 million for the three months ended September 30, 2006 and 2005, respectively. Cash received from options exercised under our share-based payment arrangements was $11.5 million and $17.5 million for the nine months ended September 30, 2006 and 2005, respectively. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was $1.0 million and $1.0 million for the three months ended September 30, 2006 and 2005, respectively. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was $1.1 million and $1.5 million for the nine months ended September 30, 2006 and 2005, respectively.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Pinnacle West has a current policy of issuing new shares to satisfy share requirements for stock-based compensation plans and does not expect to repurchase any shares during 2006.

9. Variable-Interest Entities

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

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, 2006, APS would have been required to assume approximately $228 million of debt and pay the equity participants approximately $182 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, 2006, we hedged exposures to the price variability of the power and gas commodities for a maximum of 3.25 years. 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, 2006 and 2005 are comprised of the following (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006			2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(2,830	)	$	4,667	$	(5,984	)	$	12,444
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		4			17		(10	)		756
Gains from the discontinuance of cash flow hedges		—			—		434			385

During the next twelve months ending September 30, 2007, we estimate that a net gain of $40 million before income taxes will be reclassified from accumulated OCI 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).

Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments.

The following table summarizes our assets and liabilities from risk management and trading activities at September 30, 2006 and December 31, 2005 (dollars in thousands):

September 30, 2006


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	439,620	$	124,551	$	(446,652	)	$	(146,328	)	$	(28,809	)
Margin account and options		65,941		—		(557	)		(2,228	)		63,156
Marketing and trading:
Mark-to-market		111,513		90,928		(63,735	)		(45,640	)		93,066
Options and emission allowances		366		650		(12,853	)		—			(11,837	)

Total	$	617,440	$	216,129	$	(523,797	)	$	(194,196	)	$	115,576

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2005


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	516,399	$	228,873	$	(335,801	)	$	(74,787	)	$	334,684
Margin account and options		1,814		—		(124,165	)		—			(122,351	)
Marketing and trading:
Mark-to-market		307,883		291,122		(236,922	)		(181,417	)		180,666

Options and emission allowances		1,683		77,836		(23,805	)		(209	)		55,505

Total	$	827,779	$	597,831	$	(720,693	)	$	(256,413	)	$	448,504

We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $66 million at September 30, 2006 and a liability of $123 million at December 31, 2005 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 $28 million at September 30, 2006 and $6 million at December 31, 2005, and is included in other current assets in the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $62 million at September 30, 2006 and $216 million at December 31, 2005, and is included in other current liabilities in 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.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

11. Comprehensive Income

Components of comprehensive income for the three and nine months ended September 30, 2006 and 2005 are as follows (dollars in thousands):


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2006			2005			2006			2005
Net income	$	184,167		$	103,737		$	308,776		$	154,920

OCI (loss):
Net unrealized gains (losses) on derivative instruments (a)		(68,201	)		389,474			(342,307	)		524,898
Reclassification of realized (gains) losses to income (b)		2,519			(41,455	)		(15,688	)		(57,143	)
Income tax benefit (expense) related to items of OCI		25,649			(136,528	)		139,798			(183,500	)

Total OCI (loss)		(40,033	)		211,491			(218,197	)		284,255

Comprehensive income	$	144,134		$	315,228		$	90,579		$	439,175


(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.

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 has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.

APS currently estimates it will incur $147 million (in 2005 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

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2006, APS had a regulatory liability of $0.2 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

NRC Inspections

In September 2006, the NRC completed an inspection relating to Palo Verde’s spray ponds, which provide cooling for certain emergency and safety-related equipment during normal shutdown or accident conditions. APS had earlier advised the NRC that certain residues in the spray ponds suggested the need for adjustments to the ongoing maintenance and chemistry control protocols of the spray ponds, which APS is implementing. The NRC will hold a public regulatory conference on November 20 to discuss its findings. In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator did not activate during routine inspections on July 25 and September 22, 2006. The Company is currently unable to predict the impact of the results, if any, of these NRC inspections on Palo Verde’s operations.

California Energy Market Issues and Refunds in the Pacific Northwest

FERC

In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. 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 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. Petitions for rehearing on this order are due no later than February 28, 2007. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.

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 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 March 2, 2007. The request for stay was granted. The outcome of the further proceedings cannot be predicted at this time.

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

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals. 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 has sought appellate review and is seeking to reallocate the cost responsibility associated with the changed contractual obligations in a way that would be less favorable to APS than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS’ annual capacity cost could be increased 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 is no basis for modifying the settlement rates during the remaining term of the settlement. Despite the May 26 order, the party seeking appellate review is continuing to pursue an appeal of this issue.

Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on June 30, 2005, which proposed new rates, terms and conditions and services, which became effective on January 1, 2006. These rates are subject to refund pending the outcome of a hearing. The cost impact of this rate case will not have a material adverse effect on APS’ financial position, results of operations, cash flows or liquidity.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 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 believes Peabody’s claims are without merit and intends to contest those claims. Because the litigation is in preliminary stages, however, 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.

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 the 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. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2004 and again in 2005, the current income tax liability was increased, with a corresponding decrease to plant-related deferred tax liability, to reflect the expected outcome of this audit. We do not expect the ultimate outcome of

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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, cash flows or liquidity.

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 $18.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

14. Other Income and Other Expense

The following table provides detail of other income and other expense for the three months and nine months ended September 30, 2006 and 2005 (dollars in thousands):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Other income:
S02 emission allowance sales and other (a)	$	801		$	1,299		$	9,972		$	1,683
Interest income		5,878			6,815			13,068			12,006
SunCor other income		9,430			312			10,313			2,654
Investment gains — net		1,656			162			559			—
Miscellaneous		290			106			536			1,676

Total other income	$	18,055		$	8,694		$	34,448		$	18,019


Other expense:
Non-operating costs (a)	$	(2,954	)	$	(4,084	)	$	(10,501	)	$	(10,240	)
Miscellaneous		(739	)		(831	)		(2,452	)		(2,745	)

Total other expense	$	(3,693	)	$	(4,915	)	$	(12,953	)	$	(12,985	)


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

15. Guarantees

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of APS Energy Services. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by APS Energy Services 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 its subsidiary. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. At September 30, 2006, we had guarantees totaling $20 million and surety bonds totaling $24 million with a term of approximately one year for APS Energy Services.

At September 30, 2006, Pinnacle West had approximately $4 million of letters of credit related to workers’ compensation expiring in 2007. 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, 2006, 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 $91 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, 2006, 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.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

16. Earnings Per Share

The following table presents earnings per weighted-average common share outstanding for the three months and nine months ended September 30, 2006 and 2005:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Basic earnings per share:
Income from continuing operations	$	1.85	$	0.86	$	3.09	$	2.08
Income (loss) from discontinued operations		—		0.19		0.02		(0.46	)

Earnings per share — basic	$	1.85	$	1.05	$	3.11	$	1.62


Diluted earnings per share:
Income from continuing operations	$	1.84	$	0.86	$	3.07	$	2.08
Income (loss) from discontinued operations		—		0.19		0.03		(0.46	)

Earnings per share — diluted	$	1.84	$	1.05	$	3.10	$	1.62

Dilutive stock options and performance shares increased average common shares outstanding by approximately 482,000 shares and 119,000 shares for the three months ended September 30, 2006 and 2005, respectively, and by approximately 446,000 shares and 113,000 shares for the nine months ended September 30, 2006 and 2005, respectively.

Options to purchase 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 were outstanding but were not included in the computation of 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 not included in the computation of diluted earnings per share for that same reason were 167,604 shares for the three-month period ended September 30, 2005 and 503,304 shares for the nine-month period ended September 30, 2005.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

17. Discontinued Operations

Silverhawk (marketing and trading segment) — In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on January 10, 2006. As a result of this sale, we recorded a loss from discontinued operations of approximately $56 million ($91 million pretax) in the second quarter of 2005. The marketing and trading segment discontinued operations amounts in the chart below also include the revenues and expenses related to the operations of Silverhawk.

SunCor (real estate segment) — In 2005 and 2006, SunCor sold commercial properties that are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” At September 30, 2006, SunCor had real estate assets held for sale of approximately $23 million.

NAC (other segment) — In 2004, we sold our investment in NAC, and the third quarter of 2005 includes recognition of a previously contingent $4 million after-tax gain in connection with the sale.

The following table provides revenue and income (loss) before income taxes and after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three months and nine months ended September 30, 2006 and 2005 (dollars in millions):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006			2005
Revenue:
Silverhawk	$	—	$	45	$	1		$	88
SunCor — commercial operations		1		2		3			9
NAC		—		—		—			—

Total revenue	$	1	$	47	$	4		$	97


Income (loss) before income taxes:
Silverhawk (a)	$	—	$	1	$	1		$	(106	)
SunCor — commercial operations		—		24		4			27
NAC		—		6		(1	)		6

Total income (loss) before income taxes	$	—	$	31	$	4		$	(73	)


Income (loss) after income taxes:
Silverhawk	$	—	$	1	$	1		$	(64	)
SunCor — commercial operations		—		14		2			16
NAC		—		4		(1	)		4

Total income (loss) after income taxes	$	—	$	19	$	2		$	(44	)


(a)		For the three months and nine months ended September 30, 2005, income (loss) before income taxes includes an interest expense allocation, net of capitalized costs, of $3 million and $9 million, respectively. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.

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 debt and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, 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, 2006 and December 31, 2005 (dollars in millions):


			Total		Total
			Unrealized		Unrealized
	Fair Value		Gains		Losses
September 30, 2006
Equity securities	$	172	$	61	$	—
Debt securities		154		3		1

Total	$	326	$	64	$	1


December 31, 2005
Equity securities	$	150	$	50	$	—
Debt securities		144		3		1

Total	$	294	$	53	$	1

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,
	2006			2005			2006			2005
Realized gains		1			1			2			2
Realized losses		(1	)		(1	)		(3	)		(2	)
Proceeds from the sale of securities		56			53			171			136

The fair value of debt securities, summarized by contractual maturities, at September 30, 2006 is as follows (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Fair Value
	September 30,
	2006
Less than one year	$	8
1 year – 5 years		41
5 years – 10 years		40
Greater than 10 years		65

Total	$	154

19. New Accounting Standards

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” This guidance requires us to recognize the tax benefits of an uncertain tax position if it is more likely than not that the benefit will be sustained upon examination by the taxing authority. A tax position that meets the more-likely-than-not recognition threshold must be recognized in the financial statements at the largest amount of benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The Interpretation is effective for fiscal years beginning after December 15, 2006. We are currently evaluating this new guidance and believe it will not have a material impact on our financial statements.

In September 2006, the FASB issued FASB Statement 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 fiscal years beginning after November 15, 2007. We are currently evaluating this new guidance.

In September 2006, the FASB issued FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This guidance requires us to recognize the underfunded positions of our pension and other postretirement benefit plans in our balance sheet. The Statement is effective for fiscal years ending after December 15, 2006. We are currently evaluating this new guidance. Based on the December 31, 2005 funded status of our postretirement plans, the pension liability recorded in our balance sheet would increase by about $267 million and the other postretirement benefits liability would increase by about $190 million. The guidance requires that the offset be reported in other comprehensive income, net of tax; however, because the obligations relate primarily to APS’ regulated operations, we expect the increase in liabilities to be offset by regulatory assets. The proposed standard would not have a material impact on our results of operations or cash flows.

See Note 8 for a discussion of the accounting standard (SFAS No. 123(R)) on share-based payment.

ARIZONA PUBLIC SERVICE COMPANY

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


	Three Months Ended
	September 30,
	2006			2005
ELECTRIC OPERATING REVENUES (LOSSES)
Regulated electricity	$	888,724		$	755,778
Marketing and trading		(2,038	)		(7,430	)

Total		886,686			748,348


OPERATING EXPENSES
Regulated electricity fuel and purchased power		315,666			219,420
Marketing and trading fuel and purchased power		839			223
Operations and maintenance		156,170			149,198
Depreciation and amortization		88,999			81,701
Income taxes		93,061			88,984
Other taxes		31,371			34,407

Total		686,106			573,933

OPERATING INCOME		200,580			174,415


OTHER INCOME (DEDUCTIONS)
Regulatory disallowance		—			(143,217	)
Income taxes		684			60,265
Allowance for equity funds used during construction		3,178			2,852
Other income (Note S-3)		7,713			4,954
Other expense (Note S-3)		(2,770	)		(3,835	)

Total		8,805			(78,981	)


INTEREST DEDUCTIONS
Interest on long-term debt		39,175			33,583
Interest on short-term borrowings		2,438			1,753
Debt discount, premium and expense		1,066			914
Allowance for borrowed funds used during construction		(1,928	)		(1,909	)

Total		40,751			34,341


NET INCOME	$	168,634		$	61,093

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,
	2006			2005
ELECTRIC OPERATING REVENUES
Regulated electricity	$	2,070,673		$	1,755,969
Marketing and trading		11,732			22,428

Total		2,082,405			1,778,397


OPERATING EXPENSES
Regulated electricity fuel and purchased power		739,675			503,205
Marketing and trading fuel and purchased power		3,697			31,874
Operations and maintenance		493,896			429,806
Depreciation and amortization		263,279			240,723
Income taxes		136,682			147,136
Other taxes		99,585			97,174

Total		1,736,814			1,449,918

OPERATING INCOME		345,591			328,479


OTHER INCOME (DEDUCTIONS)
Regulatory disallowance		—			(143,217	)
Income taxes		1,873			57,879
Allowance for equity funds used during construction		10,612			8,407
Other income (Note S-3)		22,798			17,618
Other expense (Note S-3)		(10,298	)		(10,069	)

Total		24,985			(69,382	)


INTEREST DEDUCTIONS
Interest on long-term debt		108,315			104,712
Interest on short-term borrowings		7,449			4,999
Debt discount, premium and expense		3,264			3,106
Allowance for borrowed funds used during construction		(5,322	)		(5,856	)

Total		113,706			106,961


NET INCOME	$	256,870		$	152,136

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,
	2006			2005
ASSETS

UTILITY PLANT
Electric plant in service and held for future use	$	11,008,227		$	10,682,999
Less accumulated depreciation and amortization		3,771,163			3,616,886

Total		7,237,064			7,066,113
Construction work in progress		349,182			314,584
Intangible assets, net of accumulated amortization		93,346			90,327
Nuclear fuel, net of accumulated amortization		64,780			54,184

Utility plant — net		7,744,372			7,525,208


INVESTMENTS AND OTHER ASSETS
Decommissioning trust accounts (Note 18)		326,318			293,943
Assets from long-term risk management and trading activities (Note S-1)		124,551			234,372
Other assets		66,374			64,128

Total investments and other assets		517,243			592,443


CURRENT ASSETS
Cash and cash equivalents		117,693			49,933
Investment in debt securities		203,317			—
Customer and other receivables		508,667			421,621
Allowance for doubtful accounts		(4,124	)		(3,568	)
Materials and supplies (at average cost)		116,867			109,736
Fossil fuel (at average cost)		21,679			23,658
Assets from risk management and trading activities (Note S-1)		509,459			532,923
Deferred income taxes		8,089			—
Other current assets		24,086			14,639

Total current assets		1,505,733			1,148,942


DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		209,017			172,756
Other regulatory assets		188,368			151,123
Unamortized debt issue costs		26,641			25,279
Other deferred debits		82,891			91,690

Total deferred debits		506,917			440,848


TOTAL ASSETS	$	10,274,265		$	9,707,441

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,
	2006			2005
CAPITALIZATION AND LIABILITIES

CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		2,063,098			1,853,098
Retained earnings		990,045			860,675
Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		(86,132	)		(86,132	)
Derivative instruments		11,417			179,422

Common stock equity		3,156,590			2,985,225
Long-term debt less current maturities		2,877,331			2,479,703

Total capitalization		6,033,921			5,464,928


CURRENT LIABILITIES
Current maturities of long-term debt		84,740			85,620
Accounts payable		199,513			215,384
Accrued taxes		491,125			360,737
Accrued interest		40,297			25,003
Customer deposits		60,259			55,474
Deferred income taxes		—			64,210
Liabilities from risk management and trading activities (Note S-1)		456,585			480,138
Other current liabilities (Note S-1)		76,085			227,398

Total current liabilities		1,408,604			1,513,964


DEFERRED CREDITS AND OTHER
Deferred income taxes		1,213,061			1,215,403
Regulatory liabilities		588,957			592,494
Liability for asset retirements		282,060			269,011
Pension liability		235,951			233,342
Customer advances for construction		68,245			60,287
Unamortized gain — sale of utility plant		42,325			45,757
Liabilities from long-term risk management and trading activities (Note S-1)		148,658			83,774
Other		252,483			228,481

Total deferred credits and other		2,831,740			2,728,549


COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13, 15 and S-4)

TOTAL CAPITALIZATION AND LIABILITIES	$	10,274,265		$	9,707,441

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,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	256,870		$	152,136
Adjustments to reconcile net income to net cash provided by operating activities:
Regulatory disallowance		—			143,217
Depreciation and amortization including nuclear fuel		284,036			262,647
Deferred fuel and purchased power		(231,388	)		(142,806	)
Deferred fuel and purchased power amortization		195,127			—
Allowance for equity funds used during construction		(10,612	)		(8,407	)
Deferred income taxes		29,566			9,959
Change in mark-to-market valuations		6,060			4,300
Changes in current assets and liabilities:
Customer and other receivables		(85,190	)		(97,604	)
Materials, supplies and fossil fuel		(5,152	)		(10,759	)
Other current assets		4,311			3,299
Accounts payable		(13,468	)		10,697
Accrued taxes		133,359			101,819
Collateral		(185,091	)		153,040
Other current liabilities		41,306			(17,139	)
Change in risk management and trading activities — liabilities		(120,769	)		177,014
Change in other long-term assets		(70,411	)		1,509
Change in other long-term liabilities		57,278			29,469

Net cash flow provided by operating activities		285,832			772,391

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(466,095	)		(459,737	)
Allowance for borrowed funds used during construction		(5,322	)		(5,856	)
Purchase of Sundance Plant		—			(185,046	)
Purchases of investment securities		(592,495	)		(1,338,624	)
Proceeds from sale of investment securities		389,178			1,501,199
Proceeds from nuclear decommissioning trust sales		170,827			136,202
Investment in nuclear decommissioning trust		(186,383	)		(149,440	)
Repayment of loan by Pinnacle West Energy		—			500,000
Other		(3,453	)		120

Net cash flow used for investing activities		(693,743	)		(1,182	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		395,481			411,787
Repayment and reacquisition of long-term debt		(2,310	)		(568,236	)
Equity infusion		210,000			100,000
Dividends paid on common stock		(127,500	)		(42,500	)

Net cash flow provided by (used for) financing activities		475,671			(98,949	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		67,760			672,260
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		49,933			49,575

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	117,693		$	721,835

Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Income taxes, net of refunds	$	24,414		$	29,058
Interest, net of amounts capitalized	$	95,149		$	101,422

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	—
Stock-Based Compensation	Note 8	—
Variable Interest Entities	Note 9	—
Derivative and Energy Trading Accounting	Note 10	Note S-1
Comprehensive Income	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	—
Related Party Transactions	—	Note S-4

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-1. Derivative and Energy Trading Accounting

APS is exposed to the impact of market fluctuations in the commodity price of electricity, natural gas, coal 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, 2006, APS hedged exposures to these risks for a maximum of 3.25 years.

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 months and nine months ended September 30, 2006 and 2005 were comprised of the following (dollars in thousands):


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006			2005
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(2,505	)	$	4,722	$	(5,765	)	$	12,590
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		4			17		(10	)		756
Gains from the discontinuance of cash flow hedges		—			—		159			302

During the next twelve months ending September 30, 2007, APS estimates that a net gain of $12 million before income taxes will be reclassified from accumulated OCI 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, consistent with Pinnacle West’s business segments.

The following table summarizes APS’ assets and liabilities from risk management and trading activities at September 30, 2006 and December 31, 2005 (dollars in thousands):

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

September 30, 2006


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	439,620	$	124,551	$	(446,652	)	$	(146,328	)	$	(28,809	)
Margin account and options		65,941		—		(557	)		(2,228	)		63,156
Marketing and Trading:
Mark-to-market		3,898		—		(8,557	)		(102	)		(4,761	)
Options		—		—		(819	)		—			(819	)

Total	$	509,459	$	124,551	$	(456,585	)	$	(148,658	)	$	28,767

December 31, 2005


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	516,399	$	228,873	$	(335,801	)	$	(74,787	)	$	334,684
Margin account and options		1,814		—		(124,165	)		—			(122,351	)
Marketing and Trading:
Mark-to-market		13,027		5,499		(20,172	)		(8,778	)		(10,424	)
Options		1,683		—		—			(209	)		1,474

Total	$	532,923	$	234,372	$	(480,138	)	$	(83,774	)	$	203,383

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 $13 million at September 30, 2006 and is included in other current assets on the Condensed Balance Sheets. No collateral was provided at December 31, 2005. Collateral provided to us by counterparties was $2 million at September 30, 2006 and $175 million at December 31, 2005, and is included in other current liabilities on the Condensed Balance Sheets.

S-2. Comprehensive Income

Components of APS’ comprehensive income for the three months and nine months ended September 30, 2006 and 2005 are as follows (dollars in thousands):

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Net income	$	168,634		$	61,093		$	256,870		$	152,136

OCI (loss):
Unrealized gains (losses) on derivative instruments (a)		(51,359	)		315,532			(276,555	)		399,602
Reclassification of realized (gains) losses to income (b)		8,068			(32,868	)		910			(38,687	)
Income tax (expense) benefit related to items of OCI		16,906			(111,285	)		107,640			(142,092	)

Total OCI (loss)		(26,385	)		171,379			(168,005	)		218,823

Comprehensive income	$	142,249		$	232,472		$	88,865		$	370,959


(a)		These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.

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

S-3. Other Income and Other Expense

The following table provides detail of APS’ other income and other expense for the three months and nine months ended September 30, 2006 and 2005 (dollars in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Other income:
S02 emission allowance sales and other(a)	$	801		$	1,299		$	9,972		$	1,683
Interest income		5,439			3,408			10,943			13,008
Investment gains — net		1,193			34			1,358			513
Miscellaneous		280			213			525			2,414

Total other income	$	7,713		$	4,954		$	22,798		$	17,618


Other expense:
Non-operating costs (a)	$	(2,353	)	$	(3,358	)	$	(8,879	)	$	(8,693	)
Miscellaneous		(417	)		(477	)		(1,419	)		(1,376	)

Total other expense	$	(2,770	)	$	(3,835	)	$	(10,298	)	$	(10,069	)


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

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-4. Related Party Transactions

From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Condensed Statements of Income and Condensed Balance Sheets related to transactions with affiliated companies (dollars in millions):


	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
	2006		2005		2006		2005
Electric operating revenues:
Pinnacle West — marketing and trading	$	2	$	2	$	5	$	5
Pinnacle West Energy		—		—		—		2

Total	$	2	$	2	$	5	$	7


Fuel and purchased power costs:
Pinnacle West Energy	$	—	$	14	$	—	$	61

Other:
Pinnacle West Energy interest income	$	—	$	—	$	—	$	5


	As of			As of
	September 30, 2006			December 31, 2005
Net intercompany receivables (payables):
Pinnacle West — marketing and trading	$	16		$	82
APS Energy Services		—			2
Pinnacle West		(5	)		(2	)

Total	$	11		$	82

Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. APS purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”

Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

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. The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, these proceedings consist of:

	•		a general retail rate case pursuant to which APS is requesting a 20.4%, or $434.5 million, increase in its annual retail electricity revenues;

	•		an application for a temporary rate increase of approximately 1.9%, through a PSA surcharge, to recover $45 million in retail fuel and purchased power costs relating to Palo Verde’s 2005 unplanned outages that were deferred by APS in 2005 under the PSA and are subject to the ACC’s completion of an inquiry regarding the outages (this matter will now be addressed in the general retail rate case); and

	•		the ACC’s prudency review of amounts collected through the May 2, 2006 interim PSA adjustor (see “Interim Rate Increase” in Note 5) related to unplanned 2006 Palo Verde outages. The related PSA deferrals were approximately $78 million for the nine months ended September 30, 2006.

SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow. Our subsidiary, APS Energy Services, 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 Energy was a subsidiary that owned and operated unregulated generating plants. Pursuant to the ACC’s April 7, 2005 order in APS’ retail rate settlement, on July 29, 2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006. See Note 17 for a discussion of discontinued operations. As a result, Pinnacle West Energy no longer owned any generating plants and was dissolved as of August 31, 2006.

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 has three principal business segments (determined by products, services and the regulatory environment):

	•		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;

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

	•		our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.

The following table summarizes net income by segment for the three months and nine months ended September 30, 2006 and 2005 (dollars in millions):


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006			2005
Regulated electricity (a)	$	170		$	70	$	252		$	152
Real estate		17			7		47			26
Marketing and trading		(4	)		7		6			18
Other		1			1		2			3

Income from continuing operations		184			85		307			199
Discontinued operations — net of tax:
Real estate (b)		—			14		2			16
Marketing and trading (c)		—			1		1			(64	)
Other		—			4		(1	)		4

Net income	$	184		$	104	$	309		$	155


(a)		2005 periods include an $87 million after-tax regulatory disallowance of plant costs in accordance with the APS retail rate case settlement.

(b)		Primarily relates to sales of commercial properties.

(c)		Relates to losses on the sale of Silverhawk announced in June 2005 and related operations until the sale closed in January 2006.

PINNACLE WEST CONSOLIDATED — RESULTS OF OPERATIONS

General

Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.1 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses.

Deferred Fuel and Purchased Power Costs

APS’ retail rate case settlement relating to its 2003 general rate case became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications. See “Power Supply Adjustor” in Note 5.

Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates primarily due to the use of higher cost resources to serve incremental customer growth and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA deferrals at September 30, 2006 was $209 million. APS estimates that its PSA deferral balance at December 31, 2006 will be approximately $140 million to $160 million, based on the amounts already approved for collection and on APS’ hedged positions for fuel and purchased power at September 30, 2006 and recent forward market prices for natural gas and purchased power (which are subject to change). The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses.

APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18, 2006 due to vibration levels in one of the Unit’s shutdown cooling lines. During an outage at Unit 1 from March 18, 2006 to July 7, 2006, APS performed the necessary work and modifications to remedy the situation. APS estimates that incremental replacement power costs resulting from these Palo Verde outages and reduced power levels were approximately $86 million during the nine months ended September 30, 2006. The impact on the PSA deferrals was an increase of approximately $78 million in that period. These Palo Verde replacement power costs were partially offset by $43 million of lower than expected replacement power costs related to APS’ other generating units during the nine months ended September 30, 2006, which decreased PSA deferrals by $39 million.

The PSA deferral balance at September 30, 2006 and estimated balance as of December 31, 2006 each includes (a) $45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages and (b) $78 million related to replacement power costs associated with unplanned 2006 outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages and reduced power operations are the subject of ACC prudence reviews. The ACC staff has recommended disallowance of $17 million of the 2005 costs. The recommendation will be considered as part of APS’ general rate case currently before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 5. The ACC staff recommendation does not change management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable.

Operating Results — Three-month period ended September 30, 2006 compared with three-month period ended September 30, 2005

Our consolidated net income for the three months ended September 30, 2006 was $184 million compared with $104 million for the comparable prior-year period. The three months ended September 30, 2005 included income from discontinued operations of $19 million, a substantial portion of which was related to the sale of real estate commercial properties. Income from continuing operations increased $99 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

	•		Regulated Electricity Segment — Income from continuing operations increased approximately $100 million primarily due to an $87 million after-tax regulatory disallowance of plant costs recorded in 2005. Income was also higher due to higher retail sales volumes related to customer growth. These positive factors were partially offset by the effects of milder weather on retail sales. Higher fuel and purchased power costs (as discussed above) were substantially offset by the deferral of those costs in accordance with the PSA.

	•		Real Estate Segment — Income from continuing operations increased approximately $10 million primarily due to the sale of certain joint venture assets and increased margins on residential and parcel sales. Income from discontinued real estate operations decreased $14 million due to lower commercial property sales.

	•		Marketing and Trading Segment — Income from continuing operations decreased approximately $11 million primarily due to declines in forward prices.

Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):


	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Higher fuel and purchased power costs	$	(32	)	$	(19	)
Increased deferred fuel and purchased power costs		30			18
Higher retail sales volumes due to customer growth, excluding weather effects		28			17
Effects of milder weather on retail sales		(6	)		(4	)
Miscellaneous items, net		3			2

Net increase in regulated electricity segment gross margin		23			14
Lower marketing and trading segment gross margin primarily due to declines in forward prices		(16	)		(10	)
Higher real estate segment contribution primarily related to the sale of certain joint venture assets and increased margins on residential and parcel sales		17			10
Regulatory disallowance of plant costs in 2005, in accordance with the APS retail rate case settlement		143			87
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls		(3	)		(2	)
Miscellaneous items, net		(2	)		(1	)
Higher depreciation and amortization primarily due to increased plant asset balances		(5	)		(3	)
Miscellaneous items, net		1			4

Net increase in income from continuing operations	$	158			99

Discontinued operations primarily related to sales of real estate assets					(19	)

Net increase in net income				$	80

Regulated Electricity Segment Revenues

Regulated electricity segment revenues were $134 million higher for the three months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $102 million increase in 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 “Deferred Fuel and Purchased Power Costs” above);

	•		a $43 million increase in retail revenues related to customer growth, excluding weather effects;

	•		an $8 million decrease in retail revenues related to milder weather;

	•		an $8 million decrease in Off-System Sales due to lower prices; and

	•		a $5 million increase due to miscellaneous factors.

Real Estate Segment Revenues

Real estate segment revenues were $19 million higher for the three months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $13 million increase from residential sales due to higher prices; and

	•		a $6 million increase from parcel sales.

Marketing and Trading Segment Revenues

Marketing and trading segment revenues were $22 million lower for the three months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $17 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices;

	•		a $7 million decrease from lower prices on competitive retail sales in California; and

	•		a $2 million increase due to higher power prices on delivered wholesale electricity sales.

Operating Results — Nine-month period ended September 30, 2006 compared with nine-month period ended September 30, 2005

Our consolidated net income for the nine months ended September 30, 2006 was $309 million compared with $155 million for the comparable prior-year period. The nine months ended September 30, 2005 included a net loss from discontinued operations of $44 million, which was related to the sale and operations of Silverhawk, partially offset by income from the sales of real estate commercial properties. Income from continuing operations increased $108 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

	•		Regulated Electricity Segment — Income from continuing operations increased approximately $100 million primarily due to an $87 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; income tax credits related to prior years resolved in 2006; effects of weather on retail sales; a retail price increase effective April 1, 2005; lower interest expense; and higher interest income. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; and higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates. In addition, higher fuel and purchased power costs of $80 million after-tax were partially offset by the deferral of $51 million after-tax of costs in accordance with the PSA. See discussion above – “Deferred Fuel and Purchased Power Costs.”

	•		Real Estate Segment — Income from continuing operations increased approximately $21 million primarily due to increased margins on residential and parcel sales and the sale of certain joint venture assets. Income from discontinued operations decreased $14 million due to lower commercial property sales.

•

Marketing and Trading Segment — Income from continuing operations decreased approximately $12 million primarily due to lower mark-to-market gains on contracts for future delivery, partially offset by higher unit margins on wholesale sales.

Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):


	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Higher fuel and purchased power costs	$	(131	)	$	(80	)
Increased deferred fuel and purchased power costs (deferrals began April 1, 2005)		83			51
Higher retail sales volumes due to customer growth, excluding weather effects		71			43
Effects of weather on retail sales		7			4
Retail price increase effective April 1, 2005		7			4
Miscellaneous items, net		(13	)		(7	)

Net increase in regulated electricity segment gross margin		24			15
Lower marketing and trading segment gross margin primarily related to lower mark-to-market gains, partially offset by higher unit margins on wholesale sales		(21	)		(13	)
Higher real estate segment contribution primarily related to increased margins on residential and parcel sales and the sale of certain joint venture assets		35			21
Regulatory disallowance of plant costs in 2005, in accordance with the APS retail rate case settlement		143			87
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls		(32	)		(20	)
Customer service costs, including regulatory demand-side management programs and planned maintenance		(10	)		(6	)
Miscellaneous items, net		(2	)		(1	)
Higher depreciation and amortization primarily due to increased plant asset balances partially offset by lower depreciation rates		(5	)		(3	)
Lower interest expense, net of capitalized financing costs, primarily due to lower debt balances, partially offset by higher rates		6			4
Higher other income, net of expense, primarily due to miscellaneous asset sales and increased interest income		9			5
Income tax credits related to prior years resolved in 2006		—			10
Miscellaneous items, net		1			9

Net increase in income from continuing operations	$	148			108

Discontinued operations:
Silverhawk loss in 2005					65
Lower commercial property real estate sales					(14	)
Other					(5	)

Net increase in net income				$	154

Regulated Electricity Segment Revenues

Regulated electricity segment revenues were $317 million higher for the nine months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $195 million increase in 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 “Deferred Fuel and Purchased Power Costs” above);

	•		a $102 million increase in retail revenues related to customer growth, excluding weather effects;

	•		a $12 million increase in Off-System Sales primarily resulting from sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;

	•		a $10 million increase in retail revenues related to weather;

	•		a $7 million increase in retail revenues due to a price increase effective April 1, 2005; and

	•		a $9 million decrease due to miscellaneous factors.

Real Estate Segment Revenues

Real estate segment revenues were $85 million higher for the nine months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $62 million increase from residential sales due to higher prices and volumes;

	•		a $15 million increase from parcel sales; and

	•		an $8 million increase due to miscellaneous sales.

Marketing and Trading Segment Revenues

Marketing and trading segment revenues were $8 million lower for the nine months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $26 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices;

	•		a $12 million decrease in Off-System Sales due to the absence of sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;

	•		a $25 million increase from higher prices on competitive retail sales in California; and

	•		a $5 million increase due to miscellaneous factors.

LIQUIDITY AND CAPITAL RESOURCES

Capital Needs and Resources — Pinnacle West Consolidated

Capital Expenditure Requirements

The following table summarizes the actual capital expenditures for the nine months ended September 30, 2006 and estimated capital expenditures for the next three years:

CAPITAL EXPENDITURES
(dollars in millions)


	Nine Months Ended		Estimated for the Year Ending
	September 30,		December 31,
	2006		2006		2007		2008
APS
Distribution	$	275	$	340	$	382	$	412
Transmission		72		115		177		227
Generation		110		185		322		263
Other (a)		14		22		22		28

Subtotal		471		662		903		930
SunCor (b)		151		191		130		105
Other		6		8		17		19

Total	$	628	$	861	$	1,050	$	1,054


(a)		Primarily information systems and facilities projects.

(b)		Consists primarily of capital expenditures for land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” 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. Generation also includes nuclear fuel expenditures of approximately $40 million annually for 2006 through 2008.

The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit 3 and are scheduled for completion in the Fall of 2007 at an approximate cost of $70 million (APS’ share). Approximately $26 million of the Unit 3 steam generator costs have been incurred through September 30, 2006, with the remaining $44

million included in the capital expenditures table above. Capital expenditures will be funded with internally generated cash and/or external financings.

Contractual Obligations

Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2005 Form 10-K, with the following exception:

•

aggregate fuel and purchased power commitments, which increased from approximately $1.9 billion at December 31, 2005 to $2.9 billion at September 30, 2006 as follows (in billions):


2006	2007-2008	2009-2010	Thereafter	Total

$0.4	$0.6	$0.4	$1.5	$2.9

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

Off-Balance Sheet Arrangements

Guarantees and Letters of Credit

We have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to these obligations. 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.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of November 7, 2006 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
Pinnacle West
Senior unsecured (a)	Baa3 (P)	BB+ (prelim)
Commercial paper	P-3	A-3
Outlook	Negative	Stable

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


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

Debt Provisions

Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt to capitalization ratio. 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 each of Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At September 30, 2006, the ratio was approximately 49% for Pinnacle West and 47% 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 times under APS’ bank financing agreements as of September 30, 2006. 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.

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 further rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

All of Pinnacle West’s bank 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.

Capital Needs and Resources — By Company

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, 2006, APS’ common equity ratio, as defined, was approximately 52%.

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and our subsidiaries. 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 the plan assets and our pension obligation. The assets in the plan are comprised of common stocks, bonds, common and collective trusts and short-term investments. Future year contribution amounts are dependent on fund performance and valuation assumptions of plan assets. We contributed $53 million in 2005. Our 2006 pension contribution of $46.5 million has been made for the year. The contribution to our other postretirement benefit plan in 2006 is estimated to be approximately $29 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.

In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk. See “Equity Infusions” in Note 5 for more information.

On October 18, 2006, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on December 1, 2006, to shareholders of record on November 1, 2006.

In connection with the FERC Order discussed under “Federal” in Note 5, the FERC revoked a previous FERC order allowing Pinnacle West to issue securities or incur long-term debt without FERC approval. On May 3, 2006, the FERC issued an order approving Pinnacle West’s application to issue a broad range of debt and equity securities through June 30, 2008. Pinnacle West does not expect this FERC order to limit its ability to meet its capital requirements. See “FERC Application” in Note 5 for a discussion of the application which, once implemented, would permit Pinnacle West to issue securities and incur long-term debt without the need for authorization from the FERC.

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.

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.

On August 3, 2006, APS issued $400 million of debt as follows: $250 million of its 6.25% Notes due 2016 and $150 million of its 6.875% Notes due 2036. A portion of the proceeds will be used to pay at maturity approximately $84 million of APS’ 6.75% Senior Notes due November 15, 2006, to fund its construction program and for other general corporate purposes. A portion of the proceeds may also be used to pay any liability determined to be payable as a result of the review by the IRS of a tax refund the Company received in 2002.

See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” 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 the ACC’s approval of annual PSA adjustments and periodic surcharge applications. During the nine months ended September 30, 2006, APS recovered approximately $195 million of PSA deferrals, which had no effect on earnings because of amortization of the same amount recorded as fuel and purchased power expense.

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

Pinnacle West Energy

See Note 17 of Notes to Condensed Consolidated Financial Statements above for a discussion of the sale of our 75% ownership interest in Silverhawk.

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, 2006 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.

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

APS Energy Services expects minimal capital expenditures over the next three years.

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 2005 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2005 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

See Note 8 for a discussion of the accounting standard (SFAS No. 123(R)) on share-based payment.

PINNACLE WEST CONSOLIDATED — FACTORS AFFECTING
OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity rates and tariffs and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition.

Retail Rate Proceedings The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, these proceedings consist of a general rate case request; an application for a 1.9% temporary rate increase that is subject to the ACC’s completion of an inquiry regarding unplanned 2005 Palo Verde outages (this matter will now be addressed in the general rate case); and a “prudency review” of amounts collected through the May 2, 2006 interim PSA adjustor, including a “prudence audit” of unplanned 2006 Palo Verde outages to be conducted by the ACC staff.

Fuel and Purchased Power Costs Fuel and purchased power costs 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, variances in deferrals and amortization of fuel and purchased power since April 1, 2005 and our hedging program for managing such costs. See “Power Supply Adjustor” in Note 5 for information regarding the PSA, including PSA deferrals related to unplanned Palo Verde outages and reduced power operations that are the subject of ACC prudence reviews. See “Natural Gas Supply” in Note 12 for more information on fuel costs. APS’ recovery of PSA deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.

Customer and Sales Growth The customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory averaged about 3.8% a year for the three years 2003 through 2005; we currently expect customer growth to average about 4.2% per year from 2006 to 2008. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.6% on average, from 2006 through 2008, before the effects of weather variations. Customer growth was 4.5% higher for the nine-month period ended September 30, 2006 when compared with the prior-year period.

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.

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

Wholesale Power Market Conditions The marketing and trading division focuses primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. The marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits.

Other Factors Affecting Financial Results

Operations and Maintenance Expenses Operations 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 Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction, acquisition, the sale of generation (see discussion of the sale of Silverhawk — Note 17), changes in depreciation and amortization rates, and changes in regulatory asset amortization.

Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed value for 2005 and 2004. We expect property taxes to increase as new power plants, the acquisition of the Sundance Plant in 2005 and our additions to transmission and distribution facilities are included in the property tax base.

Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our 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 Competition Although some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

Subsidiaries SunCor’s net income was $56 million in 2003, $45 million in 2004 and $56 million in 2005.

APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.

General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” 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 debt securities held by our nuclear decommissioning trust fund. The nuclear decommissioning trust fund also has risk 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, coal and emissions allowances. 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. 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. 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 values of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:

	•		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 segment.

The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions for the nine months ended September 30, 2006 and 2005 (dollars in millions):


	Nine Months Ended						Nine Months Ended
	September 30, 2006						September 30, 2005
	Regulated			Marketing			Regulated			Marketing
	Electricity			and Trading			Electricity			and Trading
Mark-to-market of net positions at beginning of period	$	335		$	181		$	33		$	107
Recognized in earnings:
Change in mark-to-market for future period deliveries – gains (losses)		(9	)		(3	)		15			24
Mark-to-market gains realized including ineffectiveness during the period		(3	)		(2	)		(6	)		(3	)
Deferred as a regulatory (asset) liability		(76	)		—			29			—
Recognized in OCI:
Change in mark-to-market for future period deliveries – gains (losses) (a)		(277	)		(66	)		400			125
Mark-to-market gains losses realized during the period		1			(17	)		(38	)		(19	)


Mark-to-market of net positions at end of period	$	(29	)	$	93		$	433		$	234


(a)		The gains (losses) 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, 2006 by maturities and by the source for calculating the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2005 Form 10-K for more discussion of our valuation methods.

Regulated Electricity


																Total
													Years			fair
Source of Fair Value	2006			2007			2008			2009			thereafter			value
Prices actively quoted	$	(10	)	$	(3	)	$	(8	)	$	(13	)	$	—		$	(34	)
Prices provided by other external sources		1			10			(2	)		(1	)		—			8
Prices based on models and other valuation methods		—			(1	)		—			4			(6	)		(3	)

Total by maturity	$	(9	)	$	6		$	(10	)	$	(10	)	$	(6	)	$	(29	)

Marketing and Trading


																Total
														Years		fair
Source of Fair Value	2006		2007			2008		2009			2010			thereafter		value
Prices actively quoted	$	6	$	—		$	—	$	—		$	—		$	—	$	6
Prices provided by other external sources		—		53			16		—			—			—		69
Prices based on models and other valuation methods		4		(3	)		17		(1	)		(1	)		2		18

Total by maturity	$	10	$	50		$	33	$	(1	)	$	(1	)	$	2	$	93

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, 2006 and December 31, 2005 (dollars in millions).


	September 30, 2006					December 31, 2005
	Gain (Loss)					Gain (Loss)
	Price Up		Price Down			Price Up		Price Down
Commodity	10%		10%			10%		10%
Mark-to-market changes reported in OCI (a):
Electricity	$	42	$	(42	)	$	66	$	(66	)
Natural gas		85		(85	)		103		(103	)


Total	$	127	$	(127	)	$	169	$	(169	)


(a)		These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

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 2005 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

General

financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses.

Deferred Fuel and Purchased Power Costs

Operating Results – Three-month period ended September 30, 2006 compared with three-month period ended September 30, 2005

APS’ net income for the three months ended September 30, 2006 was $169 million compared with $61 million for the comparable prior-year period. The $108 million increase was primarily due to an $87 million after-tax regulatory disallowance of plant costs recorded in 2005; higher retail sales volumes related to customer growth; and higher marketing and trading gross margin primarily due to higher mark-to-market gains. In addition, the increase also related to the absence of a prior-year cost-based contract for PWEC Dedicated Assets, which was partially offset by increased operations and maintenance expense and depreciation related to those units due to their transfer to APS. These positive factors were partially offset by the effects of milder weather on retail sales; higher operations and maintenance expense related to generation; and higher depreciation and amortization primarily related to increased plant balances. Higher fuel and purchased power costs (as discussed above — “Deferred Fuel and Purchased Power Costs”) were substantially offset by the deferral of those costs in accordance with the PSA.

Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):


	Increase (Decrease)
	Pretax			After Tax
Gross margin:
Higher fuel and purchased power costs	$	(32	)	$	(19	)
Increased deferred fuel and purchased power costs		30			18
Absence of prior year cost-based contract for PWEC Dedicated Assets		14			9
Higher retail sales volumes due to customer growth, excluding weather effects		28			17
Effects of milder weather on retail sales		(6	)		(4	)
Higher marketing and trading gross margin primarily due to higher mark-to-market gains		5			3
Miscellaneous items, net		2			1

Net increase in gross margin		41			25
Regulatory disallowance of plant costs in 2005, in accordance with the APS retail rate case settlement		143			87
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls		(4	)		(2	)
Costs of PWEC Dedicated Assets not included in prior year period		(2	)		(1	)
Miscellaneous items, net		(1	)		(1	)
Depreciation and amortization increases primarily due to:
Higher other depreciable assets partially offset by lower depreciation rates		(5	)		(3	)
Higher depreciable assets due to transfer of PWEC Dedicated Assets		(2	)		(1	)
Miscellaneous items, net		1			4

Net increase in net income	$	171		$	108

Regulated Electricity Revenues

Regulated electricity revenues were $133 million higher for the three months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $102 million increase in 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 “Deferred Fuel and Purchased Power Costs” above);

	•		a $43 million increase in retail revenues related to customer growth, excluding weather effects;

	•		an $8 million decrease in retail revenues related to weather;

	•		an $8 million decrease in Off-System Sales due to lower prices; and

	•		a $4 million increase due to miscellaneous factors.

Operating Results – Nine-month period ended September 30, 2006 compared with nine-month period ended September 30, 2005

APS’ net income for the nine months ended September 30, 2006 was $257 million compared with $152 million for the comparable prior-year period. The $105 million increase was primarily due to an $87 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; higher marketing and trading gross margin primarily related to higher mark-to-market gains; income tax credits related to prior years resolved in 2006; effects of weather on retail sales; a retail price increase effective April 1, 2005; and higher interest income. In addition, the increase also related to the absence of a prior year cost-based contract for PWEC Dedicated Assets, which was partially offset by increased operations and maintenance expenses and depreciation related to those units after their transfer to APS. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; higher depreciation and amortization primarily due to increased plant asset balances, partially offset by higher depreciation rates; and higher interest expense. Higher fuel and purchased power costs of $80 million after-tax were partially offset by the deferral of $51 million after-tax costs in accordance with the PSA. See discussion above – “Deferred Fuel and Purchased Power Costs.”

Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):


	Increase (Decrease)
	Pretax			After Tax
Gross margin:
Higher fuel and purchased power costs	$	(131	)	$	(80	)
Increased deferred fuel and purchased power costs (deferrals began April 1, 2005)		83			51
Higher retail sales volumes due to customer growth, excluding weather effects		71			43
Absence of prior year cost-based contract for PWEC Dedicated Assets		56			34
Higher marketing and trading gross margin primarily related to higher mark-to-market gains		18			11
Effects of weather on retail sales		7			4
Retail price increase effective April 1, 2005		7			4
Miscellaneous items, net		(15	)		(9	)

Net increase in gross margin		96			58
Regulatory disallowance of plant costs in 2005, in accordance with the APS retail rate case settlement		143			87
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls		(32	)		(20	)
Costs of PWEC Dedicated Assets not included in prior year period		(18	)		(11	)
Customer service costs, including regulatory demand-side management programs and planned maintenance		(12	)		(7	)
Miscellaneous items, net		(2	)		(1	)
Depreciation and amortization increases primarily due to:
Higher depreciable assets due to transfer of PWEC Dedicated Assets		(14	)		(9	)
Higher other depreciable assets partially offset by lower depreciation rates		(9	)		(5	)
Higher interest expense, net of capitalized financing costs, primarily due to higher rates and higher debt balances		(7	)		(4	)
Higher other income, net of expense, due to miscellaneous asset sales and increased interest income		5			3
Income tax credits related to prior years resolved in 2006		—			7
Miscellaneous items, net		—			7

Net increase in net income	$	150		$	105

Regulated Electricity Revenues

Regulated electricity revenues were $315 million higher for the nine months ended September 30, 2006 compared with the prior-year period primarily as a result of:

•

a $195 million increase in 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 “Deferred Fuel and Purchased Power Costs” above);

	•		a $102 million increase in retail revenues related to customer growth, excluding weather effects;

	•		a $12 million increase in Off-System Sales primarily resulting from sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in the regulated electricity in accordance with the APS retail rate case settlement;

	•		a $10 million increase in retail revenues related to weather;

	•		a $7 million increase in retail revenues due to a price increase effective April 1, 2005; and

	•		an $11 million decrease due to miscellaneous factors.

Marketing and Trading Revenues

Marketing and trading revenues were $11 million lower for the nine months ended September 30, 2006 compared with the prior-year period primarily as a result of:

	•		a $12 million decrease in energy trading revenues on realized sales of electricity primarily due to lower delivered electricity prices and lower volumes;

	•		a $12 million decrease in Off-System Sales due to the absence of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with the APS retail rate case settlement; and

	•		a $13 million increase in mark-to-market gains on contracts for future delivery due to changes in forward prices.

ARIZONA PUBLIC SERVICE COMPANY – LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations

APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2005 Form 10-K, with the following exception:

•

aggregate fuel and purchased power commitments, which increased from approximately $1.7 billion at December 31, 2005 to $2.8 billion at September 30, 2006 as follows (in billions):


2006	2007-2008		2009-2010		Thereafter		Total
$0.4	$	0.5	$	0.4	$	1.5	$	2.8

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

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2005 Form 10-K, these factors include, but are not limited to:

	•		state and federal regulatory and legislative decisions and actions, including the outcome and timing of APS’ retail rate proceedings pending before the ACC;

	•		the timely recovery of PSA deferrals, including approximately $123 million of deferrals at September 30, 2006 associated with unplanned Palo Verde outages and reduced power operations that are the subject of ACC prudence reviews;

	•		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;

	•		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 the assets in the trusts holding our nuclear decommissioning, pension, and other postretirement benefit plans 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 — Market Risks” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

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

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of September 30, 2006. 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, 2006. 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, 2006 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 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report with regard to pending or threatened litigation or other disputes.

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in the 2005 Form 10-K, which could materially affect the business, financial condition or future results of APS and Pinnacle West. The risks described in this report and the 2005 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 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 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of regulatory developments.

Environmental Matters

See “Environmental Matters – Superfund” in Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of a Superfund site.

Mercury. By November 2006, the ADEQ will submit a State Implementation Plan to the EPA to implement the Clean Air Mercury Rule. See “Environmental Matters – Mercury” in Part I, Item 1 of the 2005 Form 10-K. ADEQ issued a proposed mercury rule on July 25, 2006. The proposed rule generally incorporates the EPA’s model cap-and-trade program, but requires sources to acquire two allowances for every one allowance needed for compliance. The proposed rule also requires coal-fired power plants to achieve a 90% mercury removal efficiency or to achieve certain emission limits. APS is still evaluating the potential impacts of the proposed rule and cannot currently estimate the expenditures that may be required.

Federal Implementation Plan. In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and the Four Corners Power Plant. See “Environmental Matters – Federal Implementation Plan” in Part I, Item 1 of the 2005 Form 10-K. On July 26, 2006, the Sierra Club sued the EPA in an attempt to force the EPA to issue a final FIP to limit emissions at the Four Corners Power Plant. On September 12, 2006, the EPA again proposed FIPs to establish air quality standards at Four Corners and the Navajo Generating Station. On September 18, 2006, APS filed a motion to intervene in the

Sierra Club’s lawsuit against the EPA, in order to assure that its interests are protected. APS cannot currently predict the effect of the proposed FIP on its financial position, results of operations, cash flows or liquidity, or whether the proposed FIP will be adopted in its current form.

In addition, on August 21, 2006, the EPA proposed a FIP to implement “minor New Source Review” on Indian reservations. The FIP, if finalized, would apply to Four Corners and the Navajo Generating Station, and would require preconstruction review and permitting of plant projects that meet specified criteria. APS does not currently expect this FIP to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.

Item 6. EXHIBITS

(a) Exhibits


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

10.1	APS	$500,000,000 Five-Year Credit Agreement dated as of September 28, 2006 among Arizona Public Service Company as Borrower, Bank Of America, N.A. as Administrative Agent and Issuing Bank, The Bank Of New York as Syndication Agent and Issuing Bank and the other parties thereto

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

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


*Exhibit No.*	*Registrant(s)*	*Description*
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1	Pinnacle West	Reconciliation of Operating Income to Gross Margin

99.2	APS	Reconciliation of Operating Income to Gross Margin

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 Exhibit ^a*	*Effective*
3.1	Pinnacle West	Articles of Incorporation, restated as of July 29, 1988	19.1 to Pinnacle West’s September 1988 Form 10-Q Report, File No. 1-8962	11-14-88

3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of December 14, 2005	3.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	12-15-05

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


^a		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 8, 2006	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 8, 2006	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)