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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 18, 2004

PINNACLE WEST CAPITAL CORPORATION

(Exact name of registrant as specified in its charter)


Arizona	1-8962	86-0512431

(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification Number)


400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona		85072-3999

(Address of Principal Executive Offices)		(Zip Code)

(602) 250-1000

(Registrant’s telephone number, including area code)

NONE

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

AFUDC – allowance for funds used during construction

ALJ – Administrative Law Judge

ANPP – Arizona Nuclear Power Project, also known as Palo Verde

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

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

CC&N – Certificate of Convenience and Necessity

Cholla – Cholla Power Plant

Citizens – Citizens Communications Company

Clean Air Act – the Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

CPUC – California Public Utility Commission

DOE – United States Department of Energy

EITF – the 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

FIN – FASB Interpretation

Financing Order – ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May 2003

Four Corners – Four Corners Power Plant

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

IRS – United States Internal Revenue Service

ISO – California Independent System Operator

kWh – kilowatt-hour, one thousand watts per hour

Moody’s – Moody’s Investors Service

MW – megawatt, one million watts

MWh – megawatt-hours, one million watts per hour

NAC – NAC Holding Inc. and NAC International Inc., subsidiaries of El Dorado

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

1999 Settlement Agreement – comprehensive settlement agreement related to the implementation of retail electric competition

NRC – United States Nuclear Regulatory Commission

Nuclear Waste Act – Nuclear Waste Policy Act of 1982, as amended

OCI – other comprehensive income

Palo Verde – Palo Verde Nuclear Generating Station

PCAOB – Public Company Accounting Oversight Board

PG&E – PG&E Corp.

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company

PWEC Dedicated Assets – the following Pinnacle West Energy power plants, each of which is dedicated to serving APS’ customers: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3

PX – California Power Exchange

RTO – regional transmission organization

Rules – ACC retail electric competition rules

SCE – Southern California Edison Company

SEC – United States Securities and Exchange Commission

September 2004 10-Q Report – Pinnacle West Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2004

SFAS – Statement of Financial Accounting Standards

SNWA – Southern Nevada Water Authority

SPE – special-purpose entity

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

SunCor – SunCor Development Company, a subsidiary of the Company

T&D – transmission and distribution

Track A Order – ACC order dated September 10, 2002 regarding generation asset transfers and related issues

Track B Order –ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizona’s investor-owned electric utilities

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

2003 Form 10-K – Pinnacle West Capital Corporation Annual Report on Form 10-K for the fiscal year ended December 31, 2003

VIE – variable interest entity

ITEM 1.01 — ENTRY INTO A MATERIAL DEFINITIVE AGREEMENT

Asset Purchase Agreement

On December 14, 2004, APS and PPL Sundance Energy, LLC, a wholly-owned subsidiary of PPL Corporation (“PPL Sundance”) amended the Asset Purchase Agreement dated as of June 1, 2004 (the “Asset Purchase Agreement”), relating to the sale by PPL Sundance to APS of the assets comprising the 450 MW Sundance power plant located in Pinal County, Arizona. See Note 5 of Notes to Condensed Consolidated Financial Statements in the Company’s September 2004 10-Q Report.

The Asset Purchase Agreement as in effect prior to the amendment provided that either party could terminate the Asset Purchase Agreement on or before January 10, 2005 if the ACC did not, on or before December 31, 2004, issue an order approving, among other things, the purchase of the power plant assets by APS. PPL Sundance and APS have amended the Asset Purchase Agreement to provide that either party may terminate the agreement on or before January 31, 2005 if the ACC does not issue such order on or before January 21, 2005. A copy of the amendment to the Asset Purchase Agreement is attached as Exhibit 99.1 and is incorporated herein by reference.

2005 Incentive Plans

On December 14, 2004, the Human Resources Committee (the “Committee”) of the Company’s Board of Directors approved the Chairman and CEO Variable Incentive Plan (the “CEO Incentive Plan”). The Company’s Chairman of the Board and CEO, William J. Post, is eligible to receive an incentive award under the CEO Incentive Plan. Incentive award funding under the CEO Incentive Plan is triggered by the attainment of specified 2005 Company earnings. The amount of the award to Mr. Post is in the sole discretion of the Committee. Accordingly, the Committee may consider factors other than 2005 Company earnings to measure Mr. Post’s performance.

On December 15, 2004, the Company’s Board of Directors, acting on the recommendation of the Committee, approved the 2005 Officer Variable Incentive Plan (the “Officer Incentive Plan”). Each of the Company’s officers, as well as the officers of APS (currently 19 officers), are eligible to participate in the Officer Incentive Plan, including the following four most highly-compensated current executive officers (excluding the CEO) named in the Company’s proxy statement relating to its May 19, 2004 annual meeting: Jack E. Davis, President and Chief Operating Officer of the Company; Donald E. Brandt, Executive Vice President and Chief Financial Officer of the Company; James M. Levine, Executive Vice President, Generation of APS; and Steven M. Wheeler, Executive Vice President, Customer Service and Regulation of APS (the “Named Executive Officers”).

The Officer Incentive Plan is composed of two components, one of which is based on the Company’s 2005 earnings and the other on the achievement of specified business unit results. Once a specified earnings threshold is met, the achievement of the level of earnings and business unit results generally determines what award, if any, the officer receives. However, the amount of the award, if any, to each officer under the Officer Incentive Plan is in the sole discretion of the Committee. Accordingly, the Committee may consider factors other than Company earnings and the achievement of business unit results to measure performance, including input from the CEO about each officer’s 2005 achievements.

Subject to the foregoing, award opportunities (expressed as a percentage of the officer’s base salary) for the Chairman and CEO and the Named Executive Officers will be based on the following performance measures (weighted according to the indicated percentages):


Officer	Performance Measure(s)	Award Opportunity
William J. Post	Company Earnings	Threshold (63%)
		Midpoint (125%)
		Maximum (200%)

Jack E. Davis	Company Earnings	Threshold (37.5%)
		Midpoint (75%)
		Maximum (150%)

Donald E. Brandt	-Company Earnings (50%) -Shared Services Business Unit Results (Combined Generation Business Unit, Palo Verde Business Unit, and Delivery Business Unit Performance; Meeting or Exceeding Budget Targets; and Preventable Recordable Injuries) (50%)	-Company Earnings: Threshold (0%) Midpoint (25%) Maximum (50%) -Shared Services Business Unit Results (up to 50%)

James M. Levine	-Company Earnings (50%) -Generation Business Unit Results (Preventable Recordable Injuries; Coal & Nuclear Production Cost; APS Gas Units’ Annual Equivalent Availability Factor; Coal and Nuclear Capacity Factor; and Environmental) (50%)	-Company Earnings: Threshold (0%) Midpoint (25%) Maximum (50%) -Generation Business Unit Results (up to 50%)

Steven M. Wheeler	-Company Earnings (50%) -Delivery Unit Results (Preventable Recordable Injuries; Customer Satisfaction; Business Performance Trends; Customer Reliability; and Environmental Incidents) (50%)	-Company Earnings: Threshold (0%) Midpoint (25%) Maximum (50%) -Delivery Business Unit Results (up to 50%)

Award opportunities for other executive vice presidents and senior vice presidents are up to 100% of base salary (up to 50% based on Company earnings and up to 50% based on the achievement of business unit results). Award opportunities for other officers are up to 70% of base salary (up to 35% based on Company earnings and up to 35% based on the achievement of business unit results).

2005 Deferred Compensation Plan

On December 15, 2004, the Company’s Board of Directors, acting on the Committee’s recommendation, authorized the Company’s management to adopt a new nonqualified deferred compensation plan applicable to post-2004 deferrals. No future deferrals will be permitted under the Company’s existing nonqualified deferred compensation plan, the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor

Development Company, and El Dorado Investment Company Deferred Compensation Plan (the “Pre-2005 Plan”). The new plan will be based in large part on the Pre-2005 Plan, and is required as a result of the new tax law requirements imposed by Internal Revenue Code Section 409A, which was added by the American Jobs Creation Act of 2004. Under the terms of the new plan, an account will be established for each participant to record the participant’s deferrals and interest credits thereon.

Eligibility Participation is limited to Directors, officers and a select group of management or highly compensated employees of the Company, APS, SunCor and El Dorado selected by an administrative committee appointed by the Company’s Board of Directors (the “Plan Committee”). Participants include Mr. Post and each of the Named Executive Officers.

Deferrals A participant is allowed to defer up to 50% of the participant’s base salary and up to 100% of the participant’s bonus. Amounts deferred are credited with interest rates determined by the Plan Committee. Assuming the participants meet certain length-of-service requirements, the interest rate for 2005 under the Pre-2005 Plan and the new plan will be 7.5%. Deferrals of base salary must be made prior to the calendar year in which such base salary will be paid. Deferrals of any bonus payable in 2005 must be made before the end of 2004. Deferrals of bonuses paid in 2006 and future years must be made at least six months prior to the end of the earning period.

Distributions When making a deferral election, a participant will also make an election regarding the timing and manner of distributions of the participant’s deferrals and interest thereon. Changes in any such election will be permitted only to the extent allowed by Internal Revenue Code Section 409A. All distributions under the Plan will be made in accordance with Internal Revenue Code Section 409A.

Effective Date The plan will be effective as of January 1, 2005.

ITEM 8.01. OTHER EVENTS

Financial Statement Reclassification

Section 8 of this Current Report on Form 8-K is limited to the disclosure of the reclassification of financial statements of Pinnacle West to reflect reclassifications of the activities of NAC to discontinued operations, as defined by SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” In July 2004, we entered into an agreement to sell our investment in NAC. The transaction closed on November 18, 2004. This Report reflects the impact of the reclassification on the following disclosures in our 2003 Form 10-K.

• Item 8. Financial Statements and Supplementary Data; and

• Schedule II – Valuation and Qualifying Accounts.

NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER DISCLOSURES IN OUR 2003 FORM 10-K OR OUR OTHER SECURITIES AND EXCHANGE COMMISSION FILINGS.

As previously disclosed in our September 2004 10-Q Report, revenues and expenses related to NAC activities were required to be reported as discontinued operations in accordance with SFAS 144. Among other guidance, SFAS 144 prescribes accounting for discontinued operations and defines certain activities as discontinued operations. The September 2004 10-Q Report reflects certain reclassifications related to NAC’s discontinued operations for 2004 and 2003.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Pinnacle West Capital Corporation
Phoenix, Arizona

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2003 and 2002 and the related consolidated statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 18 to the consolidated financial statements, in 2003 the Company changed its method of accounting for non-trading derivatives in order to comply with the provisions of Emerging Issues Task Force Issue No. 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 Issue No. 02-3.

As discussed in Note 18 to the consolidated financial statements, in 2002 the Company changed its method of accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.

As discussed in Note 18 to the consolidated financial statements, in 2001 the Company changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona
March 11, 2004 (December 15, 2004 as to the effects of the discontinued operations of NAC described in Note 22)

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)


	Year Ended December 31,
	2003			2002			2001
OPERATING REVENUES
Regulated electricity segment	$	1,978,075		$	1,890,391		$	1,984,305
Marketing and trading segment		391,886			286,879			469,784
Real estate segment		361,604			201,081			168,908
Other revenues		27,929			26,899			11,771

Total		2,759,494			2,405,250			2,634,768

OPERATING EXPENSES
Regulated electricity segment purchased power and fuel		517,320			376,911			583,080
Marketing and trading segment purchased power and fuel		344,862			154,987			152,762
Operations and maintenance		548,732			584,538			530,095
Real estate operations segment		305,974			185,925			153,462
Depreciation and amortization		435,140			422,299			427,903
Taxes other than income taxes		110,270			107,952			101,068
Other expenses		23,254			21,895			10,375

Total		2,285,552			1,854,507			1,958,745

OPERATING INCOME		473,942			550,743			676,023

OTHER
Allowance for equity funds used during construction		14,240			—			—
Other income		35,563			14,910			26,416
Other expenses		(20,574	)		(33,655	)		(33,577	)

Total		29,229			(18,745	)		(7,161	)

INTEREST EXPENSE
Interest charges		204,339			187,039			175,822
Capitalized interest		(29,444	)		(43,749	)		(47,862	)

Total		174,895			143,290			127,960

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		328,276			388,708			540,902
INCOME TAXES		102,473			152,145			213,535

INCOME FROM CONTINUING OPERATIONS		225,803			236,563			327,367
Income (loss) from discontinued operations – net of income tax expense (benefit) of $9,616 and ($14,045)		14,776			(21,410	)		—
Cumulative effect of a change in accounting for derivatives – net of income tax benefit of ($9,892)		—			—			(15,201	)
Cumulative effect of a change in accounting for trading activities – net of income tax benefit of ($43,123)		—			(65,745	)		—

NET INCOME	$	240,579		$	149,408		$	312,166

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		91,265			84,903			84,718
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		91,405			84,964			84,930
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	2.47		$	2.79		$	3.86
Net income – basic		2.64			1.76			3.68
Income from continuing operations – diluted		2.47			2.78			3.85
Net income – diluted		2.63			1.76			3.68
DIVIDENDS DECLARED PER SHARE	$	1.725		$	1.625		$	1.525

See Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS
(dollars in thousands)


	December 31,
	2003			2002
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	222,912		$	77,566
Customer and other receivables		354,666			362,587
Allowance for doubtful accounts		(9,223	)		(9,607	)
Accrued utility revenues		88,629			94,504
Materials and supplies (at average cost)		96,099			91,652
Fossil fuel (at average cost)		28,367			28,185
Deferred income taxes (Note 4)		—			4,094
Assets from risk management and trading activities (Note 18)		97,630			102,664
Assets held for sale (Note 22)		23,065			42,339
Other current assets		72,649			66,388

Total current assets		974,794			860,372

INVESTMENTS AND OTHER ASSETS
Real estate investments – net (Notes 1 and 6)		343,322			384,427
Assets from risk management and trading activities-long term (Note 18)		138,946			191,754
Decommissioning trust accounts		240,645			194,440
Other assets		88,473			76,843

Total investments and other assets		811,386			847,464

PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9, 10 and 12)
Plants in service and held for future use		9,904,874			9,058,900
Less accumulated depreciation and amortization		3,145,609			2,917,552

Total		6,759,265			6,141,348
Construction work in progress		554,876			777,542
Intangible assets, net of accumulated amortization		108,534			109,815
Nuclear fuel, net of accumulated amortization of $58,053 and $59,163		52,011			51,124

Net property, plant and equipment		7,474,686			7,079,829

DEFERRED DEBITS
Regulatory assets (Notes 1, 3 and 4)		164,804			241,045
Other deferred debits		110,708			110,447

Total deferred debits		275,512			351,492

TOTAL ASSETS	$	9,536,378		$	9,139,157

See Notes to Consolidated Financial Statements.

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


	December 31,
	2003			2002
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	283,021		$	332,441
Accrued taxes		69,769			71,107
Accrued interest		51,825			53,018
Short-term borrowings (Note 5)		86,081			227,683
Current maturities of long-term debt (Note 6)		704,914			280,888
Customer deposits		49,783			42,190
Deferred income taxes (Note 4)		631			—
Liabilities from risk management and trading activities (Note 18)		92,755			111,329
Liabilities held for sale (Note 22)		16,427			28,855
Other current liabilities		77,362			85,585

Total current liabilities		1,432,568			1,233,096

LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)		2,616,585			2,743,741

DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)		1,329,253			1,209,074
Regulatory liabilities (Notes 1, 3 and 4)		510,423			26,264
Liability for asset retirements and removals (Note 12)		234,440			600,431
Pension liability (Note 8)		188,041			183,880
Liabilities from risk management and trading activities-long term (Note 18)		82,730			147,900
Unamortized gain – sale of utility plant (Note 9)		54,909			59,484
Other		257,650			249,134

Total deferred credits and other		2,657,446			2,476,167

COMMITMENTS AND CONTINGENCIES (NOTES 3, 11 AND 12)
COMMON STOCK EQUITY (Note 7)
Common stock, no par value; authorized 150,000,000 shares; issued 91,379,947 at end of 2003 and 2002		1,744,354			1,737,258
Treasury stock at cost; 92,015 shares at end of 2003 and 124,830 shares at end of 2002		(3,273	)		(4,358	)

Total common stock		1,741,081			1,732,900

Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		(66,564	)		(71,264	)
Derivative instruments		27,563			(20,020	)

Total accumulated other comprehensive loss		(39,001	)		(91,284	)

Retained earnings		1,127,699			1,044,537

Total common stock equity		2,829,779			2,686,153

TOTAL LIABILITIES AND EQUITY	$	9,536,378		$	9,139,157

See Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)


	Year Ended December 31,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	240,579		$	149,408		$	312,166
Adjustment to reconcile net income to net cash provided by operating activities:
Loss (income) from discontinued operations, net of tax		(14,776	)		21,410			—
Cumulative effect of accounting change, net of tax		—			65,745			15,201
Depreciation and amortization		435,140			422,299			427,903
Nuclear fuel amortization		28,757			31,185			28,362
Allowance for equity funds used during construction		(14,240	)		—			—
Deferred income taxes		81,756			191,135			(17,203	)
Change in mark-to-market valuations		17,410			(18,146	)		(133,573	)
Redhawk Units 3 and 4 cancellation charge		—			49,192			—
Changes in current assets and liabilities:
Customer and other receivables		(12,456	)		60,336			146,581
Accrued utility revenues		5,875			(18,373	)		(1,565	)
Materials, supplies and fossil fuel		(4,629	)		(11,599	)		(16,867	)
Other current assets		(6,865	)		(6,643	)		64
Accounts payable		(7,125	)		17,008			(128,017	)
Accrued taxes		(1,338	)		(36,041	)		7,483
Accrued interest		(1,193	)		4,212			5,852
Other current liabilities		8,668			24,755			3,761
Proceeds from the sale of real estate assets		163,700			57,178			35,783
Real estate investments		(71,618	)		(72,412	)		(80,603	)
Increase in regulatory assets		(11,697	)		(11,029	)		(17,516	)
Change in risk management and trading – assets		46,911			(11,700	)		(51,894	)
Change in risk management and trading – liabilities		(11,613	)		(22,783	)		45,330
Change in customer advances		7,270			(23,780	)		28,599
Change in pension liability		19,074			(3,009	)		(30,205	)
Change in other long-term assets		3,850			(13,593	)		14,746
Change in other long-term liabilities		12,829			9,785			(23,345	)

Net cash flow provided by operating activities		914,269			854,540			571,043

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(693,475	)		(893,202	)		(1,055,574	)
Capitalized interest		(29,444	)		(43,749	)		(47,862	)
Discontinued operations – Real Estate		27,193			28,917			—
Discontinued operations – NAC		(19,971	)		(12,259	)		—
Other		(21,040	)		36,635			(16,481	)

Net cash flow used for investing activities		(736,737	)		(883,658	)		(1,119,917	)

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		656,850			674,919			995,447
Short-term borrowings and payments – net		(173,303	)		(306,079	)		322,987
Dividends paid on common stock		(157,417	)		(137,721	)		(129,199	)
Repayment of long-term debt		(366,497	)		(354,916	)		(621,057	)
Common stock equity issuance		—			199,238			—
Other		8,181			2,624			(1,048	)

Net cash flow (used for) provided by financing activities		(32,186	)		78,065			567,130

NET INCREASE IN CASH AND CASH EQUIVALENTS		145,346			48,947			18,256
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		77,566			28,619			10,363

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	222,912		$	77,566		$	28,619

Supplemental disclosure of cash flow information Cash paid during the period for:
Income taxes paid/(refunded)	$	32,816		$	(17,918	)	$	223,037
Interest paid, net of amounts capitalized	$	161,581		$	126,322		$	115,276

See Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)


	Year Ended December 31,
	2003			2002			2001
COMMON STOCK (Note 7)
Balance at beginning of year	$	1,737,258		$	1,536,924		$	1,537,920
Issuance of common stock		—			199,238			—
Other		7,096			1,096			(996	)

Balance at end of year		1,744,354			1,737,258			1,536,924

TREASURY STOCK (Note 7)
Balance at beginning of year		(4,358	)		(5,886	)		(5,089	)
Purchase of treasury stock		—			(5,971	)		(16,393	)
Reissuance of treasury stock used for stock compensation, net		1,085			7,499			15,596

Balance at end of year		(3,273	)		(4,358	)		(5,886	)

RETAINED EARNINGS
Balance at beginning of year		1,044,537			1,032,850			849,883
Net income		240,579			149,408			312,166
Common stock dividends		(157,417	)		(137,721	)		(129,199	)

Balance at end of year		1,127,699			1,044,537			1,032,850

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
Balance at beginning of year		(91,284	)		(64,565	)		—
Minimum pension liability adjustment, net of tax of $3,700, $46,109 and $634		4,700			(70,298	)		(966	)
Cumulative effect of a change in accounting for derivatives, net of tax of $47,404		—			—			72,274
Unrealized gain/(loss) on derivative instruments, net of tax of $33,298, $28,820 and $71,720		51,089			43,939			(109,346	)
Reclassification of realized gain to income, net of tax of $2,343, $237 and $17,399		(3,506	)		(360	)		(26,527	)

Balance at end of year		(39,001	)		(91,284	)		(64,565	)

TOTAL COMMON STOCK EQUITY	$	2,829,779		$	2,686,153		$	2,499,323

COMPREHENSIVE INCOME (LOSS)
Net income	$	240,579		$	149,408		$	312,166
Other comprehensive income (loss)		52,283			(26,719	)		(64,565	)

Comprehensive income	$	292,862		$	122,689		$	247,601

See Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Consolidation and Nature of Operations

The consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). See Note 22 for a discussion of the sale of NAC. Significant intercompany accounts and transactions between the consolidated companies have been eliminated.

APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. APS also generates, sells and delivers electricity to wholesale customers in the western United States. In early 2003, the marketing and trading division of Pinnacle West was moved to APS for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy. See Note 3 for a discussion of the Track A Order. Pinnacle West Energy, which was formed in 1999, is the subsidiary through which we conduct our unregulated generation operations. APS Energy Services was formed in 1998 and provides competitive commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. El Dorado is an investment firm (see Note 22 for a discussion of the sale of NAC).

Accounting Records and Use of Estimates

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.

Derivative Accounting

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. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. 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.

We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.

Prior to the fourth quarter of 2002, we accounted for our trading activity at fair value, with changes in fair value reported in earnings as required by EITF 98-10 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” In the fourth quarter of 2002, we adopted EITF 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which rescinded EITF 98-10. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy trading contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

See Note 18 for additional information about our derivative and energy trading accounting policies.

Mark-to-Market Accounting

Under mark-to-market accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as current or long-term assets and liabilities from risk management and trading activities in the Consolidated Balance Sheets.

We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.

When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers. We convert quarterly and calendar year quotes into monthly prices based on historical relationships.

For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.

For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.

The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. See Note 18 for further discussion on credit risk.

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.

Regulatory Accounting

APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent the recovery of expected future costs in current customer rates.

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

As part of the 1999 Settlement Agreement with the ACC (see Note 3), we continue to amortize certain regulatory assets over an eight-year period as follows (dollars in millions):


1999	2000		2001		2002		2003		2004		Total
$164	$	158	$	145	$	115	$	86	$	18	$	686

The detail of regulatory assets is as follows (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	December 31,
	2003		2002
Remaining balance recoverable under the 1999 Settlement Agreement (a)	$	18	$	104
Spent nuclear fuel storage (Note 11)		49		46
Electric industry restructuring transition costs (Note 3)		46		40
Deferred compensation		24		23
Contributions in aid of construction		11		10
Loss on reacquired debt (b)		12		9
Other		5		9

Total regulatory assets	$	165	$	241

(a) The majority of our unamortized regulatory assets above relates to deferred income taxes (see Note 4) and rate synchronization cost deferrals (see “Rate Synchronization Cost Deferrals” below).

(b) See “Reacquired Debt Costs” below.

The detail of regulatory liabilities is as follows (dollars in millions):


	December 31,
	2003		2002
Removal costs (a)	$	480	$	—
Deferred gains on utility property		20		20
Deferred interest income (b)		8		—
Other		2		6

Total regulatory liabilities	$	510	$	26

(a) See Note 12 for information on Asset Retirement Obligations.

(b) See “ACC Financing Orders” in Note 3 for information on the “APS Loan”.

Rate Synchronization Cost Deferrals

As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense in the Consolidated Statements of Income.

Utility Plant and Depreciation

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:

• material and labor;

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• contractor costs;

• capitalized leases;

• construction overhead costs (where applicable); and

• capitalized interest or an allowance for funds used during construction.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Prior to 2003, we charged removal costs, less salvage, to accumulated depreciation. Effective January 1, 2003, we applied the provisions of SFAS 143 (see Note 12).

We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2003 were as follows:

• Fossil plant – 23 years;

• Nuclear plant – 20 years;

• Other generation – 29 years;

• Transmission – 36 years;

• Distribution – 23 years; and

• Other – 9 years.

For the years 2001 through 2003, the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 12.5%. The weighted-average rate was 3.35% for 2003, 3.35% for 2002 and 3.40% for 2001. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.

El Dorado Investments

El Dorado accounts for its investments using the equity (if significant influence) and cost (less than 20% ownership) methods.

Capitalized Interest

Capitalized interest represents the cost of debt funds used to finance construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. The rate used to calculate capitalized interest was a composite rate of 4.55% for 2003, 4.80% for 2002 and 6.13% for 2001. Capitalized interest ceases to accrue when construction is complete.

Allowance for Funds Used During Construction

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AFUDC was calculated by using a composite rate of 8.55% for 2003. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

In 2003, APS returned to the AFUDC method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This is consistent with APS returning to a vertically-integrated utility, as evidenced by APS’ recent general rate case filing, which includes the request for rate recognition of generation assets. Previously, APS capitalized interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” Although AFUDC both increases the plant balance and results in higher current earnings during the construction period, AFUDC is realized in future revenues through depreciation provisions included in rates. This change increased earnings by $11 million in 2003 as compared to what it would have been under SFAS No. 34.

Electric Revenues

We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. However, the determination and billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers since the date of the last meter reading and billing and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis in our Consolidated Statements of Income.

All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis.

We adopted 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 Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provides guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows (see Note 18 for additional information).

SunCor

SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed. SunCor recognizes income only after the assets’ title has passed. A single method of recognizing income is applied to all sales transactions within an entire home, land or commercial development project. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22 – Discontinued Operations.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an initial maturity of three months or less to be cash equivalents.

Nuclear Fuel

APS charges nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

APS also charges nuclear fuel expense for the permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel, and it charges APS $0.001 per kWh of nuclear generation. See Note 11 for information about spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.

Income Taxes

Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. See Note 4.

Reacquired Debt Costs

For debt related to the regulated portion of APS’ business, APS defers those gains and losses incurred upon early retirement and is seeking recovery in the APS general rate case (see Note 3). In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate the amortization of reacquired debt costs over an eight-year period that will end June 30, 2004. All regulatory asset amortization is included in depreciation and amortization expense in the Consolidated Statements of Income.

Real Estate Investments

Real estate investments primarily include SunCor’s land, home inventory and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In 2003, SunCor acquired two joint ventures for $10 million and consolidated $53 million of assets and $43 million of liabilities, which are included in the Consolidated Balance Sheets at December 31, 2003. The $10 million cash investment is included on the other investing line of the Consolidated Statements of Cash Flow at December 31, 2003. In addition, see Note 22 – Discontinued Operations.

Stock-Based Compensation

In 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.” The fair value method of accounting is the preferred method. 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 Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”

The following chart compares our net income, stock compensation expense and earnings per share to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through 2003 (dollars in thousands, except per share amounts):

2003
2002
2001

Net Income as reported:
$ 240,579 $ 149,408 $ 312,166

Add: Stock compensation expense included in reported net income (net of tax):
1,288 300 —

Deduct: Total stock compensation expense determined under fair value method (net of tax)
(2,994 ) (1,695 ) (2,292 )

Pro forma net income
$ 238,873 $ 148,013 $ 309,874

Earnings per share – basic:

As reported
$ 2.64 $ 1.76 $ 3.68

Pro forma (fair value method)
$ 2.62 $ 1.74 $ 3.66

Earnings per share – diluted:

As reported
$ 2.63 $ 1.76 $ 3.68

Pro forma (fair value method)
$ 2.61 $ 1.74 $ 3.65

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In order to calculate the fair value of the 2003, 2002 and 2001 stock option grants and the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options:


	2003			2002			2001
Risk-free interest rate		3.35	%		4.17	%		4.08	%
Dividend yield		5.26	%		4.17	%		3.70	%
Volatility		38.03	%		22.59	%		27.66	%
Expected life (months)		60			60			60

See Note 16 for further discussion about our stock compensation plans.

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets on our Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. The Company’s gross intangible assets (which are primarily capitalized software costs) were $237 million at December 31, 2003 and $214 million at December 31, 2002. The related accumulated amortization was $128 million at December 31, 2003 and $104 million at December 31, 2002. Amortization expense was $25 million in 2003, $21 million in 2002, and $22 million in 2001. Estimated amortization expense on existing intangible assets over the next five years is $28 million in 2004, $27 million in 2005, $25 million in 2006, $20 million in 2007, and $9 million in 2008. At December 31, 2003, the weighted average amortization period for intangible assets is 7 years.

2. Accounting Matters

See the following Notes for information about new accounting standards and other accounting matters:

• Note 8 for amended disclosure requirements (SFAS No. 132) on retirement plans and other benefits;

• Note 12 for a new accounting standard (SFAS No. 143) on asset retirement obligations;

• Note 16 for a new accounting standard (SFAS No. 148) related to stock-based compensation;

• Note 18 for EITF issues (EITF 02-3 and 03-11), DIG Issue No. C15, and a new accounting standard (SFAS No. 149) related to accounting for derivatives and energy contracts;

• Note 20 for a new FASB interpretation (FIN No. 46R) related to VIEs;

• Note 21 for a new FASB interpretation (FIN No. 45) on guarantees; and

• Note 22 for a standard (SFAS No. 144) on accounting for the impairment or disposal of long-lived assets.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. Regulatory Matters

Electric Industry Restructuring

State

1999 Settlement Agreement

The following are the major provisions of the 1999 Settlement Agreement, as approved by the ACC:

• APS has reduced rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. Based on the price reductions authorized in the 1999 Settlement Agreement, there were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; approximately $28 million ($17 million after taxes), effective July 1, 2002; and approximately $29 million ($18 million after taxes), effective July 1, 2003. For customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.

• Unbundled rates being charged by APS for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.

• There is a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor APS is prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.

• APS will be permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• APS’ distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. APS opened its distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

• Prior to the 1999 Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also states that APS will not be allowed to recover $183 million net present value (in 1999 dollars) of the $533 million. The 1999 Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As discussed below under “APS General Rate Case and Retail Rate Adjustment Mechanisms,” APS is seeking to recover amounts written off by APS as a result of the 1999 Settlement Agreement.

• The 1999 Settlement Agreement required APS to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that APS would be allowed to defer and later collect, beginning July 1, 2004, 67% of its costs to accomplish the required transfer of generation assets to an affiliate. However, as discussed below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing the Track A Order, an order preventing APS from transferring its generation assets. APS is seeking to recover all costs incurred by APS in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.

Retail Electric Competition Rules

The Rules approved by the ACC include the following major provisions:

• They apply to virtually all Arizona electric utilities regulated by the ACC, including APS.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• Effective January 1, 2001, retail access became available to all APS retail electricity customers.

• Electric service providers that get CC&N’s from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.

• Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.

• The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.

• Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, APS received a waiver to allow transfer of its competitive electric assets and services to affiliates no later than December 31, 2002. However, as discussed below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets.

Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement.

On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of APS’ property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute.

Provider of Last Resort Obligation

Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is, under the Rules, the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS’ current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below for a discussion of retail rate adjustment mechanisms that were the subject of ACC hearings in April 2003.

Track A Order

On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things:

• reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets either to an unrelated third party or to a separate corporate affiliate; and

• unilaterally modified the 1999 Settlement Agreement, which authorized APS’ transfer of its generating assets, and directed APS to cancel its activities to transfer its generation assets to Pinnacle West Energy.

On November 15, 2002, APS filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals. Arizona Public Service Company vs. Arizona Corporation Commission, CV 2002-0222 32. Arizona Public Service Company vs. Arizona Corporation Commission, 1CA CC 02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for resolving certain issues raised by APS in its appeals of the Track A Order. APS and the ACC are the only parties to the Track A Order appeals. The major provisions of the principles include, among other things, the following:

• APS and the ACC staff agreed that it would be appropriate for the ACC to consider the following matters in APS’ general rate case, which was filed on June 27, 2003:

• the generating assets to be included in APS’ rate base, including the question of whether the PWEC Dedicated Assets should be included in APS’ rate base;

• the appropriate treatment of the $234 million pretax asset write-off agreed to by APS as part of the 1999 Settlement Agreement; and

• the appropriate treatment of costs incurred by APS in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy.

• Upon the ACC’s issuance of a final decision that is no longer subject to appeal approving APS’ request to provide $500 million of financing or credit support to Pinnacle West Energy or the Company, with appropriate conditions, APS’ appeals of the Track A Order would be limited to the issues described in the preceding bullet points, each of which would be presented to the ACC for consideration prior to any final judicial resolution. As noted below, the ACC issued the Financing Order on April 4, 2003. The Financing Order is final and no longer subject to appeal. As a result, APS’ appeals of the Track A Order are limited to the issues described in the preceding bullet points.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On August 27, 2003, APS, Pinnacle West and Pinnacle West Energy filed a lawsuit asserting damage claims relating to the Track A Order. Arizona Public Service Company et al. v. The State of Arizona ex rel., Superior Court of the State of Arizona, County of Maricopa, No. CV2003-016372.

Track B Order

On March 14, 2003, the ACC issued the Track B Order, which required APS to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003, APS was required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS’ total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS’ retail load and APS’ retail energy sales. The Track B Order also confirmed that it was “not intended to change the current rate base status of [APS’] existing assets.”

The order recognizes APS’ right to reject any bids that are unreasonable, uneconomical or unreliable. The ACC staff and an independent monitor participated in the Track B procurement process. The Track B Order also contains requirements relating to standards of conduct between APS and any affiliate of APS participating in the competitive solicitation, requires that APS treat bidders in a non-discriminatory manner and requires APS to file a protocol regarding short-term and emergency procurements. The order permits the provision by APS of corporate oversight, support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with confidential APS bidding information that is not available to other bidders. The order directs APS to evaluate bids on cost, reliability and reasonableness. The decision requires bidders to allow the ACC to inspect their plants and requires assurances of appropriate competitive market conduct from senior officers of such bidders. Following the solicitation, the decision requires APS to prepare a report evaluating environmental issues relating to the procurement, and a series of workshops on environmental risk management will be commenced thereafter.

APS issued requests for proposals in March 2003 and, by May 6, 2003, APS entered into contracts to meet all or a portion of its requirements for the years 2003 through 2006 as follows:

(1) Pinnacle West Energy agreed to provide 1,700 MW in July through September of 2003 and in June through September of 2004, 2005 and 2006, by means of a unit contingent contract.

(2) PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3) Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.

ACC Financing Orders

On April 4, 2003, the ACC issued the Financing Order authorizing APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate (the “APS Loan”), subject to the following principal conditions:

• any debt issued by APS pursuant to the order must be unsecured;

• the APS Loan must be callable and secured by the PWEC Dedicated Assets;

• the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on APS debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security);

• the 264 basis points referred to in the previous bullet point will be capitalized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum;

• the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC;

• any demonstrable increase in APS’ cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;

• APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its common equity ratio below that threshold, unless otherwise waived by the ACC. The ACC will process any waiver request within sixty days, and for this sixty-day period this condition will be suspended. However, this condition, which will continue indefinitely, will not be permanently waived without an order of the ACC; and

• certain waivers of the ACC’s affiliated interest rules previously granted to APS and its affiliates will be temporarily withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each, a “Covered Transaction”), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, except that the foregoing restrictions will not apply to the following categories of Covered Transactions:

• Covered Transactions less than $100 million, measured on a cumulative basis over the calendar year in which the Covered Transactions are made;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCor’s anticipated accelerated asset sales activity during those years;

• Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy’s (a) West Phoenix Unit 5, located in Phoenix, and (b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and

• Covered Transactions related to the sale of 25% of the Silverhawk plant to SNWA pursuant to an agreement between SNWA and Pinnacle West Energy.

The ACC also ordered the ACC staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003, APS submitted its report on these matters to the ACC staff. The ACC has indicated that the preliminary investigation would be addressed in the pending general rate case (see below).

On May 12, 2003, APS issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to us to fund the repayment of a portion of the debt we incurred to finance the construction of the PWEC Dedicated Assets. See Note 6.

On November 22, 2002, the ACC issued an order approving APS’ request to permit APS to make short-term advances to Pinnacle West in the form of an interaffiliate line of credit in the amount of $125 million. As of December 31, 2003, there were no borrowings outstanding under this financing arrangement, and this authority expired on December 4, 2003.

APS General Rate Case and Retail Rate Adjustment Mechanisms

As noted above, on June 27, 2003, APS filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, to become effective July 1, 2004. In this rate case, APS updated its cost of service and rate design.

Major Components of the Request The major reasons for the request include:

• complying with the provisions of the 1999 Settlement Agreement;

• incorporating significant increases in fuel and purchased power costs, including results of purchases through the ACC’s Track B procurement process;

• recognizing changes in APS’ cost of service, cost allocation and rate design;

• obtaining rate recognition of the PWEC Dedicated Assets;

• recovering $234 million written off by APS as a result of the 1999 Settlement Agreement; and

• recovering restructuring and compliance costs associated with the ACC’s Rules.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Requested Rate Increase The requested rate increase totals $175.1 million, or 9.8%, and is comprised of the following items (dollars in millions):


	Annual Revenue		Percent
Increase in base rates	$	166.8		9.3	%
Rules compliance charge		8.3		0.5	%

Total increase	$	175.1		9.8	%

Test Year The filing is based on an adjusted historical test year ended December 31, 2002.

Cost of Capital The proposed weighted average cost of capital for the test year ended December 31, 2002 is 8.67%, including an 11.5% return on equity.

Rate Base The request is based on a rate base of $4.2 billion, calculated using Original Cost Less Depreciation (“OCLD”) methodology. The OCLD rate base approximates the ACC-jurisdictional portion of the net book value of utility plant, net of accumulated depreciation and deferred taxes, as of December 31, 2002, except as set forth below.

The requested rate base includes the PWEC Dedicated Assets, with a total combined capacity of approximately 1,800 MW. These assets were included at their estimated July 1, 2004 net book value. Upon approval of the request, the PWEC Dedicated Assets would be transferred to APS from Pinnacle West Energy.

The filing also includes calculated amounts for Fair Value Rate Base and Replacement Cost New Depreciated (“RCND”) rate base. The ACC is required by the Arizona Constitution to make a finding of Fair Value Rate Base, which has traditionally been defined by the ACC as the arithmetic average of OCLD rate base and RCND rate base.

Recovery of Previous $234 Million Write-Off The request includes recovery, over a fifteen year period, of the write-off of $234 million pretax of regulatory assets by APS as a result of the 1999 Settlement Agreement. See “1999 Settlement Agreement” above.

Estimated Timeline APS has asked the ACC to approve the requested rate increase by July 1, 2004. The ACC ALJ has issued a procedural schedule setting a hearing date on the application of May 25, 2004. Based on the schedule and existing ACC regulations, we believe the ACC will be able to make a decision in this general rate case by the end of 2004.

The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the Rules.

On November 4, 2003, the ACC approved the issuance of an order which authorizes a rate adjustment mechanism allowing APS to recover changes in purchased power costs (but not changes in fuel costs) incurred after July 1, 2004. The other rate adjustment mechanisms authorized in the 1999 Settlement Agreement (such as the costs associated with complying with the ACC electric competition rules) were also tentatively approved for subsequent implementation in the general rate case. The provisions of this order will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend, modify or reconsider, in its entirety, this November 4 order during the rate case.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Testimony As required by the procedural schedule, on February 3, 2004, the following parties filed their initial written testimony with the ACC on all issues except cost of service (i.e., cost allocation among customer classes) and rate design:

• the ACC “litigation” staff;

• the Arizona Residential Utility Consumers Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and

• other approved rate case interveners.

ACC Staff Recommendations In its filed testimony, the ACC staff recommended, among other things, that the ACC:

• decrease APS’ annual retail electricity revenues by at least $142.7 million, which would result in a rate decrease of approximately 8%, based on a 9% return on equity;

• not allow the PWEC Dedicated Assets to be included in APS’ rate base;

• not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement; and

• not implement any adjustment mechanisms for fuel and purchased power.

The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard.

The ACC staff also submitted testimony indicating that APS and its affiliates had violated the “spirit, if not the letter” of the Rules, the Code of Conduct and the 1999 Settlement Agreement.

RUCO Recommendations In its filed testimony, RUCO recommended, among other things, that the ACC:

• decrease APS’ annual retail electricity revenues by $53.6 million, which would result in a rate decrease of approximately 2.84%, based on a 9.5% return on equity;

• not allow the PWEC Dedicated Assets to be included in APS’ rate base;

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

• not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement; and

• not implement any adjustment mechanisms for fuel and purchased power.

APS believes that its rate request is necessary to ensure APS’ continued ability to reliably serve one of the fastest growing regions in the country and views any ultimate decision that would deny recovery of the Company’s investment in the PWEC Dedicated Assets as constituting a regulatory “taking.” APS will vigorously oppose the recommendations of the ACC staff, RUCO, and other parties offering similar recommendations.

Request for Proposals

In early December 2003, APS issued a request for proposals (“RFP”) for long-term power supply resources, and on January 8, 2004, an ACC Administrative Law Judge issued an order requiring, among other things, APS to file a summary of the proposals with the ACC. On January 27, 2004, APS filed a summary of the proposals with the ACC. APS is negotiating with certain of the parties that submitted proposals.

Federal

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. Sales at prices above the cap must be justified and are subject to potential refund.

On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule. On April 28, 2003, the FERC Staff issued an additional white paper on the proposed Standard Market Design. The white paper discusses several policy changes to the proposed Standard Market Design, including a greater emphasis on flexibility for regional needs. We cannot currently predict what, if any, impact there may be to the Company if the FERC adopts the proposed rule or any modifications proposed in the comments.

General

The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. Income Taxes

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.

APS has recorded a regulatory asset related to income taxes on its Balance Sheets in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. APS amortizes this amount as the differences reverse. In accordance with ACC settlement agreements, APS is continuing to accelerate amortization of a regulatory asset related to income taxes over an eight-year period that will end June 30, 2004 (see Note 1). Accordingly, we are including this accelerated amortization in depreciation and amortization expense on our Consolidated Statements of Income.

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. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return. In 2003, we resolved certain prior-year issues with the taxing authorities and recorded an $18 million tax benefit associated with tax credits and other reductions to income tax expense.

The components of income tax expense are as follows (dollars in thousands):


	Year Ended December 31,
	2003		2002			2001
Current:
Federal	$	22,875	$	(43,492	)	$	184,893
State		3,752		(14,732	)		45,845

Total current		26,627		(58,224	)		230,738
Deferred		85,462		153,201			(27,095	)

Total income tax expense		112,089		94,977			203,643
Less: income tax expense/(benefit) on discontinued operations		9,616		(14,045	)		—
Less: income tax benefit for cumulative effect of accounting change		—		(43,123	)		(9,892	)

Total income tax expense for income from continuing operations	$	102,473	$	152,145		$	213,535

The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year Ended December 31,
	2003			2002			2001
Federal income tax expense at 35% statutory rate	$	114,897		$	136,048		$	189,316
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		14,017			18,114			23,353
Credits and favorable adjustments related to prior years resolved in 2003		(17,944	)		—			—
Allowance for equity funds used during construction (see Note 1)		(5,616	)		—			—
Other		(2,881	)		(2,017	)		866

Income tax expense	$	102,473		$	152,145		$	213,535

The following table sets forth the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):


	December 31,
	2003			2002
Current asset/(liability)	$	(631	)	$	4,094
Long term liability		(1,329,253	)		(1,209,074	)

Accumulated deferred income taxes — net	$	(1,329,884	)	$	(1,204,980	)

The components of the net deferred income tax liability were as follows (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	December 31,
	2003			2002
DEFERRED TAX ASSETS
Pension liability	$	73,844		$	72,835
Risk management and trading activities		59,293			43,542
Regulatory liabilities:
Federal excess deferred income taxes		18,936			20,887
Other		33,542			9,818
Deferred gain on Palo Verde Unit 2 sale leaseback		21,656			23,562
Other		64,769			89,236

Total deferred tax assets		272,040			259,880

DEFERRED TAX LIABILITIES
Plant-related		(1,448,730	)		(1,316,636	)
Regulatory assets		(69,070	)		(101,522	)
Risk management and trading activities		(84,124	)		(46,702	)

Total deferred tax liabilities		(1,601,924	)		(1,464,860	)

Accumulated deferred income taxes — net	$	(1,329,884	)	$	(1,204,980	)

5. Lines of Credit and Short-Term Borrowings

APS had committed lines of credit with various banks of $250 million at December 31, 2003 and 2002, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The current line matures in May 2004, and the document allows for a 364-day extension of the termination date without lender consent. The commitment fees at December 31, 2003 and 2002 for these lines of credit were 0.175% and 0.09% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2003 and 2002.

APS had no commercial paper borrowings outstanding at December 31, 2003 and 2002. By Arizona statute, APS’ short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC.

Pinnacle West had committed lines of credit of $275 million at December 31, 2003 and $475 million at December 31, 2002, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The current lines mature in November and December of 2004 and the $150 million facility allows for a 364-day extension of the termination date without lender consent. Pinnacle West had no outstanding borrowings at December 31, 2003 and $72 million was outstanding at December 31, 2002. The commitment fees ranged from 0.125% to 0.175% in 2003 and ranged from 0.10% to 0.15% in 2002. Pinnacle West had no commercial paper borrowings outstanding at December 31, 2003. Commercial paper borrowings outstanding were $24 million at December 31, 2002. The weighted average interest rate on commercial paper borrowings was 2.06% for the year ended December 31, 2002.

All APS and Pinnacle West bank lines of credit and commercial paper agreements are unsecured.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On November 22, 2002, the ACC approved APS’ request to permit APS to make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million. This interim loan matured in December 2003, and there were never any borrowings on this line.

SunCor had revolving lines of credit totaling $120 million at December 31, 2003 and $140 million at December 31, 2002. The commitment fees were 0.125% in 2003 and 2002. SunCor had $50 million outstanding at December 31, 2003 and $126 million outstanding at December 31, 2002. The weighted-average interest rate was 4.50% at December 31, 2003 and was 3.75% at December 31, 2002. Interest for 2003 and 2002 was based on LIBOR plus 2% or prime plus 0.5%. The balance is included in short-term debt on the Consolidated Balance Sheets. SunCor had other short-term loans in the amount of $36 million at December 31, 2003 and $6 million outstanding at December 31, 2002. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2003 and 2002. In addition, two notes acquired in 2003 had interest rates of 3.37% and 3.87%.

6. Long-Term Debt

Borrowings under the APS mortgage bond indenture are secured by substantially all utility plant. APS also has unsecured debt. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2003 and 2002 (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Maturity	Interest		December 31,
	Dates (a)	Rates		2003			2002
APS
First mortgage bonds	2004	6.625	%	$	80,000		$	80,000
	2023	7.25	%(b)		—			54,150
	2025	8.0	%(c)		—			33,075
	2028	5.5	%		25,000			25,000
	2028	5.875	%		154,000			154,000
Unamortized discount and premium					(8,631	)		(6,337	)
Pollution control bonds	2024-2034		(d)		386,860			386,860
Pollution control bonds with senior notes (e)	2029	5.05	%		90,000			90,000
Unsecured notes	2004	5.875	%		125,000			125,000
Unsecured notes	2005	6.25	%		100,000			100,000
Unsecured notes	2005	7.625	%		300,000			300,000
Unsecured notes	2011	6.375	%		400,000			400,000
Unsecured notes	2012	6.50	%		375,000			375,000
Unsecured notes	2033	5.625	%		200,000			—
Unsecured notes	2015	4.650	%		300,000			—
Senior notes (f)	2006	6.75	%		83,695			83,695
Capitalized lease obligations	2004-2012		(g)		11,749			20,400

Subtotal					2,622,673			2,220,843

SUNCOR
Notes payable	2004-2008		(h)		17,125			7,647
Capitalized lease obligations	2004-2005	8.91	%		728			1,299

Subtotal					17,853			8,946

PINNACLE WEST
Senior notes	2004-2006		(i)		515,000			540,000
Unamortized discount and premium					(270	)		(530	)
Floating rate notes	2003		(j)		—			250,000
Floating senior notes	2005		(k)		165,000			—
Capitalized lease obligations	2004-2007	5.48	%		1,243			1,999

Subtotal					680,973			791,469

EL DORADO
Construction loan	2005	1.22	%		—			2,600
Capitalized lease obligations	2004-2005		(l)		—			771

Subtotal					—			3,371

Total long-term debt					3,321,499			3,024,629
Less current maturities					704,914			280,888

TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES				$	2,616,585		$	2,743,741

(a) This schedule does not reflect the timing of redemptions that may occur prior to maturity.

(b) On August 15, 2003, APS redeemed at maturity $54 million of its First Mortgage Bonds, 7.25% Series due 2023.

(c) On April 7, 2003, APS redeemed $33 million of its First Mortgage Bonds, 8.00% Series due 2025.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(d) The weighted-average rate was 1.51% at December 31, 2003 and 1.94% at December 31, 2002. Changes in short-term interest rates would affect the costs associated with this debt.

(e) On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned the proceeds to APS pursuant to a loan agreement. The bonds were issued to refinance $90 million of outstanding pollution control bonds. The bondholders were issued $90 million of first mortgage bonds (senior note mortgage bonds) as collateral.

(f) APS currently has outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes, as well as the $90 million issue discussed in footnote (e) above. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity and redemption provisions as the senior notes. APS’ payments of principal, premium and/or interest on the senior notes satisfy its corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When APS repays all of its first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding.

(g) The weighted average rate was 5.55% at December 31, 2003 and 5.78% at December 31, 2002. Capital leases are included in property, plant and equipment on the Consolidated Balance Sheets for both December 31, 2003 and December 31, 2002.

(h) Multiple notes with variable interest rates based on the lenders’ prime plus 0.25%, lenders’ prime plus 1.75% and LIBOR plus 2.5%. There is also one note at a fixed rate of 7.96%.

(i) Includes two series of notes: $300 million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of December 31, 2002. In December 2003, we repaid the $25 million note. On January 29, 2004, we entered into a fixed-for-floating interest rate swap transaction on the $300 million 6.4% note. The transaction qualifies as a fair value hedge under SFAS No. 133.

(j) The weighted average rate was 2.85% at December 31, 2002. Interest for 2002 was based on LIBOR plus 0.98%. In June 2003, we repaid the $250 million floating note.

(k) The weighted average rate was 1.980% at December 31, 2003. Interest for 2003 was based on LIBOR plus 0.80%.

(l) The weighted average rate was 7.04% at December 31, 2002.

Pinnacle West’s and APS’ debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet the covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for each of the Company and APS individually. At December 31, 2003, the ratio was approximately 54% for Pinnacle West. At December 31, 2003, the ratio was approximately 53% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. Based on 2003 results, the coverages were approximately 4 times for the Company, 4 times for the APS bank agreements and 15 times for the APS mortgage indenture. 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.

Neither Pinnacle West’s nor APS’ financing agreements contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

downgrade. However, in the event of a ratings 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 other 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 other agreements. Pinnacle West’s and APS’ credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects.

The following is a list of payments due on total long-term debt and capitalized lease requirements through 2008:

• $705 million in 2004;

• $568 million in 2005;

• $395 million in 2006;

• $2 million in 2007;

• $6 million in 2008; and

• $1,654 million, thereafter.

APS’ first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. APS may pay dividends on its common stock if there is a sufficient amount “available” from retained earnings and the excess of cumulative book depreciation (since the mortgage’s inception) over mortgage depreciation, which is the cumulative amount of additional property pledged each year to address collateral depreciation. As of December 31, 2003, the amount “available” under the mortgage would have allowed APS to pay approximately $3 billion of dividends compared to APS’ current annual common stock dividends of $170 million.

The mortgage currently constitutes a lien on substantially all of the property of APS. We anticipate that in early April 2004, all first mortgage bonds issued by APS under its existing mortgage and deed of trust, other than the first mortgage bonds securing APS’ senior notes, will have been paid and retired. At that time, APS’ obligation to make payment on the first mortgage bonds securing the senior notes will also be deemed to be satisfied and discharged and the senior note first mortgage bonds will cease to secure the senior notes. APS is then obligated to take all steps necessary to terminate its existing mortgage and deed of trust and cannot issue any additional first mortgage bonds under that mortgage.

7. Common Stock and Treasury Stock

Our common stock and treasury stock activity during each of the three years 2003, 2002 and 2001 is as follows (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Common Stock					Treasury Stock
	Shares		Amount			Shares			Amount
Balance at December 31, 2000		84,824,947	$	1,537,920			(109,638	)	$	(5,089	)
Purchase of treasury stock		—		—			(334,600	)		(16,393	)
Reissuance of treasury stock for stock compensation (net)		—		—			342,931			15,596
Other		—		(996	)		—			—

Balance at December 31, 2001		84,824,947		1,536,924			(101,307	)		(5,886	)
Common stock issuance - December 23, 2002		6,555,000		199,238			—			—
Purchase of treasury stock		—		—			(150,500	)		(5,971	)
Reissuance of treasury stock for stock compensation (net)		—		—			126,977			7,499
Other		—		1,096			—			—

Balance at December 31, 2002		91,379,947		1,737,258			(124,830	)		(4,358	)
Reissuance of treasury stock for stock compensation (net)		—		—			32,815			1,085
Other		—		7,096			—			—

Balance at December 31, 2003		91,379,947	$	1,744,354			(92,015	)	$	(3,273	)

8. Retirement Plans and Other Benefits

Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance plan for all new employees in place of the defined benefit plan, and, as of April 1, 2003, the plan was offered as an alternative to the defined benefit plan for all existing employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all of our employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

In December 2003, FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to enhance disclosures of relevant accounting information by

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

providing additional information on plan assets, obligations, cash flows, and net cost. The revisions are reflected in this Note. Pinnacle West uses a December 31 measurement date for its plans.

On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug costs. We have not yet quantified the effect, if any, on accumulated projected benefit obligation or the net periodic postretirement benefit cost in our financial statements and accompanying notes. Specific accounting guidance for this subsidy, including transition rules, is pending.

The following table provides details of the plan’s benefit costs. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants (dollars in thousands):


	Pension									Other Benefits
	2003			2002			2001			2003			2002			2001
Service cost-benefits earned during the period	$	37,662		$	30,333		$	27,640		$	15,858		$	12,036		$	9,438
Interest cost on benefit obligation		76,951			71,242			66,549			30,163			25,235			21,585
Expected return on plan assets		(65,046	)		(75,652	)		(77,340	)		(18,762	)		(21,116	)		(21,985	)
Amortization of:
Transition (asset)/obligation		(3,227	)		(3,227	)		(3,227	)		3,005			4,001			7,698
Prior service cost/(credit)		2,401			2,912			3,008			(125	)		(75	)		—
Net actuarial loss/(gain)		18,135			1,846			907			9,714			3,072			(4,066	)

Net periodic benefit cost	$	66,876		$	27,454		$	17,537		$	39,853		$	23,153		$	12,670

Portion of cost charged to expense	$	30,094		$	13,727		$	8,944		$	17,934		$	11,577		$	6,462

The following table sets forth the plan’s change in the benefit obligations for the plan years 2003 and 2002 (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Pension						Other Benefits
	2003			2002			2003			2002
Benefit obligation at January 1	$	1,069,577		$	931,646		$	409,874		$	318,355
Service cost		37,662			30,333			15,858			12,036
Interest cost		76,951			71,242			30,163			25,235
Benefit payments		(43,869	)		(35,230	)		(15,749	)		(10,473	)
Actuarial losses		171,420			71,696			106,475			108,979
Plan amendments		(4,113	)		(110	)		(6,440	)		(44,258	)(a)

Benefit obligation at December 31	$	1,307,628		$	1,069,577		$	540,181		$	409,874

(a) The plan was amended in January 2002 to increase the deductibles, out-of-pocket maximums and prescription drug co-pays. The plan was amended in June 2002 to increase the participants’ portion of premiums.

The following table sets forth the qualified defined benefit plan and other benefit plan changes in the fair value of plan assets for the years 2003 and 2002 (dollars in thousands):


	Pension						Other Benefits
	2003			2002			2003			2002
Fair value of plan assets at January 1	$	720,807		$	764,873		$	223,474		$	237,810
Actual gain/(loss) on plan assets		162,571			(36,966	)		46,071			(27,802	)
Employer contributions		46,000			26,600			39,852			23,600
Benefit payments		(42,067	)		(33,700	)		(15,346	)		(10,134	)

Fair value of plan assets at December 31	$	887,311		$	720,807		$	294,051		$	223,474

The following table shows a reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets as of December 31, 2003 and 2002 (dollars in thousands):


	Pension						Other Benefits
	2003			2002			2003			2002
Funded status at December 31	$	(420,317	)	$	(348,770	)	$	(246,130	)	$	(186,400	)
Unrecognized net transition (asset)/obligation		(7,099	)		(10,327	)		27,044			36,489
Unrecognized prior service cost/(credit)		16,634			23,148			(1,547	)		(1,673	)
Unrecognized net actuarial losses/(gains)		348,982			293,223			217,611			148,268

Benefit liability recognized in the Consolidated Balance Sheet	$	(61,800	)	$	(42,726	)	$	(3,022	)	$	(3,316	)

The following sets forth the details related to benefits included on the Consolidated Balance Sheets (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Pension						Other Benefits
	2003			2002			2003			2002
Accrued benefit cost	$	(61,800	)	$	(42,726	)	$	(3,022	)	$	(3,316	)
Additional minimum liability		(126,241	)		(141,154	)		—			—

Total liability		(188,041	)		(183,880	)		(3,022	)		(3,316	)
Intangible asset		16,634			23,147			—			—
Accumulated other comprehensive income (pretax)		109,607			118,007			—			—

Net amount recognized	$	(61,800	)	$	(42,726	)	$	(3,022	)	$	(3,316	)

The following table sets forth the other comprehensive income arising from the change in additional minimum liability for the years ended December 31, 2003 and 2002 (dollars in thousands):


	2003		2002
Decrease/(Increase) in minimum liability included in other comprehensive income – net of tax	$	4,700	$	(70,298	)

The following table sets forth the projected benefit obligation and the accumulated benefit obligation for pension plans in excess of plan assets for the plan years 2003 and 2002 (dollars in thousands):


	2003		2002
Projected benefit obligation	$	1,307,628	$	1,069,577

Accumulated benefit obligation	$	1,075,352	$	904,687
Less fair value of plan assets		887,311		720,807

Pension liability	$	188,041	$	183,880

Below are the weighted-average assumptions for both the pension and other benefits used to determine each respective benefit obligation and net periodic benefit cost:


							Benefit Costs
	Benefit Obligations						For the Years Ended
	As of December 31,						December 31,
	2003			2002			2003			2002
Discount rate		6.10	%		6.75	%		6.75	%		7.50	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
Expected long-term return on plan assets		9.00	%		9.00	%		9.00	%		10.00	%
Initial health care cost trend rate		8.00	%		8.00	%		8.00	%		7.00	%
Ultimate health care cost trend rate		5.00	%		5.00	%		5.00	%		5.00	%
Year ultimate health care trend rate is reached		2008			2007			2007			2006

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2003, we decreased our pretax expected long-term rate of return on plan assets from 10% to 9%, as a result of continued declines in general equity and bond market conditions. For the year 2004 we are assuming a 9% rate of return on plan assets. This rate is reflective of the market returns earned historically on our target asset allocation. As recent history has demonstrated, markets may decline and increase dramatically. However, the long-term rate of return on plan assets of 9% is reasonable given our asset allocation in relation to historical and expected future performance.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):


	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	7		($5	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	$	9		($7	)
Effect on the accumulated other postretirement benefit obligation	$	95		($76	)

Plan Assets

Pinnacle West’s qualified pension plan asset allocation at December 31, 2003, and 2002 is as follows:


	Percentage of Plan Assets
	at December 31,
Asset Category:	2003			2002			Target Asset Allocation
Equity securities		65	%		56	%		50–70	%
Debt securities		23			31			20–40	%
Other		12			13			5–15	%

Total		100	%		100	%

The Board of Directors has established an investment policy for the pension plan assets and has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with a stated tolerance of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.

Pinnacle West’s other postretirement benefit plan asset allocation at December 31, 2003, and 2002, is as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Percentage of Plan Assets
	at December 31,
Asset Category:	2003			2002			Target Asset Allocation
Equity securities		71	%		62	%		60–80	%
Fixed Income		25			34			20–35	%
Other		4			4			1–6	%

Total		100	%		100	%

The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the postretirement benefit plans. The investment policy for other post retirement benefit plan assets is similar to that of the pension plan assets described above.

Contributions

Under current law, we are required to contribute approximately $100 million to our pension plans in 2004 and expect to contribute approximately $50 million to our other postretirement benefit plans in 2004. If currently pending legislation is enacted, our required pension contribution in 2004 would decrease to the $25 to $50 million range.

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and subsidiaries. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account. Under this plan, the Company matches a percentage of the participants’ contributions in the form of Pinnacle West stock. After a five year vesting period, participants have an option to transfer the Company matching contributions out of the Pinnacle West Stock Fund to other investment funds within the plan. At December 31, 2003, approximately 23% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately $5 million for each of the years 2003, 2002 and 2001.

Severance Charges

In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $36 million before taxes in voluntary severance costs in 2002. No further charges are expected.

9. Leases

In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, a regulatory

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the SPEs involved in the Palo Verde sale leaseback transactions.

In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.

Total lease expense recognized in the Consolidated Statements of Income was $67 million in 2003, $67 million in 2002 and $59 million in 2001.

The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2004 to 2015.

In accordance with the 1999 Settlement Agreement and previous settlement agreements, APS is continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). All regulatory asset amortization is included in depreciation and amortization expense in the Consolidated Statements of Income. The balance of this regulatory asset at December 31, 2003 was $5 million.

Estimated future minimum lease payments for our operating leases are approximately as follows (dollars in millions):


Year
2004	$	73
2005		70
2006		68
2007		66
2008		66
Thereafter		421

Total future lease commitments	$	764

10. Jointly-Owned Facilities

APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS’ interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2003. APS’ share of operating and maintaining these facilities is included in the Consolidated Statements of Income in operations and maintenance expense (dollars in thousands):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Percent								Construction
	Owned by			Plant in		Accumulated			Work in
	APS			Service		Depreciation			Progress
Generating facilities:
Palo Verde Nuclear Generating Station Units 1 and 3		29.1	%	$	1,880,218	$	(867,322	)	$	21,620
Palo Verde Nuclear Generating Station Unit 2 (see Note 9)		17.0	%		681,744		(242,131	)		9,771
Four Corners Steam Generating Station Units 4 and 5		15.0	%		154,111		(81,369	)		2,580
Navajo Steam Generating Station Units 1, 2 and 3		14.0	%		242,987		(111,744	)		2,352
Cholla Steam Generating Station Common Facilities (a)		62.4	%(b)		78,500		(44,379	)		1,338
Transmission facilities:
ANPP500KV System		35.8	%(b)		68,457		(27,050	)		40
Navajo Southern System		31.4	%(b)		26,903		(17,971	)		128
Palo Verde – Yuma 500KV System		23.9	%(b)		9,583		(4,364	)		602
Four Corners Switchyards		27.5	%(b)		2,852		(1,734	)		—
Phoenix – Mead System		17.1	%(b)		36,418		(3,567	)		—
Palo Verde – Estrella 500KV System		55.5	%(b)		70,972		(1,615	)		1,632
Palo Verde SE Valley Project		15.0	%(b)		—		—			648

(a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned.

(b) Weighted average of interests.

11. Commitments and Contingencies

Enron

We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. This amount is comprised of a $15 million reserve for the Company’s net exposure to Enron and its affiliates and additional expenses of $6 million primarily related to 2002 power contracts with Enron that were canceled. These charges take into consideration our rights of set-off with respect to the Enron related contractual obligations. The APS portion of the write-off was $13 million. The basis of the set-offs included, but was not limited to, provisions in the various contractual arrangements with Enron and its affiliates, including an International Swaps and Derivative Agreement (ISDA) between APS and Enron North America. The write-off is also net of the expected recovery based on secondary market quotes from the bond market. The amounts were written-off from the balances of the related assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. In February 2004, Enron filed an adversary proceeding against APS in bankruptcy court regarding differences in the valuation of trading positions involving APS. Enron North America v. Arizona Public Service Company, Adversary Proceeding No. 04-02366 (ALJ). APS will vigorously defend this action and does not believe it will have any material adverse impact on its anticipated exposure to Enron described above.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Palo Verde Nuclear Generating Station

Spent 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 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 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. 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. Arizona Public Service Company v. United States of America, United States Court of Federal Claims, 03-2832C.

In February 2002, the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the President’s recommendation. Congress approved the Yucca Mountain site, overriding the Nevada veto. It is now expected that the DOE will submit a license application to the NRC in late 2004. The State of Nevada has filed several lawsuits relating to the Yucca Mountain site. We cannot currently predict what further steps will be taken in this area.

APS has existing fuel storage pools at Palo Verde and is operating a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, APS believes spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.

Although some low-level waste has been stored on-site in a low-level waste facility, APS is currently shipping low-level waste to off-site facilities. APS currently believes interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.

APS currently estimates it will incur $115 million (in 2003 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2003, APS had spent $7 million and recorded a liability of $42 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. APS has recorded a corresponding regulatory asset of $49 million and is seeking recovery of these costs through future rates (see “APS General Rate Case and Retail Rate Mechanisms” in Note 3).

APS has reclassified prior year spent nuclear fuel costs of approximately $44 million previously included in accumulated amortization of nuclear fuel to the liability for asset retirements and removals on our Consolidated Balance Sheets at December 31, 2002. Upon adoption of SFAS No. 143 in 2003, APS reclassified this liability to a regulatory liability because no legal obligation for removal exists.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

APS believes that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, APS acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which APS is less able to predict. APS expects to vigorously protect and pursue its rights related to this matter.

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 programs 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 $10 million per incident. 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 $9 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 outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

Purchased Power and Fuel Commitments

APS and Pinnacle West are parties to various purchased power and fuel contracts with terms expiring from 2004 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $209 million in 2004; $68 million in 2005; $66 million in 2006; $51 million in 2007; $51 million in 2008 and $461 million thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

Of the various purchased power and fuel contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for the supply of its coal and nuclear fuel supply have take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2016. The current take-or-pay nuclear fuel contracts expire in 2004 and had not been renewed as of December 31, 2003.

The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


					Estimated
	Years Ending December 31,
	2004		2005		2006		2007		2008		Thereafter
Coal		41		42		43		44		43		306
Nuclear		11		—		—		—		—		—

Total take-or-pay commitments (a)	$	52	$	42	$	43	$	44	$	43	$	306

(a) Total take-or-pay commitments are approximately $530 million. The total net present value of these commitments is approximately $340 million.

Coal Mine Reclamation Obligations

APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. Our coal mine reclamation obligation was $60 million at December 31, 2003 and $59 million at December 31, 2002 and is included in deferred credits-other in the Consolidated Balance Sheets.

A regulatory asset has been established for amounts not yet recovered from ratepayers related to the coal obligations. In accordance with the 1999 Settlement Agreement with the ACC, APS is continuing to accelerate the amortization of the regulatory asset for coal mine reclamation over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the Consolidated Statements of Income.

California Energy Market Issues and Refunds in the Pacific Northwest

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. APS does not anticipate material changes in its exposure and still believes, subject to the finalization of the revised proxy prices, that it will be entitled to a net refund.

The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Court of Appeals (Ninth Circuit).

Although the FERC ruling in the Pacific Northwest 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 liquidity.

On March 26, 2003, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

that allegedly violated certain provisions of the ISO tariff. APS and the FERC staff have settled this matter, and the settlement was approved by the FERC.

SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO. PG&E filed for bankruptcy protection in 2001.

We are closely monitoring developments in the California energy market and the potential impact of these developments on us and our subsidiaries. Based on our evaluations, we previously reserved $10 million before income taxes for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001. Our evaluations took into consideration our range of exposure of approximately zero to $38 million before income taxes and a review of likely recovery rates in bankruptcy situations.

In the second quarter of 2002, PG&E filed its Modified Second Amended Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization. Both plans generally indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstanding, undisputed debts. As a result of these developments, the probable range of our total exposure now is approximately zero to $27 million before income taxes, and our best estimate of the probable loss is now approximately $6 million before income taxes. Consequently, we reversed $4 million of the $10 million reserve in the second quarter of 2002. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us, our subsidiaries or the regional energy market in general.

California Energy Market Litigation 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. State of California v. British Columbia Power Exchange et al., Docket No. EL02-71-000. 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 has been dismissed by the FERC and the State of California is now appealing the matter to the Ninth Circuit Court of Appeals. In addition, the State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including APS, attempting to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit.

APS was also named in a lawsuit regarding wholesale contracts in California, which has now been moved back to state court. James Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court, Case No. 407867. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against APS and numerous other PX participants. Cal PX v. The State of California, Superior Court in and for the County of Sacramento, JCCP No. 4203. Various motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations or liquidity.

Citizens Power Service Agreement

By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised APS that it believes APS overcharged Citizens by over $50 million under a power service agreement. APS believes its charges under the agreement were fully in accordance with the terms of the agreement. In addition, in testimony filed with the ACC on March 13, 2002, Citizens acknowledged, based on its review, “if Citizens filed a complaint with the FERC, it probably would lose the central issue in the contract interpretation dispute.” APS and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, the Company and Citizens entered into a power sale agreement under which the Company will supply Citizens with future specified amounts of electricity and ancillary services through May 31, 2008. This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001.

Construction Program

Consolidated capital expenditures in 2004 are estimated to be (dollars in millions):


APS	$	426
Pinnacle West Energy		61
SunCor		83
Other (primarily APS Energy Services and Pinnacle West)		11

Total	$	581

Natural Gas Supply

APS and Pinnacle West Energy purchase the majority of their natural gas requirements for their gas-fired plants under contracts with a number of natural gas suppliers. Effective September 1, 2003, APS’ and Pinnacle West Energy’s natural gas supply is transported pursuant to a firm, contract demand service agreement with El Paso Natural Gas Company. Pursuant to the terms of a comprehensive settlement entered into in 1996, the rates charged for transportation are subject to a 10-year rate moratorium extending through December 31, 2005.

Prior to September 1, 2003, APS’ and Pinnacle West Energy’s natural gas supply was transported pursuant to a firm, full requirements transportation service agreement. On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement by requiring all firm, full requirements contract holders to convert to contract demand service agreements effective September 1, 2003. This required conversion has imposed additional

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

limitations on the former full requirements contract holders’ ability to nominate firm transportation capacity. In order for APS and Pinnacle West Energy to meet their natural gas supply and capacity requirements, they must make market purchases, which we expect to increase costs by approximately $5 million per year for natural gas supply and by approximately $14 million per year for capacity. APS and Pinnacle West Energy have sought appellate review of the FERC’s July 9 order and related issues on the grounds that the FERC decision to abrogate the full requirements contracts is arbitrary and capricious and is not supported by substantial evidence. Arizona Public Service Company and Pinnacle West Energy Corporation v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1209. This petition for review was consolidated with a petition filed by the ACC and other full requirements contract holders. Arizona Corporation Commission et al v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1206. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements.

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 consolidated financial statements, results of operations or liquidity.

12. Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The standard requires that these liabilities be recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Prior to January 1, 2003, we accrued asset retirement obligations over the life of the related asset through depreciation expense.

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term. Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets. The asset retirement obligations associated with our non-regulated assets are immaterial.

On January 1, 2003 and in accordance with SFAS No. 143, APS recorded a liability of $219 million for its asset retirement obligations, including the accretion impacts; a $67 million increase in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, APS recorded a net regulatory liability of $40 million for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. APS believes it can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. The adoption of SFAS No. 143 did not have a material impact on our net income for the year ended December 31, 2003.

APS has reclassified prior year removal costs of approximately $557 million previously included in accumulated depreciation to the liability for asset retirements and removals on our Consolidated Balance Sheets. In 2003, APS reclassified the portion of this liability for which no legal obligation for removal exists to a regulatory liability.

In accordance with SFAS No. 71, APS will continue to accrue for removal costs for its regulated assets, even if there is no legal obligation for removal. At December 31, 2003, regulatory liabilities shown on our Consolidated Balance Sheets included approximately $480 million of estimated future removal costs that are not considered legal obligations.

The following schedule shows the change in our asset retirement obligations during the twelve-month period ended December 31, 2003 (dollars in millions):


Balance at January 1, 2003	$	219
Changes attributable to:
Liabilities incurred		—
Liabilities settled		—
Accretion expense		15
Estimated cash flow revisions		—

Balance at December 31, 2003	$	234

The following schedule shows the change in our pro forma liability for the years ended December 31, 2002 and 2001, as if we had recorded an asset retirement obligation based on the guidance in SFAS No. 143 (dollars in millions):


	2002		2001
Balance at beginning of year	$	204	$	190
Accretion expense		15		14

Balance at end of year	$	219	$	204

The pro forma effects on net income for 2002 and 2001 are immaterial.

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and domestic equity securities and classifies them as available for sale. The following table shows the cost and fair value of APS’ nuclear decommissioning trust fund assets which are on the Consolidated Balance Sheets at December 31, 2003 and December 31, 2002 (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	December 31,		December 31,
	2003		2002
Trust fund assets – at cost Fixed income securities	$	124	$	113
Domestic stock		74		68

Total	$	198	$	181

Trust fund assets – at fair value Fixed income securities	$	140	$	117
Domestic stock		101		77

Total	$	241	$	194

13. Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2003 and 2002 is as follows (dollars in thousands, except per share amounts):


	2003 Quarter ended:
	March 31,		June 30,		September 30,		December 31,		Total
As originally reported:
Operating Revenues	$	552,643	$	683,302	$	847,703	$	734,204	$	2,817,852
Operating Income		69,255		132,482		198,850		81,466		482,053
Income From Continuing Operations		20,153		54,889		109,538		45,996		230,576
Net Income (a)		25,298		56,142		110,048		49,091		240,579
NAC reclassifications (see Note 22):
Operating Revenues		11,382		19,637		16,701		10,638		58,358
Operating Income		3,675		1,347		1,489		1,600		8,111
Income From Continuing Operations		2,167		783		878		945		4,773
Reclassified:
Operating Revenues		541,261		663,665		831,002		723,566		2,759,494
Operating Income		65,580		131,135		197,361		79,866		473,942
Income From Continuing Operations		17,986		54,106		108,660		45,051		225,803
Net Income (a) (d)		25,298		56,142		110,048		49,091		240,579

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2002 Quarter ended:
								December 31,
	March 31,		June 30,		September 30,			(b)(c)			Total
As originally reported:
Operating Revenues	$	483,479	$	574,554	$	767,940		$	614,315		$	2,440,288
Operating Income		118,736		155,832		212,491			13,875			500,934
Income (Loss) From Continuing Operations		53,251		68,803		100,713			(16,569	)		206,198
Net Income (Loss) (a)		53,757		75,365		100,916			(80,630	)		149,408
NAC reclassifications (see Note 22):
Operating Revenues		—		—		17,266			17,772			35,038
Operating Income (Loss)		—		—		(13,432	)		(36,377	)		(49,809	)
Income (Loss) From Continuing Operations		—		—		(8,329	)		(22,036	)		(30,365	)
Reclassified:
Operating Revenues		483,479		574,554		750,674			596,543			2,405,250
Operating Income		118,736		155,832		225,923			50,252			550,743
Income (Loss) From Continuing Operations		53,251		68,803		109,042			5,467			236,563
Net Income (Loss) (a) (d)		53,757		75,365		100,916			(80,630	)		149,408

(a) Includes income from discontinued operations at SunCor (see Note 22).

(b) Includes a $66 million after-tax charge for the cumulative effect of a change in accounting for trading activities (see Note 18).

(c) The fourth quarter of 2002 included pretax losses of $38 million related to our investment in NAC (see Note 22), a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of approximately $11 million.

(d) Includes income (loss) from NAC’s discontinued operations (see Note 22).

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Earnings per share:


	2003 Quarter ended:
	March 31,		June 30,		September 30,		December 31,
As originally reported — Basic earnings per share:
Income From Continuing Operations — EPS	$	0.22	$	0.60	$	1.20	$	0.50
Net Income – EPS		0.28		0.62		1.21		0.54
NAC reclassifications (See Note 22):
Income from Discontinued Operations – EPS		0.02		0.01		0.01		0.01
Reclassified – Basic earnings per share:
Income from Continuing Operations – EPS		0.20		0.59		1.19		0.49
Net Income – EPS		0.28		0.62		1.21		0.54
As originally reported – Diluted earnings per share:
Income From Continuing Operations – EPS		0.22		0.60		1.20		0.50
Net Income – EPS		0.28		0.61		1.20		0.54
NAC reclassifications (see Note 22):
Income from Discontinued Operations – EPS		0.02		0.01		0.01		0.01
Reclassified – Diluted earnings per share:
Income From Continued Operations – EPS		0.20		0.59		1.19		0.49
Net Income – EPS		0.28		0.61		1.20		0.54


	2002 Quarter ended:
	March 31,		June 30,		September 30,			December 31,
As originally reported — Basic earnings per share:
Income From Continuing Operations — EPS	$	0.63	$	0.81	$	1.19		$	(0.19	)
Net Income – EPS		0.63		0.89		1.19			(0.95	)
NAC reclassifications (See Note 22):
Income from Discontinued Operations – EPS		—		—		(0.10	)		(0.25	)
Reclassified – Basic earnings per share:
Income from Continuing Operations – EPS		0.63		0.81		1.29			0.06
Net Income – EPS		0.63		0.89		1.19			(0.95	)
As originally reported – Diluted earnings per share:
Income From Continuing Operations – EPS		0.63		0.81		1.19			(0.19	)
Net Income – EPS		0.63		0.89		1.19			(0.95	)
NAC reclassifications (see Note 22):
Income from Discontinued Operations – EPS		—		—		(0.10	)		(0.25	)
Reclassified – Diluted earnings per share:
Income From Continued Operations – EPS		0.63		0.81		1.29			0.06
Net Income – EPS		0.63		0.89		1.19			(0.95	)

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. Fair Value of Financial Instruments

We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2003 and 2002 due to their short maturities.

We hold investments in fixed income and domestic equity securities for purposes other than trading. The December 31, 2003 and 2002 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.

On December 31, 2003, the carrying value of our long-term debt (excluding capitalized lease obligations) was $3.32 billion, with an estimated fair value of $3.46 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $3.00 billion on December 31, 2002, with an estimated fair value of $3.21 billion. The fair value estimates are based on quoted market prices of the same or similar issues.

15. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the years ended December 31, 2003, 2002 and 2001:


	2003		2002			2001
Basic earnings per share:
Income from continuing operations	$	2.47	$	2.79		$	3.86
Income (loss) from discontinued operations		0.17		(0.26	)		—
Cumulative effect of change in accounting		—		(0.77	)		(0.18	)

Earnings per share – basic	$	2.64	$	1.76		$	3.68

Diluted earnings per share:
Income from continuing operations	$	2.47	$	2.78		$	3.85
Income (loss) from discontinued operations		0.16		(0.25	)		—
Cumulative effect of change in accounting		—		(0.77	)		(0.17	)

Earnings per share – diluted	$	2.63	$	1.76		$	3.68

Dilutive stock options increased average common shares outstanding by approximately 140,000 shares in 2003, 61,000 shares in 2002 and 212,000 shares in 2001. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 91,405,134 shares in 2003, 84,963,921 shares in 2002 and 84,930,140 shares in 2001.

Options to purchase 2,291,646 shares of common stock were outstanding at December 31, 2003 but were not included in the computation of diluted earnings per share because the options’ exercise price was 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 were 1,629,958 at December 31, 2002 and 212,562 at December 31, 2001.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. Stock-Based Compensation

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

In May 2002, shareholders approved the 2002 Long-Term Incentive Plan (2002 plan), which allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. The Company has reserved 6 million shares of common stock for 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 term of the option cannot be longer than 10 years and the option cannot be repriced during its term.

The 1994 plan and the 1985 plan each include outstanding options but no new options will be granted under either 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. Following the approval of the 2002 plan, no further grants have been made under the 1994 plan, except for awards for the annual award of up to 20,000 shares of stock to satisfy stock award obligations under employment contracts to certain executives.

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. The fair value method of accounting is the preferred method. 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. We recorded approximately $2.1 million in stock option expense before income taxes in our Consolidated Statements of Income in 2003 and approximately $0.5 million in 2002. This amount may not be reflective of the stock option expense we will record in future years because stock options typically vest over several years and additional grants are generally made each year.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” The standard amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. The standard also amends the disclosure requirements of SFAS No. 123. SFAS No. 148 is effective for fiscal years ending after December 15, 2002. We adopted the disclosure requirements in 2002. See Note 1 for our pro forma disclosures on stock-based compensation and our weighted-average assumptions used to calculate the fair value of our stock options.

Total stock-based compensation cost, including stock option cost, was $6 million in 2003, $5 million in 2002 and $3 million in 2001.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table is a summary of the status of our stock option plans as of December 31, 2003, 2002 and 2001 and changes during the years ending on those dates:


				2003					2002					2001
				Weighted					Weighted					Weighted
				Average					Average					Average
	2003			Exercise		2002			Exercise		2001			Exercise
	Shares			Price		Shares			Price		Shares			Price
Outstanding at beginning of year		2,185,129		$	39.96		1,832,725		$	39.52		1,569,171		$	37.55
Granted		621,875			32.29		603,900			38.37		444,200			42.55
Exercised		(62,366	)		26.09		(163,381	)		28.25		(162,229	)		28.53
Forfeited		(46,392	)		37.61		(88,115	)		41.54		(18,417	)		41.67

Outstanding at end of year		2,698,246			38.56		2,185,129			39.96		1,832,725			39.52

Options exercisable at year-end		1,787,622			40.35		1,155,357			39.66		926,315			37.41

Weighted average fair value of options granted during the year				$	7.37				$	6.16				$	8.84

The following table summarizes information about our stock options at December 31, 2003:


					Weighted
			Weighted		Average				Weighted
			Average		Remaining				Average
Exercise	Options		Exercise		Contract		Options		Exercise
Prices Per Share	Outstanding		Price		Life (Years)		Exercisable		Price
$18.71 – 23.39		10,584	$	19.00		0.8		10,584	$	19.00
23.39 – 28.07		48,417		27.40		2.3		48,417		27.40
28.07 – 32.75		647,400		32.23		8.7		49,625		31.50
32.75 – 37.42		220,994		34.70		5.4		220,994		34.70
37.42 – 42.10		759,333		38.86		6.7		579,854		38.95
42.10 – 46.78		1,011,518		43.96		6.1		878,148		44.17

		2,698,246						1,787,622

The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2003, 2002 and 2001:

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2003		2003 Grant			2002		2002 Grant			2001		2001 Grant
	Shares		Price			Shares		Price			Shares		Price
Restricted stock		4,000	$	32.20	(a)		6,000	$	38.84	(a)		95,450	$	42.84	(a)
Performance share awards		119,085		32.29	(b)		115,975		38.37	(b)		—		—

(a) Restricted stock priced at the average of the high and low market price for the grant date.

(b) Performance shares priced at the closing market price for the grant date.

17. 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 and related activities, and includes electricity generation, transmission and distribution;

• 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. In early 2003, we moved our marketing and trading activities to APS from Pinnacle West (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy; and

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

The amounts in our other segment include activity related to APS Energy Services non-commodity trading activities, as well as the parent company and other subsidiaries. See Note 18 for information about reclassifications related to the adoption of EITF 03-11. Financial data for the years ended December 31, 2003, 2002 and 2001 by business segments is provided as follows (dollars in millions):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Business Segments for the Year Ended December 31, 2003
				Marketing
	Regulated			and
	Electricity			Trading		Real Estate			Other		Total
Operating revenues	$	1,978		$	392	$	362		$	27	$	2,759
Purchased power and fuel costs		517			345		—			—		862
Other operating expenses		625			34		306			23		988

Operating margin		836			13		56			4		909
Depreciation and amortization		428			1		6			—		435
Interest expense		172			—		2			1		175
Other expense/(income)		(4	)		—		(25	)		—		(29	)

Pretax margin		240			12		73			3		328
Income taxes		70			3		28			1		102

Income from continuing operations		170			9		45			2		226
Income from discontinued operations – net of income taxes of $10 (see Note 22)		—			—		10			5		15

Net income	$	170		$	9	$	55		$	7	$	241

Total assets	$	8,761		$	324	$	424		$	27	$	9,536

Capital expenditures	$	686		$	9	$	72		$	—	$	767


	Business Segments for the Year Ended December 31, 2002
			Marketing
	Regulated		and
	Electricity		Trading			Real Estate			Other			Total
Operating revenues	$	1,890	$	287		$	201		$	27		$	2,405
Purchased power and fuel costs		377		155			—			—			532
Other operating expenses		659		34			185			22			900

Operating margin		854		98			16			5			973
Depreciation and amortization		416		2			4			—			422
Interest expense		141		—			2			—			143
Other expense/(income)		19		—			(7	)		7			19

Pretax margin		278		96			17			(2	)		389
Income taxes		108		38			7			(1	)		152

Income (loss) from continuing operations		170		58			10			(1	)		237
Income (loss) from discontinued operations – net of income taxes of $14 (see Note 22)		—		—			9			(31	)		(22	)
Cumulative effect of change in accounting for trading activities – net of income taxes of $43		—		(66	)		—			—			(66	)

Net income (loss)	$	170	$	(8	)	$	19		$	(32	)	$	149

Total assets	$	8,185	$	414		$	504		$	36		$	9,139

Capital expenditures	$	893	$	19		$	72		$	—		$	984

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Business Segments for the Year Ended December 31, 2001
				Marketing
	Regulated			and
	Electricity			Trading		Real Estate		Other		Total
Operating revenues	$	1,984		$	470	$	169	$	12	$	2,635
Purchased power and fuel costs		583			153		—		—		736
Other operating expenses		598			33		154		11		796

Operating margin		803			284		15		1		1,103
Depreciation and amortization		423			1		4		—		428
Interest expense		125			—		3		—		128
Other expense/(income)		4			—		3		—		7

Pretax margin		251			283		5		1		540
Income taxes		99			112		2		—		213

Income before accounting change		152			171		3		1		327
Cumulative effect of change in accounting for derivatives – net of income taxes of $10		(15	)		—		—		—		(15	)

Net income	$	137		$	171	$	3	$	1	$	312

Capital expenditures	$	1,004		$	23	$	80	$	22	$	1,129

18. Derivative and Energy Trading Accounting

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal 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. As part of our overall 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.

Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria is met, in common stock equity (as a component of other comprehensive income (loss)). We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.

In 2001, we recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income (loss)), both as

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

cumulative effects of a change in accounting for derivatives. The charge primarily resulted from electricity option contracts. The credit resulted from unrealized gains on cash flow hedges.

During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts, and on January 1, 2003 for existing contracts, with early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. Derivative instruments used for non-trading activities are accounted for in accordance with SFAS No. 133.

Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Consolidated Balance Sheets. For non-trading derivative instruments that qualify for cash flow hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Certain of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. Derivatives associated with trading activities are adjusted to fair value through income.

EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Previous guidance under EITF 98-10 permitted physically-settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the Consolidated Statements of Income and restated prior year amounts for all periods presented. Reclassification of such trading activity to a net basis of reporting resulted in reductions in both revenues and purchased power and fuel costs, but did not have any impact on our financial condition, net income or cash flows.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We adopted 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 Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provided guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We netted these book-outs, reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows. Following are the net reclassifications to our previously reported amounts (dollars in thousands):


	2003		2002		2001
Regulated Electricity	$	40,069	$	122,632	$	577,783
Marketing and Trading		184,298		39,052		181,447

Total	$	224,367	$	161,684	$	759,230

In November 2003, the FASB revised its derivative guidance in DIG Issue No. C15, “Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” Effective January 1, 2004, the new guidance changes the criteria for the normal purchases and sales scope exception for electricity contracts. We do not expect this guidance to have a material impact on our financial statements.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The provisions of SFAS No. 149 that relate to previously issued SFAS No. 133 derivatives implementation guidance should continue to be applied in accordance with the effective dates of the original implementation guidance. In general, other provisions are applied prospectively to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The impact of this standard was immaterial to our financial statements.

The changes in the fair value of our hedged positions included in the Consolidated Statements of Income for the years ended December 31, 2003 and 2002 are comprised of the following (dollars in thousands):


	2003		2002
Gains on the ineffective portion of derivatives qualifying for hedge accounting	$	8,237	$	13,682
Gains/(losses) from the change in options’ time value excluded from measurement of effectiveness		181		(2,484	)
Losses from the discontinuance of cash flow hedges		—		(8,820	)

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2003, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately five years. During the year ending December 31, 2004, we estimate that a net gain of $8 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.

Our assets and liabilities from 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 – both non-trading and trading derivative instruments of our competitive business segment.

The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2003 and 2002 (dollars in thousands):

December 31, 2003


	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated Electricity:
Mark-to-Market	$	44,079	$	5,900	$	(47,268	)	$	(3,028	)	$	(317	)
Options		—		12,101		—			—			12,101
Marketing and Trading:
Mark-to-Market		53,551		116,363		(37,023	)		(63,398	)		69,493
Emission allowances – at cost		—		4,582		(8,464	)		(16,304	)		(20,186	)

Total	$	97,630	$	138,946	$	(92,755	)	$	(82,730	)	$	61,091

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2002


	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated Electricity:
Mark-to-Market	$	41,522	$	6,971	$	(60,819	)	$	(36,678	)	$	(49,004	)
Options		—		24,651		—			—			24,651
Marketing and Trading:
Mark-to-Market		61,142		121,189		(50,510	)		(74,841	)		56,980
Emission allowances – at cost		—		38,943		—			(36,381	)		2,562

Total	$	102,664	$	191,754	$	(111,329	)	$	(147,900	)	$	35,189

Cash or collateral may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties is $1 million at December 31, 2003 and $5 million at December 31, 2002, and is included in investments and other assets on the Consolidated Balance Sheet. Collateral provided to us by counterparties is $12 million at December 31, 2003 and $22 million at December 31, 2002, and is included in other deferred credits on the Consolidated Balance Sheet.

Credit Risk

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 37% of our $237 million of risk management and trading assets as of December 31, 2003. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, 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 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. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Mark-to-Market Accounting” for a discussion of our credit valuation adjustment policy.

19. Other Income and Other Expense

The following table provides detail of other income and other expense for the years ended December 31, 2003, 2002 and 2001 (dollars in thousands):

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year Ended December 31,
	2003			2002			2001
Other income:
SunCor joint venture earnings (a)	$	24,740		$	7,355		$	3,687
Interest income		4,412			4,332			6,763
Investment gains		3,649			—			—
Environmental insurance recovery		—			—			12,349
Miscellaneous		2,762			3,223			3,617

Total other income	$	35,563		$	14,910		$	26,416

Other expense:
Non-operating costs (b)	$	(16,481	)	$	(19,430	)	$	(16,807	)
Investment losses (c)		—			(10,439	)		(5,126	)
Non-operating costs – SunCor		—			—			(7,000	)
Miscellaneous		(4,093	)		(3,786	)		(4,644	)

Total other expense	$	(20,574	)	$	(33,655	)	$	(33,577	)

(a) Primarily related to the sale at SunCor of a land interest and profit participation agreement in the fourth quarter of 2003 for $18 million. In 2002, SunCor received $2.5 million for the profit participation.

(b) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations).

(c) Primarily related to El Dorado’s investment losses in NAC prior to consolidation in the third quarter of 2002.

20. Variable Interest Entities

In 2003, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities,” as it applies to special-purpose entities. FIN No. 46R requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. In 1986, APS entered into agreements with three separate SPE 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. See Note 9 for further information about the sale leaseback transactions. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs. Certain provisions of FIN No. 46R have a future effective date. We do not expect these provisions to have a material impact on our financial statements.

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

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

such an event had occurred as of December 31, 2003, APS would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

21. Guarantees

On January 1, 2003, we adopted FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure provisions were effective for the year ended December 31, 2002. The initial recognition and measurement provisions of FIN No. 45 were effective on a prospective basis to guarantees issued or modified after December 31, 2002.

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction program, transmission service guarantees for West Phoenix Units 4 and 5 and long-term service agreement guarantees for new power plants. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products and enable El Dorado to support the activities of NAC. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s guarantees on behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2003 are as follows (dollars in millions):


	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Energy	$	86		1 to 2	$	—		—
APS Energy Services		16		1 to 2		35		2
El Dorado (NAC)		40		1 to 3		—		—

Total	$	142			$	35

At December 31, 2003, we had entered into approximately $41 million of letters of credit which support various construction agreements. These letters of credit expire in 2004 and 2005. 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. At December 31, 2003, Pinnacle West has approximately $4 million of letters of credit related to workers’ compensation expiring in 2004.

APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2003, 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. These letters of credit have expiration dates in 2004 and 2005. APS has also entered into approximately $109 million

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2005. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2004. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

We provide indemnifications relating to liabilities arising from or related to certain of our agreements. APS has provided indemnifications to 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 and therefore, the overall maximum amount of the obligation under such indemnifications 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 indemnifications is likely and therefore no related liability has been recorded.

22. Discontinued Operations

The following table provides a summary of SunCor and NAC income (loss) from discontinued operations (after income taxes) for the years ended December 31, 2003 and 2002 (dollars in millions):


	2003		2002
SunCor	$	10	$	9
NAC		5		(31	)

Total income (loss) from discontinued operations	$	15	$	(22	)

SunCor

Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on our Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Among other guidance, SFAS No. 144 prescribes accounting for discontinued operations and defines certain activities as discontinued operations. We adopted SFAS No. 144 effective January 1, 2002 and determined that activities that would have required discontinued operations reporting in 2002 and 2001 were immaterial.

In 2003, SunCor sold its water utility company, which resulted in an after-tax gain of $8 million ($14 million pretax). The amounts of the gain on the sale and operating income of the water utility company in 2003 and 2002 are classified as discontinued operations on our Consolidated Statements of Income. The amounts related to 2001 were immaterial for reclassification.

In the second quarter of 2002, SunCor sold a retail center, but maintained a continuing involvement through a management contract. In the first quarter of 2003, this management contract was canceled. As a result, the after-tax gain of $6 million ($10 million pre-tax) recorded in operations in 2002 related to this property was reclassified as discontinued operations on our Consolidated Statements of Income. The income from discontinued operations in the year ended

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2002 primarily reflects this sale. The amounts related to 2001 were immaterial for reclassification.

In the fourth quarter of 2003, SunCor sold a retail center, which resulted in an after-tax gain of $2 million ($3 million pretax). The gain on the sale and the operating income related to this property in 2003 are classified as discontinued operations on our Consolidated Statements of Income. There were no prior-year operations related to this retail center. The amounts related to 2001 were immaterial for reclassification.

The following table provides SunCor’s revenue and income before income taxes related to properties classified as discontinued operations on our Consolidated Statements of Income for the years ended December 31, 2003 and 2002 (dollars in thousands):


	2003		2002
Revenue	$	70,580	$	35,307
Income before taxes	$	16,532	$	14,827

NAC

In July 2004, we entered into an agreement to sell our investment in NAC Holding Inc. and NAC International Inc. (NAC). The transaction closed on November 18, 2004 and resulted in an pre-tax gain of $4 million, which is classified as discontinued operations in 2004. El Dorado began consolidating the operations of NAC in the third quarter of 2002. All related revenues and expenses for NAC have been reclassified to discontinued operations for the years ended December 31, 2003 and 2002 on our Consolidated Statements of Income.

The following table provides the revenue and income before taxes for El Dorado’s investment in NAC that was classified as discontinued operations for the years ended December 31, 2003 and 2002 (dollars in thousands):


	2003		2002
Revenue	$	58,358	$	35,038
Income (loss) before taxes	$	7,860	$	(50,282	)

Percentage-of-Completion – NAC

Certain NAC contract revenues are accounted for under the percentage-of-completion method. Revenues are recognized based upon total costs incurred to date compared to total costs expected to be incurred for each contract. Revisions in contract revenue and cost estimates are reflected in the accounting period when known. Provisions are made for the full amounts of anticipated losses in the periods in which they are first determined. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and income, and are recognized in the period in which revisions are determined. Profit incentives are included in revenues when their realization is reasonably assured.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs and depreciation costs. General and administrative costs are charged to expense as incurred. Due to the sale of NAC, all revenues and expenses have been reclassified to discontinued operations for the December 31, 2003 and 2002 Consolidated Statements of Income.

Assets and Liabilities Held for Sale

Due to the sale of NAC, all amounts related to assets and liabilities of discontinued operations have been reclassified to assets and liabilities held for sale on the December 31, 2003 Consolidated Balance Sheets. Due to the sales activities at SunCor as described above, the related assets and liabilities of discontinued operations were reclassified to assets and liabilities held for sale on the December 31, 2002 Consolidated Balance Sheets. The following table provides the amounts related to discontinued operations which were reclassified to assets and liabilities held for sale on the Consolidated Balance Sheets at December 31, 2003 and 2002 (dollars in thousands):


	2003		2002
Cash	$	5,867	$	—
Customer and other receivables		11,066		—
Net property, plant and equipment		5,404		—
Real estate investments – net		—		39,849
Other		728		2,490

Assets held for sale	$	23,065	$	42,339

Accounts payable	$	10,406	$	—
Customer deposits		—		13,648
Long-term debt less current maturities		800		12,454
Other		5,221		2,753

	$	16,427	$	28,855

PINNACLE WEST CAPITAL CORPORATION

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS


Column A		Column B		Column C					Column D			Column E
				Additions
		Balance at		Charged to			Charged					Balance
		beginning		cost and			to other					at end of
Description		of period		expenses			accounts		Deductions			Period
	(dollars in thousands)
Real Estate Valuation Reserves:
2003		$	1,661	$	—		$	—	$	1,661	(a)	$	—
2002			2,000		—			—		339	(a)		1,661
2001			2,000		—			—		—			2,000
Reserve for uncollectibles:
2003		$	9,607	$	3,715		$	—	$	4,099		$	9,223
2002			14,334		(21	)		—		4,706			9,607
2001			7,580		13,394			—		6,640			14,334
Reserve for contract losses:
2003		$	13,000	$	—		$	—	$	13,000		$	—
2002			—		13,000	(b)		—		—			13,000

(a) Represents pro-rata allocations for sale of land.

(b) Contract losses related to NAC (see Note 22 – Discontinued Operation – NAC).

	•		Item 8. Financial Statements and Supplementary Data; and

	•		Schedule II – Valuation and Qualifying Accounts.


Report Of Independent Registered Public Accounting Firm			8
Consolidated Statements of Income for 2003, 2002 and 2001			9
Consolidated Balance Sheets as of December 31, 2003 and 2002			10
Consolidated Statements of Cash Flows for 2003, 2002 and 2001			12
Consolidated Statements of Changes in Common Stock Equity for 2003, 2002 and 2001			13
Notes to Consolidated Financial Statements			14
Financial Statement Schedule for 2003, 2002 and 2001 Schedule II – Valuation and Qualifying Accounts for 2003, 2002 and 2001			73
Exhibit 12.1
Exhibit 23.1
Exhibit 99.1

	(a)		The majority of our unamortized regulatory assets above relates to deferred income taxes (see Note 4) and rate synchronization cost deferrals (see “Rate Synchronization Cost Deferrals” below).

	(b)		See “Reacquired Debt Costs” below.

	(a)		See Note 12 for information on Asset Retirement Obligations.

	(b)		See “ACC Financing Orders” in Note 3 for information on the “APS Loan”.

	•		contractor costs;

	•		capitalized leases;

	•		construction overhead costs (where applicable); and

	•		capitalized interest or an allowance for funds used during construction.

	•		Fossil plant – 23 years;

	•		Nuclear plant – 20 years;

	•		Other generation – 29 years;

	•		Transmission – 36 years;

	•		Distribution – 23 years; and

	•		Other – 9 years.

	•		Note 8 for amended disclosure requirements (SFAS No. 132) on retirement plans and other benefits;

	•		Note 12 for a new accounting standard (SFAS No. 143) on asset retirement obligations;

	•		Note 16 for a new accounting standard (SFAS No. 148) related to stock-based compensation;

	•		Note 18 for EITF issues (EITF 02-3 and 03-11), DIG Issue No. C15, and a new accounting standard (SFAS No. 149) related to accounting for derivatives and energy contracts;

	•		Note 20 for a new FASB interpretation (FIN No. 46R) related to VIEs;

	•		Note 21 for a new FASB interpretation (FIN No. 45) on guarantees; and

	•		Note 22 for a standard (SFAS No. 144) on accounting for the impairment or disposal of long-lived assets.

	•		Unbundled rates being charged by APS for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.

	•		There is a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor APS is prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.

	•		APS will be permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.

	•		APS’ distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. APS opened its distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

	•		Prior to the 1999 Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also states that APS will not be allowed to recover $183 million net present value (in 1999 dollars) of the $533 million. The 1999 Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As discussed below under “APS General Rate Case and Retail Rate Adjustment Mechanisms,” APS is seeking to recover amounts written off by APS as a result of the 1999 Settlement Agreement.

	•		The 1999 Settlement Agreement required APS to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that APS would be allowed to defer and later collect, beginning July 1, 2004, 67% of its costs to accomplish the required transfer of generation assets to an affiliate. However, as discussed below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing the Track A Order, an order preventing APS from transferring its generation assets. APS is seeking to recover all costs incurred by APS in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.

	•		They apply to virtually all Arizona electric utilities regulated by the ACC, including APS.

	•		Effective January 1, 2001, retail access became available to all APS retail electricity customers.

	•		Electric service providers that get CC&N’s from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.

	•		Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.

	•		The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.

	•		Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, APS received a waiver to allow transfer of its competitive electric assets and services to affiliates no later than December 31, 2002. However, as discussed below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets.

(1)		Pinnacle West Energy agreed to provide 1,700 MW in July through September of 2003 and in June through September of 2004, 2005 and 2006, by means of a unit contingent contract.

(2)		PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.

•		any debt issued by APS pursuant to the order must be unsecured;

•		the APS Loan must be callable and secured by the PWEC Dedicated Assets;

•		the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on APS debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security);
•		the 264 basis points referred to in the previous bullet point will be capitalized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum;

•		the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC;

•		any demonstrable increase in APS’ cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;

•		APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its common equity ratio below that threshold, unless otherwise waived by the ACC. The ACC will process any waiver request within sixty days, and for this sixty-day period this condition will be suspended. However, this condition, which will continue indefinitely, will not be permanently waived without an order of the ACC; and

•		certain waivers of the ACC’s affiliated interest rules previously granted to APS and its affiliates will be temporarily withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each, a “Covered Transaction”), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, except that the foregoing restrictions will not apply to the following categories of Covered Transactions:

•		Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCor’s anticipated accelerated asset sales activity during those years;

•		Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy’s (a) West Phoenix Unit 5, located in Phoenix, and (b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and

•		Covered Transactions related to the sale of 25% of the Silverhawk plant to SNWA pursuant to an agreement between SNWA and Pinnacle West Energy.

•		complying with the provisions of the 1999 Settlement Agreement;

•		incorporating significant increases in fuel and purchased power costs, including results of purchases through the ACC’s Track B procurement process;

•		recognizing changes in APS’ cost of service, cost allocation and rate design;

•		obtaining rate recognition of the PWEC Dedicated Assets;

•		recovering $234 million written off by APS as a result of the 1999 Settlement Agreement; and

•		recovering restructuring and compliance costs associated with the ACC’s Rules.

•		the ACC “litigation” staff;

•		the Arizona Residential Utility Consumers Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and

•		other approved rate case interveners.

•		decrease APS’ annual retail electricity revenues by at least $142.7 million, which would result in a rate decrease of approximately 8%, based on a 9% return on equity;

•		not allow the PWEC Dedicated Assets to be included in APS’ rate base;

•		not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement; and

•		not implement any adjustment mechanisms for fuel and purchased power.

(a)		This schedule does not reflect the timing of redemptions that may occur prior to maturity.

(b)		On August 15, 2003, APS redeemed at maturity $54 million of its First Mortgage Bonds, 7.25% Series due 2023.

(c)		On April 7, 2003, APS redeemed $33 million of its First Mortgage Bonds, 8.00% Series due 2025.

(d)		The weighted-average rate was 1.51% at December 31, 2003 and 1.94% at December 31, 2002. Changes in short-term interest rates would affect the costs associated with this debt.

(e)		On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned the proceeds to APS pursuant to a loan agreement. The bonds were issued to refinance $90 million of outstanding pollution control bonds. The bondholders were issued $90 million of first mortgage bonds (senior note mortgage bonds) as collateral.

(f)		APS currently has outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes, as well as the $90 million issue discussed in footnote (e) above. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity and redemption provisions as the senior notes. APS’ payments of principal, premium and/or interest on the senior notes satisfy its corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When APS repays all of its first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding.

(g)		The weighted average rate was 5.55% at December 31, 2003 and 5.78% at December 31, 2002. Capital leases are included in property, plant and equipment on the Consolidated Balance Sheets for both December 31, 2003 and December 31, 2002.

(h)		Multiple notes with variable interest rates based on the lenders’ prime plus 0.25%, lenders’ prime plus 1.75% and LIBOR plus 2.5%. There is also one note at a fixed rate of 7.96%.

(i)		Includes two series of notes: $300 million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of December 31, 2002. In December 2003, we repaid the $25 million note. On January 29, 2004, we entered into a fixed-for-floating interest rate swap transaction on the $300 million 6.4% note. The transaction qualifies as a fair value hedge under SFAS No. 133.

(j)		The weighted average rate was 2.85% at December 31, 2002. Interest for 2002 was based on LIBOR plus 0.98%. In June 2003, we repaid the $250 million floating note.

(k)		The weighted average rate was 1.980% at December 31, 2003. Interest for 2003 was based on LIBOR plus 0.80%.

(l)		The weighted average rate was 7.04% at December 31, 2002.

(a)		Includes income from discontinued operations at SunCor (see Note 22).

(b)		Includes a $66 million after-tax charge for the cumulative effect of a change in accounting for trading activities (see Note 18).

(c)		The fourth quarter of 2002 included pretax losses of $38 million related to our investment in NAC (see Note 22), a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of approximately $11 million.

(d)		Includes income (loss) from NAC’s discontinued operations (see Note 22).

(a)		Restricted stock priced at the average of the high and low market price for the grant date.

(b)		Performance shares priced at the closing market price for the grant date.

•		our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses and related activities, and includes electricity generation, transmission and distribution;

•		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. In early 2003, we moved our marketing and trading activities to APS from Pinnacle West (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy; and

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

•		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 – both non-trading and trading derivative instruments of our competitive business segment.

(a)		Primarily related to the sale at SunCor of a land interest and profit participation agreement in the fourth quarter of 2003 for $18 million. In 2002, SunCor received $2.5 million for the profit participation.

(b)		As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations).

(c)		Primarily related to El Dorado’s investment losses in NAC prior to consolidation in the third quarter of 2002.

(a)		Represents pro-rata allocations for sale of land.

(b)		Contract losses related to NAC (see Note 22 – Discontinued Operation – NAC).


Exhibit No.		Description
12.1		Computation of Ratio of Earnings to Fixed Charges
23.1		Consent of Deloitte & Touche LLP
99.1		Amendment to Asset Purchase Agreement


	PINNACLE WEST CAPITAL CORPORATION (Registrant)
Dated: December 20, 2004	By:	/s/Barbara M. Gomez
		Barbara M. Gomez Vice President and Treasurer