Arizona Public Service 10-Q 2004 Q1 Quarterly report

FORM 10-Q

Securities and Exchange Commission

Washington, D.C. 20549

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

For the quarterly period ended March 31, 2004

OR

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

For the transition period from                   to                   

Commission file number 1-4473

ARIZONA PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)

Arizona	86-0011170
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona	85072-3999
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (602) 250-1000

(Former name, former address and former fiscal year, if changed since last report)

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

Yes [X]   No [   ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes [   ]   No [X]

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

Number of shares of common stock, $2.50 par value,
outstanding as of May 7, 2004: 71,264,947

The Registrant meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONDENSED STATEMENTS OF INCOME
		CONDENSED BALANCE SHEETS
		CONDENSED STATEMENTS OF CASH FLOWS
		NOTES TO CONDENSED FINANCIAL STATEMENTS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Market Risks
	Item 4. Controls and Procedures
PART II – OTHER INFORMATION
	Item 5. Other Information Construction and Financing Programs
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
Index to Exhibits
EX-12.1
EX-31.1
EX-31.2
EX-32.1
EX-99.1

Glossary

ACC – Arizona Corporation Commission

ALJ – administrative law judge

APS – Arizona Public Service Company, the Company

APS Energy Services – APS Energy Services Company, Inc., a subsidiary of Pinnacle West

CC&N – Certificate of Convenience and Necessity

Citizens – Citizens Communications Company

Company – Arizona Public Service Company

CPUC – California Public Utility Commission

DIG – Derivative Implementation Group

DOE – United States Department of Energy

EITF – the FASB’s Emerging Issues Task Force

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 our $500 million loan to Pinnacle West Energy in May 2003

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

IRS – United States Internal Revenue Service

Moody’s – Moody’s Investors Service

MW – megawatt, one million watts

MWh – megawatt-hours, one million watts per hour

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

1999 Settlement Agreement – comprehensive settlement agreement approved by the ACC 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

PG&E – PG&E Corp.

Pinnacle West – Pinnacle West Capital Corporation, parent company of the Company

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

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

PX – California Power Exchange

Rules – ACC retail electric competition rules

SEC – United States Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

SNWA – Southern Nevada Water Authority

SPE – special-purpose entity

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

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

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 – the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003

VIE – variable interest entity

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

	Three Months
	Ended March 31,
	2004			2003
	(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	420,299		$	381,886
Marketing and trading segment		20,803			50,051
Total		441,102			431,937
PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment		88,592			84,100
Marketing and trading segment		25,758			44,433
Total		114,350			128,533
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS		326,752			303,404
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs		126,988			121,837
Depreciation and amortization		88,848			95,557
Income taxes		17,362			10,966
Other taxes		27,580			28,214
Total		260,778			256,574
OPERATING INCOME		65,974			46,830
OTHER INCOME (DEDUCTIONS):
Income taxes		(2,469	)		504
Allowance for equity funds used during construction		2,002			—
Other income (Note 16)		11,235			1,789
Other expense (Note 16)		(4,904	)		(2,842	)
Total		5,864			(549	)
INTEREST DEDUCTIONS:
Interest on long-term debt		35,646			32,968
Interest on short-term borrowings		2,501			1,259
Debt discount, premium and expense		1,195			720
Capitalized interest		(857	)		(4,599	)
Total		38,485			30,348
NET INCOME	$	33,353		$	15,933

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

ASSETS

	March 31,			December 31,
	2004			2003
	(Dollars in Thousands)
UTILITY PLANT:
Electric plant in service and held for future use	$	8,869,575		$	8,826,033
Less accumulated depreciation and amortization		3,113,369			3,089,645
Total		5,756,206			5,736,388
Construction work in progress		159,620			187,478
Intangible assets, net of accumulated amortization		106,634			94,181
Nuclear fuel, net of accumulated amortization		57,959			52,011
Utility plant — net		6,080,419			6,070,058
INVESTMENTS AND OTHER ASSETS:
Notes receivable from associated companies (Notes 5 and 18)		498,021			497,865
Decommissioning trust accounts		246,002			240,645
Assets from risk management and trading activities — long-term (Note 10)		25,459			18,001
Other assets		66,514			64,119
Total investments and other assets		835,996			820,630
CURRENT ASSETS:
Cash and cash equivalents		—			112,002
Accounts receivable:
Service customers		145,584			190,884
Other (Note 18)		77,475			67,540
Allowance for doubtful accounts		(3,258	)		(3,743	)
Accrued utility revenues		73,612			71,501
Materials and supplies, at average cost		80,907			80,682
Fossil fuel, at average cost		24,378			28,360
Assets from risk management and trading activities (Note 10)		88,782			52,448
Other		5,412			6,969
Total current assets		492,892			606,643
DEFERRED DEBITS:
Regulatory assets		161,543			164,804
Unamortized debt issue costs		24,067			19,797
Other		73,527			73,056
Total deferred debits		259,137			257,657
TOTAL ASSETS	$	7,668,444		$	7,754,988

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

CAPITALIZATION AND LIABILITIES

	March 31,			December 31,
	2004			2003
	(Dollars in Thousands)
CAPITALIZATION:
Common stock	$	178,162		$	178,162
Additional paid-in capital		1,246,804			1,246,804
Retained earnings		821,422			830,569
Accumulated other comprehensive income/(loss):
Minimum pension liability adjustment		(57,158	)		(57,158	)
Derivative instruments		22,438			5,253
Common stock equity		2,211,668			2,203,630
Long-term debt less current maturities		1,978,301			2,135,606
Total capitalization		4,189,969			4,339,236
CURRENT LIABILITIES:
Commercial paper		25,200			—
Current maturities of long-term debt		439,067			487,067
Accounts payable		121,153			131,383
Accrued taxes		139,583			90,474
Accrued interest		36,752			42,702
Customer deposits		46,867			45,481
Deferred income taxes		631			631
Liabilities from risk management and trading activities (Note 10)		66,600			58,138
Other		69,825			60,008
Total current liabilities		945,678			915,884
DEFERRED CREDITS AND OTHER:
Deferred income taxes		1,262,304			1,248,397
Liabilities from risk management and trading activities — long-term (Note 10)		13,290			4,502
Regulatory liabilities		512,190			510,423
Unamortized gain — sale of utility plant		53,765			54,909
Customer advances for construction		55,853			52,783
Pension liability		173,713			160,639
Liability for asset retirement (Note 13)		238,566			234,440
Other		223,116			233,775
Total deferred credits and other		2,532,797			2,499,868
COMMITMENTS AND CONTINGENCIES (Notes 5, 12 & 13)
TOTAL LIABILITIES AND EQUITY	$	7,668,444		$	7,754,988

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months
	Ended March 31,
	2004			2003
	(Dollars in Thousands)
Cash Flows from Operating Activities:
Net Income	$	33,353		$	15,933
Items not requiring cash:
Depreciation and amortization		88,848			95,557
Nuclear fuel amortization		7,599			7,726
Allowance for equity funds used during construction		(2,002	)		—
Deferred income taxes		2,714			(7,706	)
Change in mark-to-market valuations		(19,582	)		(19,924	)
Changes in certain current assets and liabilities:
Accounts receivable		34,880			67,855
Accrued utility revenues		(2,111	)		15,609
Materials, supplies and fossil fuel		3,757			(3,202	)
Other current assets		1,557			1,420
Accounts payable		(6,333	)		(1,558	)
Accrued taxes		49,109			44,337
Accrued interest		(5,950	)		(13,119	)
Other current liabilities		11,203			18,534
Increase in regulatory assets		(847	)		(2,152	)
Change in risk management trading — assets		2,562			3,881
Change in risk management trading — liabilities		18,856			—
Change in customer advances		3,070			(1,334	)
Change in pension liability		13,074			13,532
Change in other long-term assets		(5,383	)		(7,435	)
Change in other long-term liabilities		(11,562	)		(1,698	)
Net cash flow provided by operating activities		216,812			226,256
Cash Flows from Investing Activities:
Trust fund for bond redemption		—			(87,225	)
Capital expenditures		(99,684	)		(110,264	)
Capitalized interest		(857	)		(4,599	)
Loans to associated companies		(156	)		—
Other		(5,256	)		8,238
Net cash flow used for investing activities		(105,953	)		(193,850	)
Cash Flows from Financing Activities:
Issuance of long-term debt		179,000			—
Repayment and reacquisition of long-term debt		(384,561	)		(672	)
Short-term borrowings — net		25,200			—
Dividends paid on common stock		(42,500	)		(42,500	)
Net cash flow used for financing activities		(222,861	)		(43,172	)
Net decrease in cash and cash equivalents		(112,002	)		(10,766	)
Cash and cash equivalents at beginning of period		112,002			42,549
Cash and cash equivalents at end of period	$	—		$	31,783
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest)	$	42,228		$	42,747
Income taxes	$	—		$	—

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
(UNAUDITED)

1. Our unaudited condensed financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature. We suggest that these condensed financial statements and notes to condensed financial statements be read along with the financial statements and notes to financial statements included in our 2003 Form 10-K. 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.

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

3. We are a wholly-owned subsidiary of Pinnacle West.

4. On February 15, 2004, $125 million of our 5.875% Notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of our First Mortgage Bonds, 6.625% Series due 2004 were redeemed at maturity. We used cash from operations and short-term debt to redeem the maturing debt.

     On March 31, 2004, the Navajo County, Arizona Pollution Control Corporation issued $166 million of variable interest rate pollution control bonds, 2004 Series A-E, due 2034. The bonds were issued to refinance $166 million of outstanding pollution control bonds. These bonds are payable solely from revenues obtained from us pursuant to a loan agreement between us and the Navajo County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Balance Sheets.

     Also on March 31, 2004, Coconino County, Arizona Pollution Control Corporation issued $13 million of variable interest rate pollution control bonds, 2004 Series A, due 2034. The bonds were issued to refinance $13 million of outstanding pollution control bonds. These bonds are payable solely from revenues obtained from us pursuant to a loan agreement between us and Coconino County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Balance Sheets.

     At March 31, 2004, we had $387 million of pollution control bonds under which interest rates are reset on a daily or annual basis. The holders of these bonds have the right to cause us to purchase their bonds on the applicable reset date if the bonds are not remarketed; therefore, $337 million of such bonds are classified as current maturities of long-term debt. The remaining $50 million is classified as long-term as we have the intent and ability, demonstrated by credit agreements in place that extend for more than one year, to refinance any bonds that we are required to purchase.

     The following is a list of payments due on total long-term debt and capitalized lease requirements as of March 31, 2004:

• $339 million in 2004;

• $402 million in 2005;

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• $86 million in 2006;

• $1 million in 2007;

• $1 million in 2008; and

• $1,597 million thereafter.

5. Regulatory Matters

Electric Industry Restructuring

State

     Overview

     On June 27, 2003, we filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in our annual retail electricity revenues, to become effective July 1, 2004. The major components of the request are described under “General Rate Case and Retail Rate Adjustment Mechanisms” below.

1999 Settlement Agreement

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

• We have 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

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	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 us 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 we are 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 our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.
•	We 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 “General Rate Case and Retail Rate Adjustment Mechanisms” below.
•	Our 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. We opened our 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 our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory.
•	Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in

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1999 dollars). The 1999 Settlement Agreement also states that we will not be allowed to recover $183 million net present value (in 1999 dollars) ($234 million pre-tax) of the $533 million. The 1999 Settlement Agreement provides that we 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 “General Rate Case and Retail Rate Adjustment Mechanisms,” we are seeking to recover amounts written off by us as a result of the 1999 Settlement Agreement.

•

The 1999 Settlement Agreement required us to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) our competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that we would be allowed to defer and later collect, beginning July 1, 2004, 67% of our 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 us from transferring our generation assets. We are seeking to recover all costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “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 us.

• Effective January 1, 2001, retail access became available to all our 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

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or affiliates. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our 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 us to transfer our 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, we 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 our 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, we are, 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. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. There can be no assurance that we would be able to fully recover the costs of this power. See “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 us to transfer our generation assets either to an unrelated third party or to a separate corporate affiliate; and

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

     On November 15, 2002, we 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, we and the ACC staff agreed to principles for resolving certain issues raised by us in our appeals of the Track A Order. The major provisions of the principles include, among other things, the following:

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

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

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

• the appropriate treatment of costs incurred by us 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 our request to provide $500 million of financing or credit support to Pinnacle West Energy or the Company, with appropriate conditions, our 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, our appeals of the Track A Order are limited to the issues described in the preceding bullet points.

     On August 27, 2003, we, 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 us to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003, we were required to solicit competitive bids for about 2,500 MW of

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capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements. 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 our 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 us and any affiliate of ours participating in the competitive solicitation, requires that we treat bidders in a non-discriminatory manner and requires us to file a protocol regarding short-term and emergency procurements. The order permits the provision by us 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 us 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 us to prepare a report evaluating environmental issues relating to the procurement, and a series of workshops on environmental risk management will be commenced thereafter.

     We issued requests for proposals in March 2003 and, by May 6, 2003, we entered into contracts to meet all or a portion of our 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.
(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 Order

     On April 4, 2003, the ACC issued the Financing Order authorizing us 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 us pursuant to the order must be unsecured;

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

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• the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on our 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 our cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;

• We must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce our 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 us and our 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;

• 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.

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     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, we submitted our 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, we 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.

     General Rate Case and Retail Rate Adjustment Mechanisms

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

     Major Components of the RequestThe 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 our cost of service, cost allocation and rate design;

• obtaining rate recognition of the PWEC Dedicated Assets;

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

• recovering restructuring and compliance costs associated with the Rules.

     Requested Rate IncreaseThe 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 YearThe filing is based on an adjusted historical test year ended December 31, 2002.

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     Cost of CapitalThe 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 BaseThe 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 us 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-OffThe request includes recovery, over a fifteen year period, of the write-off of $234 million pretax of regulatory assets by us as a result of the 1999 Settlement Agreement. See “1999 Settlement Agreement” above.

     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 us 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 us 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 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.

     TestimonyOn 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

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• other approved rate case interveners.

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

• decrease our 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 our rate base;

• not allow us to recover any of the $234 million pretax 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 our rate case requests are supported by, among other things, our demonstrated need for the PWEC Dedicated Assets; our need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in our 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 we and our affiliates had violated the “spirit, if not the letter” of the Rules, the Code of Conduct and the 1999 Settlement Agreement.

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

• decrease our 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 our rate base;

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

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

     We believe that our rate request is necessary to ensure our continued ability to reliably serve one of the fastest growing regions in the country and view any ultimate decision that would deny recovery of the Company’s investment in the PWEC Dedicated Assets as constituting a regulatory “taking.” We will vigorously oppose the

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recommendations of the ACC staff, RUCO, and other parties offering similar recommendations.

     Estimated TimelineWe have asked the ACC to approve the requested rate increase by July 1, 2004. Hearings on the rate case were previously scheduled to begin on May 25, 2004. On April 15, 2004, the ACC ALJ issued a procedural order revising the schedule and timing of the rate case. On April 29, 2004, the ACC ALJ issued an order staying the existing procedural schedule for 30 days while the parties discuss settlement. The ALJ scheduled a procedural conference on May 26, 2004, to determine whether the stay should be extended or a new procedural schedule and hearing date established. Based on these two recent procedural orders, hearings should begin no earlier than early August 2004.

     Request for Proposals

     In early December 2003, we issued a request for proposals (“RFP”) for long-term power supply resources, and on January 8, 2004, an ACC ALJ issued an order requiring, among other things, that we file a summary of the proposals with the ACC. On January 27, 2004, we filed a summary of the proposals with the ACC. We are 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 our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our 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.

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6. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefits for the employees of Pinnacle West and their subsidiaries. In 2003 and 2004, we represented 89% of the total cost of the 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 obligations 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 Pinnacle West plans’ benefit costs for the three months ended March 31, 2004 and 2003. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or amounts capitalized as overhead construction (dollars in thousands):

	Pension Benefits						Other Benefits
	2004			2003			2004			2003
Service cost-benefits earned during the period	$	10,603		$	8,664		$	4,779		$	3,780
Interest cost on benefit obligation		20,927			17,701			7,825			7,191
Expected return on plan assets		(20,376	)		(14,962	)		(5,622	)		(4,473	)
Amortization of:
Transition (asset)/obligation		(804	)		(743	)		703			716
Prior service cost/(credit)		629			552			(23	)		(29	)
Net actuarial loss		4,246			4,171			2,764			2,315
Net periodic benefit cost	$	15,225		$	15,383		$	10,426		$	9,500
Our share of costs charged to expense	$	5,793		$	5,854		$	3,968		$	3,615

Contributions

     The Pension Stability Act was signed into law on April 10, 2004. Under this new legislation, Pinnacle West’s required pension contribution in 2004 is $35 million. Pinnacle West is currently evaluating whether any additional contributions will be made to our pension plans in 2004. We have not yet made any 2004 contributions to our pension plans or other postretirement benefit plans.

7. Business Segments

     We have two principal business segments (determined by services and the regulatory environment):

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

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading.

     Financial data for our business segments follows (dollars in millions):

	Three Months Ended
	March 31,
	2004			2003
Operating Revenues:
Regulated electricity	$	420		$	382
Marketing and trading		21			50
Total	$	441		$	432
Net Income (Loss):
Regulated electricity	$	38		$	14
Marketing and trading		(5	)		2
Total	$	33		$	16

	As of		As of
	March 31, 2004		December 31, 2003
Assets:
Regulated electricity	$	7,649	$	7,747
Marketing and trading		19		8
Total	$	7,668	$	7,755

8. Accounting Matters

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

• Note 9 for FASB interpretation (FIN No. 46R) related to variable interest entities;

• Note 10 for EITF issue (EITF 03-11) and DIG Issue No. C15 related to accounting for derivatives and energy trading contracts; and

• Note 13 for accounting standard (SFAS No. 143) on asset retirement obligations.

9. 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

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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, we 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. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs.

     We are exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that we do 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), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2004, we would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

     In the first quarter of 2004, we adopted FIN No. 46R for all other contractual arrangements. There was no impact to our financial statements.

10. Derivative Instruments and Energy Trading Activities

     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.

     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 that are not held for trading purposes should be reported on a net or gross basis. The EITF concludes that 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 settled by netting against other contracts to sell energy. This netting process is referred to as “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. These book-outs reduced both revenues and purchased power and fuel costs in 2003 but did not impact our financial condition, net income or cash flows.

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     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. This guidance did not have a material impact on our financial statements.

Cash Flow Hedges

     The changes in the fair value of our hedged positions included in the Condensed Statements of Income for the three months ended March 31, 2004 and 2003 were comprised of the following (dollars in thousands):

	Three Months Ended
	March 31,
	2004		2003
Gains on the ineffective portion of derivatives qualifying for hedge accounting	$	1,411	$	1,564
Gains from the change in options’ time value excluded from measurement of effectiveness		80		—
Gain from the discontinuance of cash flow hedges		575		—

     As of March 31, 2004, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions was approximately three years. During the twelve months ending March 31, 2005, we estimate that a net gain of $25 million before income taxes will be reclassified from accumulated other comprehensive income 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 our 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 March 31, 2004 and December 31, 2003 (dollars in thousands):

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March 31, 2004

	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated
Electricity:
Mark-to-market	$	70,539	$	15,268	$	(38,305	)	$	(872	)	$	46,630
Options at cost and margin account		—		9,539		(18,856	)		—			(9,317	)
Marketing and Trading:
Mark-to-market		18,243		652		(9,439	)		(12,418	)		(2,962	)
Total	$	88,782	$	25,459	$	(66,600	)	$	(13,290	)	$	34,351

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		8,369		—		(10,870	)		(1,474	)		(3,975	)
Total	$	52,448	$	18,001	$	(58,138	)	$	(4,502	)	$	7,809

     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. No collateral was provided to counterparties at March 31, 2004 and December 31, 2003. Collateral provided to us by counterparties was $12 million at March 31, 2004 and $12 million at December 31, 2003, and is included in other deferred credits on the Condensed Balance Sheets.

     Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties. Our risk management process assesses and monitors the financial exposure of our counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on 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.

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11. Comprehensive Income

     Components of comprehensive income for the three months ended March 31, 2004 and 2003, are as follows (dollars in thousands):

	Three Months Ended March 31,
	2004			2003
Net income	$	33,353		$	15,933
Other comprehensive income:
Minimum pension liability adjustment, net of tax		—			(112	)
Unrealized gain on derivative instruments, net of tax (a)		18,315			8,653
Reclassification of realized gain to income, net of tax (b)		(1,130	)		(1,921	)
Total other comprehensive income		17,185			6,620
Comprehensive income	$	50,538		$	22,553

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

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station — Spent 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 us (on behalf of ourself 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.

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. We were a seller and a purchaser in the California markets at issue, and to the extent that refunds are

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ordered, we 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. We do not anticipate material changes in our exposure and still believe, subject to the finalization of the revised proxy prices, that we 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 us, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. After reviewing the matter, along with the data supplied by us, the FERC staff moved to dismiss the claims against us and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

     California Energy Market LitigationOn 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 us, attempting to expand those matters to such other participants. We have not yet filed a responsive pleading in the matter, but we believe the claims by Reliant and Duke as they relate to us are without merit.

     We were also named in a lawsuit regarding wholesale contracts in California, which, after moving to state court, has been removed to the federal court for a second time.James Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court, Case No. 407867, U.S. District Court (Northern District) C-04-0519 SBA. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California unfair competition laws. The PX has filed a

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lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against us 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.

Natural Gas Supply

     We and Pinnacle West Energy purchase the majority of our natural gas requirements for our gas-fired plants under contracts with a number of natural gas suppliers. Pursuant to the terms of a comprehensive settlement entered into in 1996, with El Paso Natural Gas Company, the rates charged for transportation are subject to a rate moratorium through December 31, 2005.

     On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement. In order for us and Pinnacle West Energy to meet our natural gas supply and capacity requirements, we expect costs to increase by approximately $5 million per year for natural gas supply and by approximately $14 million per year for capacity. We 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.

Environmental Matters — Superfund

     On September 3, 2003, the EPA advised us and Pinnacle West that the EPA considers us and Pinnacle West to be a “potentially responsible party” in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. We have facilities that are within this superfund site. Liability under Superfund is strict, joint and several. Pinnacle West and we are currently negotiating with the EPA regarding the performance of remedial investigation activities of our facilities. Because the ultimate remediation requirements are not yet finalized, we cannot currently estimate the expenditures which may be required.

13. 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. On January 1, 2003, we recorded a liability of $219 million for our asset retirement obligations, including the accretion impacts; a $67 million increase in 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, we recorded a net regulatory liability of $40 million for the asset retirement obligations related to our 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. We believe we 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 three months ended March 31, 2004 and March 31, 2003.

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14. 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. The Price Anderson Act currently limits the combined public liability of nuclear reactor owners to $10.76 billion for claims that could arise from a single nuclear incident. The Palo Verde participants purchase the maximum available commercial insurance of $300 million. The balance of the $10.46 billion is provided by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we 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 our interest in the three Palo Verde units, our 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. We have 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 property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). We are subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The estimated maximum amount of retrospective assessments we could incur under the current NEIL policies totals $16 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

15. Stock-Based Compensation

     Pinnacle West offers stock-based compensation plans for our officers and key employees. 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.” In accordance with the transition requirements of SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” 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 and stock compensation expense for the three months ended March 31, 2004 and 2003 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 March 31, 2004 (dollars in thousands):

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	Three Months
	Ended March 31,
	2004		2003
Net income, as reported	$	33,353	$	15,933
Add: Stock compensation expense included in reported net income (net of tax)		224		96
Deduct: Total stock compensation expense determined under fair value method (net of tax)		429		285
Pro forma net income	$	33,148	$	15,744

16. Other Income and Other Expense

     The following table provides detail of other income and other expense for the three months ended March 31, 2004 and 2003 (dollars in thousands):

	Three Months
	Ended March 31,
	2004			2003
Other income:
Interest income	$	5,038		$	433
Asset sales		3,651			281
Investment gains – net		2,047			904
Miscellaneous		499			171
Total other income	$	11,235		$	1,789
Other expense:
Non-operating costs(a)	$	(2,232	)	$	(1,957	)
Asset sales		(2,139	)		(650	)
Miscellaneous		(533	)		(235	)
Total other expense	$	(4,904	)	$	(2,842	)

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

17. Guarantees

     We have entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2004, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. See Note 4 for more information. 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. We have also entered into approximately $107 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2005. Additionally, we have approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2004. We intend to provide from either

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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. We have 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 indemnifications 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.

18. Related Party Transactions

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

	Three Months Ended
	March 31,
	2004		2003
Electric operating revenues:
Pinnacle West – marketing and trading	$	4	$	1
Pinnacle West Energy		1		—
Total	$	5	$	1
Purchased power and fuel costs:
Pinnacle West Energy (a)	$	10	$	14
Total	$	10	$	14
Other:
Pinnacle West Energy interest income (b)	$	5	$	—
Total	$	5	$	—

	As of			As of
	March 31,			December 31,
	2004			2003
Net intercompany receivables/(payables):
Pinnacle West Energy (b)	$	513		$	463
Pinnacle West – marketing and trading		20			16
APS Energy Services		13			10
Pinnacle West		(5	)		(8	)
Total	$	541		$	481

(a) Includes a credit of $6 million related to mark-to-market on an intercompany contract for the three months ended March 31, 2003.

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(b) Related to $500 million of debt we loaned to Pinnacle West Energy pursuant to the Financing Order (see “ACC Financing Order” in Note 5).

     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. The Company purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in Issue No. 02-3.” See Note 10 for more information related to EITF 03-11. Intercompany receivables primarily include the amounts related to the loan we made to Pinnacle West Energy and intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

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ARIZONA PUBLICE SERVICE COMPANY

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Introduction

     We suggest this section be read along with the 2003 Form 10-K. Throughout this Item, we refer to specific “Notes” in the Notes to Condensed Financial Statements in this report. These Notes add further details to the discussion.

Overview

     We are a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona. Through our marketing and trading division, we generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading division also sells, in the wholesale market, Pinnacle West Energy’s generation output that is not needed for our Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. Our service territory growth is about three times the national average and remains a fundamental driver of our revenues and earnings. We do not distribute any products. Pinnacle West owns all of our outstanding common stock.

     Pinnacle West Energy is our unregulated generation affiliate. Pinnacle West formed Pinnacle West Energy in 1999 as a result of the ACC’s requirement that we transfer all of our competitive assets and services to an affiliate or to a third party by the end of 2002. We planned to transfer our generation assets to Pinnacle West Energy. Additionally, Pinnacle West Energy constructed several power plants to meet growing energy needs (1790 MW in Arizona and 570 MW in Nevada). In September 2002, the ACC issued the Track A Order, which prohibited us from transferring our generation assets to Pinnacle West Energy. As a result of the Track A Order, we are seeking to transfer the plants built by Pinnacle West Energy in Arizona to us to unite the Arizona generation under one common owner, as originally intended.

     The marketing and trading division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. We currently expect contributions from our trading activities to be negligible for 2004 and approximately $10 million (pretax) annually thereafter.

     We believe our general rate case pending before the ACC is the key issue affecting our outlook. See Note 5 in Item 1 for a detailed discussion of this rate case. Other factors affecting our past and future financial results include customer growth; purchased power and fuel costs; operations and maintenance expenses, including those relating to plant outages; weather variations; and depreciation and amortization expenses, which are affected by net additions to existing utility plant and other property and changes in regulatory asset amortization.

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BUSINESS SEGMENTS

     We have two principal business segments (determined by 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; and

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading.

     The following table summarizes net income by business segment for the three months ended March 31, 2004 and the comparable prior year period (dollars in millions):

	Three Months Ended
	March 31,
	2004			2003
Regulated electricity	$	38		$	14
Marketing and trading		(5	)		2
Net income	$	33		$	16

Results of Operations

     General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. In addition, we have reclassified certain prior period amounts to conform to our current period presentation.

     Operating Results – Three-month period ended March 31, 2004 compared with the three-month period ended March 31, 2003

     Our net income for the three-months ended March 31, 2004 was $33 million compared with $16 million for the prior year period. The $17 million increase in the period-to-period comparison reflects the following changes in earnings by segment:

• Regulated Electricity Segment – Net income increased approximately $24 million primarily due to lower purchased power and fuel costs resulting from lower hedged gas and power prices; customer growth and favorable weather; and lower regulatory asset amortization. These positive factors were partially offset by higher costs related to higher replacement power costs from plant outages due to higher market prices and more unplanned outages; higher interest expense primarily due to higher debt balances and lower capitalized interest; a retail electricity price reduction; higher depreciation expense

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related to increased delivery and other assets; and higher operations and maintenance costs related to higher customer service costs.

• Marketing and Trading Segment – Net income decreased approximately $7 million primarily due to lower unit margins on wholesale sales and lower sales volumes on generation sales other than Native Load.

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

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Decreased purchased power and fuel costs due to lower hedged gas and power prices	$	25		$	15
Higher retail sales volumes due to customer growth, excluding weather effects		13			8
Effects of weather on retail sales		11			7
Higher replacement power costs from plant outages due to higher market prices and more unplanned outages		(9	)		(5	)
Retail electricity price reduction effective July 1, 2003		(6	)		(4	)
Miscellaneous factors, net		(1	)		(1	)
Net increase in regulated electricity segment gross margin		33			20
Marketing and trading segment gross margin:
Higher mark-to-market gains for future delivery due to higher forward prices for wholesale electricity		1			1
Lower realized margins on wholesale sales primarily due to lower unit margins		(8	)		(5	)
Decrease in generation sales other than Native Load due to lower sales volumes		(3	)		(2	)
Net decrease in marketing and trading segment gross margin		(10	)		(6	)
Net increase in regulated electricity and marketing and trading segments’ gross margins		23			14
Higher operations and maintenance expense primarily due to higher customer service costs		(5	)		(3	)
Higher interest expense primarily due to higher debt balances and lower capitalized interest		(6	)		(3	)
Depreciation and amortization decreases (increases):
Increased delivery and other assets		(6	)		(4	)
Decreased regulatory asset amortization		13			8
Higher other income net of other expense primarily due to interest income and other		7			4
Miscellaneous items, net		1			1
Net increase in income	$	27		$	17

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Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $38 million higher for the three-months ended March 31, 2004 compared with the prior year period, primarily as a result of:

• a $23 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

• an $18 million increase in retail revenues related to weather;

• a $6 million decrease in retail revenues related to a reduction in retail electricity prices; and

• a $3 million net increase due to other miscellaneous factors.

Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $29 million lower for the three-months ended March 31, 2004 compared with the prior year period, primarily as a result of:

• a $33 million decrease from generation sales other than Native Load primarily due to lower prices and sales volumes;

• $2 million in higher mark-to-market gains for future-period deliveries primarily as a result of higher forward prices for wholesale electricity; and

• $2 million of higher realized wholesale revenues primarily due to higher volumes.

Liquidity and Capital Resources

       Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for the three months ended March 31, 2004 and estimated capital expenditures for the next three years (dollars in millions):

	Three Months
	Ended March 31,		Estimated
	2004		2004		2005		2006
Delivery	$	72	$	309	$	390	$	453
Generation (a)		26		107		160		200
Other (b)		—		20		30		18
Total	$	98	$	436	$	580	$	671

(a)	As discussed in Note 5 under “General Rate Case and Retail Rate Adjustment Mechanisms,” as part of our general rate case, we have requested rate base treatment of the PWEC Dedicated Assets. Pinnacle West Energy actual capital expenditures related to PWEC Dedicated Assets are estimated to be $15 million in 2004, $14 million in 2005 and $14 million in 2006.
(b)	Primarily information systems and facilities projects.

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     Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility cost. Examples of the types of projects included in the forecast include T&D lines and substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth. We will begin major projects each year for the next several years, and expect to spend about $200 million on major transmission projects during the 2004 to 2006 time frame. These amounts are included in “Delivery” in the table above. Completion of these projects will stretch from 2005 through at least 2008.

     Generation capital expenditures are comprised of various improvements to our existing fossil and nuclear plants and the replacement of Palo Verde steam generators. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $30 million annually for 2004 to 2006.

     Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall outage of 2003 at a cost of approximately $70 million. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. These generators will be installed in Unit 1 (scheduled completion in 2005) and Unit 3 (scheduled completion in 2007). Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million, which will be spent through 2008. In 2004 through 2006, approximately $90 million of the Unit 1 and Unit 3 costs are included in the generation capital expenditures table above and will be funded with internally-generated cash or external financings.

     Contractual Obligations

     Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2003 Form 10-K with the following exceptions that occurred in the three months ended March 31, 2004:

• Our purchased power and fuel commitments increased approximately $95 million with respect to 2004 repayment obligations.

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

     Off-Balance Sheet Arrangements

     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

35

equity investors that do not provide sufficient financial resources for the entity to support its activities.

     In 1986, we 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. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs.

     We are exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that we do 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), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2004, we would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

     In the first quarter of 2004, we adopted FIN No. 46R for all other contractual arrangements. There was no impact to our financial statements.

     Guarantees and Letters of Credit

     We have entered into various agreements that require letters of credit for financial assurance purposes. We generally provide indemnifications relating to liabilities arising from or related to certain of our agreements, except with limited exceptions depending on the particular agreement. We have not recorded any liability on our Condensed Balance Sheets with respect to these obligations. See Note 17 for additional information regarding guarantees and letters of credit.

     Credit Ratings

     The ratings of our securities as of May 5, 2004 are shown below and are considered to be “investment-grade” ratings. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of our securities and serve to increase those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).

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	Moody’s	Standard & Poor’s
Senior unsecured	Baa1	BBB
Secured lease obligation bonds	Baa2	BBB
Commercial paper	P-2	A-2
Outlook	Negative	Negative

     We no longer have any senior secured debt. See “Capital Needs and Resources” for a discussion of the termination of the mortgage and deed of trust.

     Debt Provisions

     Our debt covenants related to our respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. We comply with such covenants and we anticipate we will continue to meet these and other significant covenant requirements. The ratio of debt to total capitalization cannot exceed 65%. At March 31, 2004, our ratio was approximately 51%. The interest coverage is approximately 4 times for our bank financing agreements. 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.

     Our financing agreements do not contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, we may be subject to increased interest costs under certain financing agreements.

     All of our bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if we were to default under other agreements. Our credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in financial condition or financial prospects.

     See Note 4 for further discussions.

     Capital Needs and Resources

     Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See Note 5 for discussion of the $500 million financing arrangement between us and Pinnacle West Energy approved by the ACC in 2003.

     We pay for our capital requirements with cash from operations and, to the extent necessary, external financings. We have historically paid for our dividends to Pinnacle West with cash from operations. As discussed in Note 5, we must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce our common equity below that threshold. As defined in the Financing Order, common equity ratio is common equity divided by common equity plus long-term debt,

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including current maturities of long-term debt. At March 31, 2004 our common equity ratio was approximately 48%.

     On February 15, 2004, $125 million of our 5.875% Notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of our First Mortgage Bonds, 6.625% Series due 2004 were redeemed at maturity. We used cash from operations and short-term debt to redeem the maturing debt.

     On March 31, 2004, the Navajo County, Arizona Pollution Control Corporation issued $166 million of variable interest rate pollution control bonds, 2004 Series A-E, due 2034. The bonds were issued to refinance $166 million of outstanding pollution control bonds. These bonds are payable solely from revenues obtained from us pursuant to a loan agreement between us and the Navajo County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Balance Sheets.

     Also on March 31, 2004, Coconino County, Arizona Pollution Control Corporation issued $13 million of variable interest rate pollution control bonds, 2004 Series A, due 2034. The bonds were issued to refinance $13 million of outstanding pollution control bonds. These bonds are payable solely from revenues obtained from us pursuant to a loan agreement between us and Coconino County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Balance Sheets.

     We have elected to retire all first mortgage bonds issued by us under our 1946 mortgage and deed of trust, including the first mortgage bonds securing our senior notes. During the second quarter 2004, we expect to complete all steps necessary to terminate our existing mortgage and deed of trust and, as a result, we will not be able to issue any additional first mortgage bonds under that mortgage.

     Although provisions in our articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements.

     We participate in a pension plan sponsored by Pinnacle West. Pinnacle West contributes at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. We fund our share of the pension contribution. We represent approximately 89% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. The Pension Stability Act was signed into law on April 10, 2004. As a result of this new legislation, Pinnacle West’s required pension contribution in 2004 is $35 million. Pinnacle West is currently evaluating whether any additional contributions will be made to the pension plans in 2004. Pinnacle West has not yet made any 2004 contributions to the pension plans or other postretirement benefit plans.

     Critical Accounting Policies

     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and

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during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting and the determination of the appropriate accounting for our pension and other postretirement benefits, derivatives and mark-to-market accounting. There have been no changes to our critical accounting policies since our 2003 Form 10-K except for the impact of recent accounting pronouncements as discussed in Note 8. See “Critical Accounting Policies” in Item 7 of the 2003 Form 10-K for further details about our critical accounting policies.

     Other Accounting Matters

     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. See Note 13 for our Asset Retirement Obligation discussion.

Business Outlook

     In this section we discuss a number of factors affecting our business outlook.

     General Rate Case

     We believe our general rate case pending before the ACC is the key issue affecting our outlook. See Note 5 for a detailed discussion of this rate case.

     Wholesale Power Market Conditions

     The marketing and trading division focuses primarily on managing our purchase power and fuel risks in connection with our cost of serving retail customer demand. Pinnacle West moved this division to APS in early 2003 for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting our transfer of generating assets to Pinnacle West Energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels, and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities. Based on the erosion in the market and on the market outlook, we currently expect contributions from our trading activities to be negligible for 2004, and approximately $10 million (pretax) annually thereafter.

     Factors Affecting Operating Revenues

     GeneralElectric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity prices and variations in weather from period to period.

     Customer GrowthCustomer growth in our service territory averaged about 3.4% a year for the three years 2001 through 2003; we currently expect customer growth to average about 3.5% per year from 2004 to 2006. We currently estimate that total retail

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electricity sales in kilowatt-hours will grow 5.0% on average, from 2004 through 2006, before the retail effects of weather variations. The customer and sales growth referred to in this paragraph applies to Native Load customers. Customer growth for the three-month period ended March 31, 2004 compared with the prior year period was 3.4%.

     Retail Rate ChangesAs part of the 1999 Settlement Agreement, we agreed to 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%. The final price reduction was implemented July 1, 2003. See “1999 Settlement Agreement” in Note 5 for further information. In addition, the Company has requested a 9.8% retail rate increase to be effective July 1, 2004. See “General Rate Case and Retail Rate Adjustment Mechanisms” in Note 5 for further information.

     Other Factors Affecting Future Financial Results

     Purchased Power and Fuel CostsPurchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, prevailing market prices, new generating plants being placed in service and our hedging program for managing such costs. See “Natural Gas Supply” in Note 12 for more information on fuel costs.

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

     Depreciation and Amortization ExpensesDepreciation and amortization expenses are impacted by net additions to existing utility plant and other property and changes in regulatory asset amortization. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

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

     Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for us, was 9.3% of assessed value for 2003 and 9.7% for 2002.

     Interest ExpenseInterest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs.

     Retail CompetitionThe regulatory developments and legal challenges to the Rules discussed in Note 5 have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited

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retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory.

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

Risk Factors

     Exhibit 99.1, which is hereby incorporated by reference, contains a discussion of risk factors affecting the Company.

Forward-Looking Statements

     This document contains forward-looking statements based on current expectations, and we assume no obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “predict”, “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include, but are not limited to:

• state and federal regulatory and legislative decisions and actions, including the outcome of the rate case we filed with the ACC on June 27, 2003 and the wholesale electric price mitigation plan adopted by the FERC;

• the outcome of regulatory, legislative and judicial proceedings relating to the restructuring;

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

• market prices for electricity and natural gas;

• power plant performance and outages;

• weather variations affecting local and regional customer energy usage;

• energy usage;

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

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

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

• the performance of our marketing and trading activities due to volatile market liquidity and deteriorating counterparty credit and the use of derivative

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contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

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

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

• technological developments in the electric industry;

• conservation programs; and

• other uncertainties, all of which are difficult to predict and many of which are beyond our control.

Item 3. Market Risks

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

     Commodity Price Risk

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

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

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

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

     The following tables show the pretax changes in mark-to-market of our regulated electricity and marketing and trading derivative positions for the three months ended March 31, 2004 and 2003 (dollars in millions):

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	Three Months Ended					Three Months Ended
	March 31, 2004					March 31, 2003
			Marketing						Marketing
	Regulated		and			Regulated			and
	Electricity		Trading			Electricity			Trading
Mark-to-market of net positions at beginning of period	$	—	$	(4	)	$	(50	)	$	—
Change in mark-to-market gains for future period deliveries		10		—			5			4
Changes in cash flow hedges recorded in OCI		30		—			14			—
Ineffective portion of changes in fair value recorded in earnings		1		—			2			—
Mark-to-market losses realized during the period		6		1			6			—
Mark-to-market of net positions at end of period	$	47	$	(3	)	$	(23	)	$	4

     The tables below show the fair value of maturities of our regulated electricity and trading derivative contracts (dollars in millions) at March 31, 2004 by maturities and by the type of valuation that is performed to calculate the fair values. See “Critical Accounting Policies — Mark-to-Market Accounting,” in Item 7 of our 2003 Form 10-K for more discussion on our valuation methods.

Regulated Electricity

							Total
					Years		fair
Source of Fair Value	2004		2005		thereafter		value
Prices actively quoted	$	22	$	15	$	5	$	42
Prices provided by other external sources		4		1		—		5
Prices based on models and other valuation methods		—		—		—		—
Total by maturity	$	26	$	16	$	5	$	47

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Marketing and Trading

													Total fair
Source of Fair Value	2004			2005			2006			2007			value
Prices actively quoted	$	2		$	—		$	—		$	—		$	2
Prices provided by other external sources		1			—			1			—			2
Prices based on models and other valuation methods		(4	)		(1	)		(1	)		(1	)		(7	)
Total by maturity	$	(1	)	$	(1	)	$	—		$	(1	)	$	(3	)

     The table below shows the impact that hypothetical price movements of 10% would have had on the market value of our risk management and trading assets and liabilities included on the Condensed Balance Sheets at March 31, 2004 (dollars in millions).

	March 31, 2004
	Gain (Loss)
	Price Up			Price Down
Commodity	10%			10%
Mark-to-market changes reported in earnings (a):
Electricity	$	(5	)	$	5
Natural gas		1			(1	)
Mark-to-market changes reported in OCI (b):
Electricity		6			(6	)
Natural gas		32			(32	)
Total	$	34		$	(34	)

(a)	These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.
(b)	These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties. See “Critical Accounting Policies — Mark-to-Market Accounting,” in Item 7 of our 2003 Form 10-K for more discussion on our valuation methods. See Note 10 for further discussion of credit risk.

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

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     The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

(b) Change in Internal Control over Financial Reporting

     No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 5. Other Information Construction and Financing Programs

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

Regulatory Matters

     See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of regulatory developments.

Environmental Matters

     See “Environmental Matters — Superfund” in Note 12 of Notes to Condensed Financial Statements for a discussion of a Superfund site.

     Water Supply

     The Four Corners region, in which the Four Corners power plant is located, has been experiencing drought conditions that may affect the water supply for the plant in 2003 and 2004, as well as later years if adequate moisture is not received in the watershed that supplies the area. See “Environmental Matters — Water Supply” in Part I, Item 1 of the 2003 Form 10-K. We have entered into agreements with various parties to provide backup supplies of water for 2004, if required, and are continuing to work with area stakeholders to implement additional agreements to minimize the effect, if any, on operations of the plant for 2005 and later years. The effect of the drought cannot be fully assessed at this time, and we cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from the Four Corners power plant.

Hazardous Air Pollution

     EPA recently proposed standards for nickel emissions from oil-fired units. We are currently assessing the need for additional controls to meet the requirements of this proposed standard.

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Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

Exhibit No.	Description
12.1	Ratio of Earnings to Fixed Charges
31.1	Certification of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Certification of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	APS Risk Factors

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

		Originally Filed		Date
Exhibit No.	Description	as Exhibit:	File No.a	Effective
3.1	Articles of Incorporation restated as of May 25, 1988	4.2 to Form S-3 Registration Nos. 33910 and 33-55248 by means of September 24, 1993 Form 8-K Report	1-4473	9-29-93
3.2	Bylaws, amended as of January 21, 2004	3.1 to the Company’s 2003 Form 10-K Report	1-4473	3-15-04

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

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     (b) Reports on Form 8-K

     During the quarter ended March 31, 2004, and the period from April 1 through May 7, 2004, we filed the following reports on Form 8-K:

     Report dated December 31, 2003 containing exhibits comprised of Pinnacle West’s financial information, earnings variance explanations and an earnings news release (Item 7, Item 9 and Item 12).

     Report dated January 8, 2004 regarding a delay in the schedule for the hearing for our pending general rate case (Item 5 and Item 7).

     Report dated January 27, 2004 regarding APS’ Summary of Responses Received to its Power Supply Resource Request for Proposals dated December 3, 2003 (Item 5 and Item 7).

     Report dated February 3, 2004 regarding the ACC Staff’s and RUCO’s initial written testimony filed with the ACC (Item 5).

     Report dated April 16, 2004 containing a Procedural Order issued by an ACC ALJ, which revised the procedural schedule and timing of our general rate case (Item 5 and Item 7).

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SIGNATURES

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

	ARIZONA PUBLIC SERVICE COMPANY
		(Registrant)
Dated: May  7, 2004	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		Executive Vice President and Chief
		Financial Officer
		(Principal Financial Officer
		and Officer Duly Authorized
		to sign this Report)

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Index to Exhibits

Exhibits

Exhibit No.	Description
12.1	Ratio of Earnings to Fixed Charges
31.1	Certification of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Certification of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	APS Risk Factors

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