Arizona Public Service 10-Q 2004 Q3 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 endedSeptember 30, 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	(I.R.S. Employer
incorporation or organization)	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 November 8, 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.

Glossary

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

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

Company – Arizona Public Service Company

CPUC – California Public Utility Commission

DOE – United States Department of Energy

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

FSP – FASB Staff Position

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 – United States 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

PPL Sundance – PPL Sundance Energy, LLC

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

Sundance Generating Station – PPL Sundance’s 450 megawatt generating facility approximately 55 miles southeast of Phoenix, Arizona

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 wholesale market prices

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

2004 Settlement Agreement – an agreement proposing terms under which our general rate case would be settled

VIE — variable interest entity

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TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONDENSED STATEMENTS OF INCOME
		CONDENSED STATEMENTS OF INCOME
		CONDENSED BALANCE SHEETS
		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 1. Legal Proceedings
	Item 5. Other Information Construction and Financing Programs
	Item 6. Exhibits
SIGNATURES
EXHIBIT 12.1
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 99.1

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME
(Unaudited)

	Three Months
	Ended September 30,
	2004			2003
	(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	675,089		$	675,948
Marketing and trading segment		25,423			6,668
Total		700,512			682,616
PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment		237,035			252,312
Marketing and trading segment		23,130			12,072
Total		260,165			264,384
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS		440,347			418,232
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs		143,338			121,158
Depreciation and amortization		81,177			97,643
Income taxes		57,137			51,102
Other taxes		29,013			27,914
Total		310,665			297,817
OPERATING INCOME		129,682			120,415
OTHER INCOME (DEDUCTIONS):
Income taxes		(1,383	)		5,048
Allowance for equity funds used during construction		(1,327	)		11,194
Other income (Note 15)		6,374			9,282
Other expense (Note 15)		(2,670	)		(3,395	)
Total		994			22,129
INTEREST DEDUCTIONS:
Interest on long-term debt		36,324			37,578
Interest on short-term borrowings		1,425			1,062
Debt discount, premium and expense		1,233			754
Capitalized interest		(3,498	)		2,794
Total		35,484			42,188
NET INCOME	$	95,192		$	100,356

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME
(Unaudited)

	Nine Months
	Ended September 30,
	2004			2003
	(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	1,619,361		$	1,562,416
Marketing and trading segment		91,911			85,459
Total		1,711,272			1,647,875
PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment		488,294			484,876
Marketing and trading segment		94,774			80,948
Total		583,068			565,824
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS		1,128,204			1,082,051
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs		396,121			373,538
Depreciation and amortization		258,410			289,757
Income taxes		106,870			91,261
Other taxes		86,467			83,992
Total		847,868			838,548
OPERATING INCOME		280,336			243,503
OTHER INCOME (DEDUCTIONS):
Income taxes		(5,153	)		5,846
Allowance for equity funds used during construction		2,859			11,194
Other income (Note 15)		22,192			14,107
Other expense (Note 15)		(8,709	)		(9,654	)
Total		11,189			21,493
INTEREST DEDUCTIONS:
Interest on long-term debt		103,967			105,712
Interest on short-term borrowings		5,141			3,784
Debt discount, premium and expense		3,616			2,303
Capitalized interest		(5,754	)		(6,267	)
Total		106,970			105,532
NET INCOME	$	184,555		$	159,464

See Notes to Condensed Financial Statements

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED BALANCE SHEETS
(Unaudited)

ASSETS

	September 30,			December 31,
	2004			2003
	(Dollars in Thousands)
UTILITY PLANT:
Electric plant in service and held for future use	$	9,013,325		$	8,826,033
Less accumulated depreciation and amortization		3,209,069			3,089,645
Total		5,804,256			5,736,388
Construction work in progress		185,913			187,478
Intangible assets, net of accumulated amortization		94,887			94,181
Nuclear fuel, net of accumulated amortization		57,936			52,011
Utility plant — net		6,142,992			6,070,058
INVESTMENTS AND OTHER ASSETS:
Notes receivable from associated companies (Notes 5 and 17)		498,333			497,865
Decommissioning trust accounts		253,020			240,645
Assets from risk management and trading activities — long-term (Note 10)		33,221			18,001
Other assets		63,778			64,119
Total investments and other assets		848,352			820,630
CURRENT ASSETS:
Cash and cash equivalents		356,115			112,002
Accounts receivable:
Service customers		273,115			190,884
Other (Note 17)		70,765			67,540
Allowance for doubtful accounts		(3,632	)		(3,743	)
Accrued utility revenues		111,064			71,501
Materials and supplies, at average cost		81,759			80,682
Fossil fuel, at average cost		22,886			28,360
Assets from risk management and trading activities (Note 10)		85,364			52,448
Other		7,765			6,969
Total current assets		1,005,201			606,643
DEFERRED DEBITS:
Regulatory assets		169,368			164,804
Unamortized debt issue costs		22,394			19,797
Other		72,840			73,056
Total deferred debits		264,602			257,657
TOTAL ASSETS	$	8,261,147		$	7,754,988

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED BALANCE SHEETS
(Unaudited)

CAPITALIZATION AND LIABILITIES

	September 30,			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		887,623			830,569
Accumulated other comprehensive income/(loss):
Minimum pension liability adjustment		(57,158	)		(57,158	)
Derivative instruments		35,712			5,253
Common stock equity		2,291,143			2,203,630
Long-term debt less current maturities		2,150,944			2,135,606
Total capitalization		4,442,087			4,339,236
CURRENT LIABILITIES:
Current maturities of long-term debt		565,707			487,067
Accounts payable		196,139			131,383
Accrued taxes		233,831			90,474
Accrued interest		39,500			42,702
Customer deposits		50,817			45,481
Deferred income taxes		631			631
Liabilities from risk management and trading activities (Note 10)		55,371			58,138
Other		80,788			60,008
Total current liabilities		1,222,784			915,884
DEFERRED CREDITS AND OTHER:
Deferred income taxes		1,282,536			1,248,397
Liabilities from risk management and trading activities - long-term (Note 10)		5,658			4,502
Regulatory liabilities		528,838			510,423
Unamortized gain - sale of utility plant		51,477			54,909
Customer advances for construction		61,721			52,783
Pension liability		168,290			160,639
Liability for asset retirement		246,774			234,440
Other		250,982			233,775
Total deferred credits and other		2,596,276			2,499,868
COMMITMENTS AND CONTINGENCIES (Notes 5, 12 and 13)
TOTAL LIABILITIES AND EQUITY	$	8,261,147		$	7,754,988

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months
	Ended September 30,
	2004			2003
	(Dollars in Thousands)
Cash Flows from Operating Activities:
Net Income	$	184,555		$	159,464
Items not requiring cash:
Depreciation and amortization		258,410			289,757
Nuclear fuel amortization		23,393			22,781
Allowance for equity funds used during construction		(2,859	)		(11,194	)
Deferred income taxes		5,259			(43,976	)
Change in mark-to-market valuations		(20,666	)		7,994
Changes in certain current assets and liabilities:
Accounts receivable		(85,567	)		19,934
Accrued utility revenues		(39,563	)		(33,946	)
Materials, supplies and fossil fuel		4,397			(36	)
Other current assets		(189	)		(8,854	)
Accounts payable		69,585			59,617
Accrued taxes		143,357			144,090
Accrued interest		(3,202	)		(3,830	)
Other current liabilities		26,116			1,689
Increase in regulatory assets		(5,551	)		(10,681	)
Increase in regulatory liabilities		16,764			612
Change in risk management trading - assets		1,759			8,323
Change in risk management trading - liabilities		19,456			—
Change in customer advances		8,938			4,081
Change in pension liability		7,651			2,133
Change in other long-term assets		192			(14,348	)
Change in other long-term liabilities		14,989			63,285
Net cash flow provided by operating activities		627,224			656,895
Cash Flows from Investing Activities:
Capital expenditures		(329,759	)		(305,061	)
Capitalized interest		(5,754	)		(6,267	)
Loans to associated companies		(468	)		(497,708	)
Other		(10,446	)		(4,184	)
Net cash flow used for investing activities		(346,427	)		(813,220	)
Cash Flows from Financing Activities:
Issuance of long-term debt		476,240			491,654
Repayment and reacquisition of long-term debt		(385,424	)		(89,222	)
Dividends paid on common stock		(127,500	)		(127,500	)
Net cash flow provided by/(used for) financing activities		(36,684	)		274,932
Net increase in cash and cash equivalents		244,113			118,607
Cash and cash equivalents at beginning of period		112,002			42,549
Cash and cash equivalents at end of period	$	356,115		$	161,156
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest)	$	106,557		$	106,930
Income taxes paid	$	8,152		$	26,003

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 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. For these reasons as well as others, 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. Changes in Liquidity

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

     In May 2004, we renewed our $250 million revolving credit facility, while increasing its size to $325 million and extending its term to three years. The revolver provides liquidity support for our $250 million commercial paper program, as well as an additional $75 million for other liquidity needs and miscellaneous letters of credit.

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     On June 29, 2004, we issued $300 million of 5.80% senior unsecured notes due June 30, 2014. The proceeds from the sale of the notes will be used to redeem all or a portion of $100 million in aggregate principal amount of our 6.25% Notes due January 15, 2005 and/or all or a portion of $300 million in aggregate principal amount of our 7.625% Notes due August 1, 2005.

     At September 30, 2004, we had $566 million of pollution control bonds under which interest rates are reset on a daily, weekly or annual basis. The holders of $387 million of these bonds have the right to cause us to purchase their bonds on the applicable reset date if the bonds are not remarketed. Of these bonds, $164 million of such bonds are classified as current maturities of long-term debt. The remaining $223 million of bonds are classified as long-term debt because we have the intent and ability, as 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 principal payments due on total long-term debt and capitalized lease requirements as of September 30, 2004:

• zero in 2004;

• $616 million in 2005;

• $86 million in 2006;

• $175 million in 2007;

• $1 million in 2008; and

• $1.847 billion thereafter.

5. Regulatory Matters

Electric Industry Restructuring

State

     General Rate Case; 2004 Settlement Agreement

     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.

     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 August 18, 2004, a substantial majority of the parties to the rate case, including us, the ACC staff, the Residential Utility Consumer Office, other customer groups, and merchant power plant intervenors entered into an agreement that proposes terms under which the rate case would be settled (the “2004 Settlement Agreement”). Key financial

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components of the 2004 Settlement Agreement, which is subject to ACC approval, are as follows:

• We would receive an annual retail rate increase of approximately $75.5 million, or 4.21%. The increase would consist of an increase in base rates of approximately 3.77% and an increase of approximately 0.44% for recovery over five years of the past costs of compliance with the ACC’s retail electric competition rules.

• We would acquire the PWEC Dedicated Assets from Pinnacle West Energy and rate base the PWEC Dedicated Assets at a rate base value of $700 million, which would result in a mandatory rate base disallowance of $148 million. As a result, for financial reporting purposes, we would recognize a one-time, after-tax net plant write-off of approximately $88 million in the period when the plant transfer to us is completed, and would reduce annual depreciation expense by approximately $5 million.

• To bridge the time between the effective date of the rate increase and the actual date the PWEC Dedicated Assets transfer, we and Pinnacle West Energy would enter into a cost-based purchase power agreement (the “Bridge PPA”), which would be based on the value of the PWEC Dedicated Assets described in the previous bullet point. The Bridge PPA would remain in effect until the FERC approves the transfer of the PWEC Dedicated Assets to us and the transfer is completed.

• If the FERC were to issue an order denying our request to acquire the PWEC Dedicated Assets, the Bridge PPA would become a 30-year purchased power agreement, with prices reflecting cost-of-service as if we had acquired and rate-based the PWEC Dedicated Assets at the value described above.

• If the FERC were to issue an order (a) approving our request to transfer the PWEC Dedicated Assets at a value materially less than $700 million, (b) approving the transfer of fewer than all of the PWEC Dedicated Assets, or (c) that was materially inconsistent with the 2004 Settlement Agreement, we would file an appropriate application with the ACC so that rates could be adjusted. In these circumstances, the Bridge PPA would continue at least until the conclusion of the subsequent proceeding to consider any appropriate adjustment to our rates.

• A power supply adjuster would provide for the recovery of fuel and purchased power costs, subject to specified parameters and procedures.

• We would not restore and recover in rates the $234 million write-off recorded in 1999 as a result of a 1999 settlement agreement approved by the ACC related to the implementation of retail electric competition in Arizona. As a result, annual amortization expense for financial reporting purposes would be

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	approximately $16 million less than if the $234 million write-off had been restored and amortized over a 15-year period as originally requested.
•	We would adopt longer service lives than originally requested for certain depreciable assets, which would have the effect of reducing annual depreciation expense for financial reporting purposes by approximately $26 million.

     Major changes in revenue requirements under the 2004 Settlement Agreement are as follows (dollars in millions):

Original request	$	175
Return on equity to 10.25% versus 11.50%		(36	)
No recovery of $234 million write-off		(32	)
Lengthen asset depreciable lives		(26	)
$148 million rate base disallowance		(22	)
Miscellaneous – net (not specifically identified in 2004 Settlement Agreement)		17
Proposed settlement	$	76

     Hearings on the 2004 Settlement Agreement are scheduled to begin on November 8, 2004.

     ACC Financing Order

     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 Pinnacle West to fund the repayment of a portion of the debt Pinnacle West incurred to finance the construction of the PWEC Dedicated Assets.

     The ACC granted the Financing Order subject to various conditions. One of these conditions is that 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.

     In addition, the Financing Order required 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. As part of the 2004 Settlement Agreement, this inquiry would be concluded with no further action by the ACC.

     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 of our retail electricity customers.

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

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

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

• Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, 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 affected 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. A request for the Arizona Supreme Court to review the Court of Appeals decision is still pending.

     Track A Order

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

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• 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

• unilaterally modified the 1999 Settlement Agreement, which authorized the 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.

• As a result of the ACC’s issuance of the Financing Order, 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.

     Upon the ACC’s issuance of a final, non-appealable order approving the 2004 Settlement Agreement, we, Pinnacle West, and Pinnacle West Energy will dismiss the litigation described under this “Track A” heading.

     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,

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2003. For 2003, we were required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements.

     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.

     Effective upon final ACC approval of the 2004 Settlement Agreement and the closing of the purchase of PPL Sundance, the Track B contracts with Pinnacle West Energy and PPL Energy Plus, LLC will be cancelled.

     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. 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. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. There can be no assurance that we would be able to fully recover the costs of this power. The proposed settlement of our general rate case, discussed above, would, among other things, allow us to recover purchased power costs.

     1999 Settlement Agreement

     The following are the major provisions of a settlement agreement entered into in 1999, 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

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taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; approximately $28 million ($17 million after taxes), effective July 1, 2002; and approximately $29 million ($18 million after taxes), effective July 1, 2003. For customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.

• Unbundled rates being charged by 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 was a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004.

• We are being 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, or when the rate case is decided. See “General Rate Case; 2004 Settlement Agreement” above.

• 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” above), 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.

• 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 stated 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 1999 dollars). The 1999 Settlement Agreement also stated 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 provided 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 part of our general rate case request, we sought the recovery of amounts written off by us as a result of the 1999 Settlement Agreement. That claim would be given up under the terms of the 2004 Settlement Agreement (see above).

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• 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 above under “Track A Order,” in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing an order preventing us from transferring our generation assets. Under the 2004 Settlement Agreement, we would recover all costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “General Rate Case; 2004 Settlement Agreement” above. Such full recovery of divestiture costs is allowed under the 2004 Settlement Agreement (see above).

     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.

     Request for Proposals and Asset Purchase Agreement

     In early December 2003, we issued a request for proposals (“RFP”) for long-term power supply resources. On June 1, 2004, we and PPL Sundance, a wholly-owned subsidiary of PPL Corporation, entered into an asset purchase agreement by which we agreed to purchase the 450 MW Sundance Generating Station. The Sundance Generating Station, which began commercial operation in July 2002, would provide peaking generation support for our system and reduce our growing needs for new generation resources.

     The purchase price for the Sundance Generating Station is $189.5 million. Subject to the receipt of approvals from various regulatory agencies, including the ACC, the FERC, the Department of Justice and the Federal Trade Commission, the transaction is expected to close in the first quarter of 2005. Either party may terminate the agreement if ACC approval is not obtained by December 31, 2004 or the transaction does not close by March 31, 2005.

     On June 1, 2004, we and PPL Sundance filed a joint application with the ACC requesting approval of the transaction on or before December 31, 2004. We also requested, among other things, that the Sundance Generating Station be included in our rates in our next rate case and that certain operating and capital costs be deferred until that time. We are not requesting that the Sundance Generating Station be reflected in our

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current general rate case before the ACC. A hearing on the application was held in early October, and we expect a decision by the end of the year.

     We do not expect to enter into any additional transactions as a result of the RFP.

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.

     The FERC has been in the process of auditing numerous utilities regarding compliance with its regulations. Such an audit of us and our affiliates is currently in process. Certain instances of noncompliance with FERC regulations related to the administration of our transmission tariff have been identified. We are presently discussing these issues with the FERC staff and expect a public report to be issued later this year. We currently expect, but cannot provide any assurance, that the resolution of these matters will not have a material adverse effect on our financial position, results of operations or liquidity.

6. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit pension plan, a nonqualified 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 cost. The FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to address the accounting for the effects of the Act. During the third quarter of 2004, Pinnacle West retroactively adopted the provisions of FSP 106-2, resulting in the remeasurement of its postretirement benefit plans’ accumulated postretirement benefit obligation (APBO) as of December 31, 2003. The impact of the subsidy for Pinnacle West is a decrease in the accumulated projected benefit obligation of approximately $65 million and a decrease of approximately $11 million in the net periodic postretirement benefit cost for 2004. The annual after-tax reduction to our expense is approximately $4 million, excluding amounts capitalized as construction overhead or billed to electric plant participants.

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     The following table provides details of the benefit costs of Pinnacle West’s plans for the three and nine months ended September 30, 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 on amounts capitalized as overhead construction (dollars in millions):

				Pension Benefits												Other Benefits
	Three Months						Nine Months						Three Months						Nine Months
	Ended						Ended						Ended						Ended
	September 30,						September 30,						September 30,						September 30,
	2004			2003			2004			2003			2004			2003			2004(a)			2003
Service cost-benefits earned during the period	$	10		$	10		$	31		$	28		$	4		$	4		$	13		$	12
Interest cost on benefit obligation		21			20			62			57			7			8			22			23
Expected return on plan assets		(20	)		(17	)		(60	)		(48	)		(6	)		(5	)		(18	)		(14	)
Amortization of:
Transition (asset)/obligation		(1	)		(1	)		(2	)		(2	)		1			1			2			2
Prior service cost		1			1			2			2			—			—			—			—
Net actuarial loss		4			4			13			13			2			2			5			7
Net periodic benefit cost	$	15		$	17		$	46		$	50		$	8		$	10		$	24		$	30
Our share of costs charged to expense	$	6		$	7		$	18		$	20		$	3		$	4		$	9		$	12

(a) The nine months ended September 30, 2004 amounts include the reduction in benefit costs for the first and second quarter Medicare Part D subsidy not previously reflected in those periods.

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, which Pinnacle West contributed in the third quarter. Pinnacle West has contributed approximately $14 million to the other postretirement benefits plan in 2004 through September. Our share of these contributions is approximately 89%.

7. 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.

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

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	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2004		2003			2004			2003
Operating Revenues:
Regulated electricity	$	675	$	676		$	1,619		$	1,562
Marketing and trading		26		7			92			86
Total	$	701	$	683		$	1,711		$	1,648
Net Income (Loss):
Regulated electricity	$	95	$	106		$	191		$	162
Marketing and trading		—		(6	)		(6	)		(3	)
Total	$	95	$	100		$	185		$	159

	As of		As of
	September 30, 2004		December 31, 2003
Assets:
Regulated electricity	$	8,247	$	7,747
Marketing and trading		14		8
Total	$	8,261	$	7,755

8. Accounting Matters

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

• Note 6 for FSP 106-2 regarding the Medicare Prescription Drug, Improvement and Modernization Act related to retirement plans and other benefits; and

• Note 9 for FIN No. 46R related to variable interest entities.

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 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.

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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 September 30, 2004, we would have been required to assume approximately $250 million of debt and pay the equity participants approximately $195 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. As of September 30, 2004, we hedge exposures to the price variability of these commodities for a maximum of eight years. 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.

Cash Flow Hedges

     The changes in the fair value of our hedged positions included in the Condensed Statements of Income for the three and nine months ended September 30, 2004 and 2003 were comprised of the following (dollars in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2004			2003		2004		2003
Gains/(Losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(59	)	$	1,069	$	1,477	$	6,962
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		—			—		63		—
Gains from the discontinuance of cash flow hedges		—			—		575		—

     During the twelve months ending September 30, 2005, we estimate that a net gain of $37 million before income taxes will be reclassified from accumulated other comprehensive

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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 September 30, 2004 and December 31, 2003 (dollars in thousands):

September 30, 2004

	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated Electricity:
Mark-to-market	$	65,887	$	28,267	$	(21,913	)	$	(4,041	)	$	68,200
Options at cost and margin account		7,185		3,138		(19,456	)		—			(9,133	)
Marketing and Trading:
Mark-to-market		12,292		1,797		(14,002	)		(1,617	)		(1,530	)
Emission allowances – at cost		—		19		—			—			19
Total	$	85,364	$	33,221	$	(55,371	)	$	(5,658	)	$	57,556

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. Collateral provided to counterparties at

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September 30, 2004 was $1 million. No collateral was provided to counterparties at December 31, 2003. Collateral provided to us by counterparties was $9 million at September 30, 2004 and $12 million at December 31, 2003, and is included in other current liabilities 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, local distribution companies and financial institutions. 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.

11. Comprehensive Income

     Components of comprehensive income for the three and nine months ended September 30, 2004 and 2003, are as follows (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Net income	$	95,192		$	100,356		$	184,555		$	159,464
Other comprehensive income:
Minimum pension liability adjustment, net of tax		—			—			—			(112	)
Unrealized gains/(losses) on derivative instruments, net of tax (a)		12,129			(3,831	)		41,246			16,797
Reclassification of realized gain/ (loss) to income, net of tax (b)		(6,652	)		1,467			(10,787	)		3,004
Total other comprehensive income		5,477			(2,364	)		30,459			19,689
Comprehensive income	$	100,669		$	97,992		$	215,014		$	179,153

(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.

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12. Commitments and Contingencies

Palo Verde Nuclear Generating Station

     Spent Fuel and Waste Disposal

     Nuclear power plant owners 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.

     Based upon current estimates of the amount of spent fuel and the cost of storage, we currently estimate we will incur $115 million over the life of Palo Verde for our share of the costs related to the on-site interim storage of spent nuclear fuel. As of September 30, 2004, we had spent $10 million and recorded a liability of $41 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. We have recorded a corresponding regulatory asset of $51 million and are seeking recovery of these costs through future rates (see “General Rate Case; 2004 Settlement Agreement” in Note 5).

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 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

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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 under market-based rates. 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 was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. State of California ex rel. Bill Lockyer, Attorney General v. FERC, No. 02-73093. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The outcome of the further proceedings cannot be predicted at this time.

     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 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.

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Natural Gas Supply

     We 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 now expect that the combined increase in costs associated with the natural gas supply and the transportation capacity to result in an overall average increase of approximately $4 million per year in 2004 and 2005. 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.

     In addition, another party has also sought review of FERC’s July 9 order and is seeking to reallocate the costs associated with the changed contractual obligations in a way that would be less favorable to us and Pinnacle West Energy than under FERC’s order. Should this party prevail on this point, we and Pinnacle West Energy’s annual capacity cost could be increased by approximately $3 million per year, from September 2003 through December 2005, in addition to the $4 million discussed above.

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 us have agreed with the EPA to perform certain investigation activities of our facilities within OU3. Because the investigation has not yet been completed and the ultimate remediation requirements are not yet finalized, we cannot currently estimate the expenditures which may be required.

Asset Purchase Agreement

     See “Request for Proposals and Asset Purchase Agreement” in Note 5 for a description of an asset purchase agreement between us and PPL Sundance.

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13. Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. 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.

14. 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 and nine months ended September 30, 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 September 30, 2004 (dollars in thousands):

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	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2004		2003		2004		2003
Net income, as reported	$	95,192	$	100,356	$	184,555	$	159,464
Add: Stock compensation expense included in reported net income (net of tax)		756		634		2,053		1,454
Deduct: Total stock compensation expense determined under fair value method (net of tax)		831		891		2,306		2,224
Pro forma net income	$	95,117	$	100,099	$	184,302	$	158,694

15. Other Income and Other Expense

     The following table provides detail of other income and other expense for the three and nine months ended September 30, 2004 and 2003 (dollars in thousands):

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2004			2003			2004			2003
Other income:
Interest income	$	5,857		$	6,595		$	15,908		$	10,239
Asset sales		33			270			2,495			573
Investment gains – net		—			1,626			2,312			2,204
Miscellaneous		484			791			1,477			1,091
Total other income	$	6,374		$	9,282		$	22,192		$	14,107
Other expense:
Non-operating costs(a)	$	(1,793	)	$	(2,662	)	$	(6,336	)	$	(8,240	)
Asset sales		(123	)		(452	)		(391	)		(1,370	)
Investment losses – net		(85	)		—			—			—
Miscellaneous		(669	)		(281	)		(1,982	)		(44	)
Total other expense	$	(2,670	)	$	(3,395	)	$	(8,709	)	$	(9,654	)

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

16. Guarantees

     We have entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 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. In July 2004, $150 million of these letters of credit were renewed for a three-year term and expire in 2007. The remainder expire in 2005. We have also entered into approximately $102 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

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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 2005. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     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.

17. 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				Nine Months
	Ended				Ended
	September 30,				September 30,
	2004		2003		2004		2003
Electric operating revenues:
Pinnacle West – marketing and trading	$	4	$	5	$	12	$	8
Pinnacle West Energy		—		4		1		8
Total	$	4	$	9	$	13	$	16
Purchased power and fuel costs:
Pinnacle West Energy (a)	$	34	$	35	$	63	$	78
Total	$	34	$	35	$	63	$	78
Other:
Pinnacle West Energy interest income (b)	$	5	$	—	$	14	$	—
Total	$	5	$	—	$	14	$	—

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	As of			As of
	September 30,			December 31,
	2004			2003
Net intercompany receivables/(payables):
Pinnacle West Energy (b)	$	468		$	463
Pinnacle West – marketing and trading		3			16
APS Energy Services		13			10
Pinnacle West		(11	)		(8	)
Total	$	473		$	481

(a) Includes a debit of $6 million related to mark-to-market on an intercompany contract for the three months ended September 30, 2003.

(b) Primarily 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. We purchase electricity from and sell electricity to APS Energy Services; however, these transactions are settled net and reported net. 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 PUBLIC 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. We are a wholly-owned subsidiary of Pinnacle West. 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 marketing and trading division focuses primarily on managing purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. Our service territory growth is about three times the national average and remains a fundamental driver of our revenues and earnings.

     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 2004 Settlement Agreement would provide for that transfer.

     We believe our general rate case, including the proposed settlement, 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 and proposed settlement. 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; depreciation and amortization expenses, which are affected by net additions to existing utility plant and other property and changes in regulatory asset amortization.

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

     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.

     The following table summarizes net income (loss) by segment for the three and nine months ended September 30, 2004 and the comparable prior-year periods (dollars in millions):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2004		2003			2004			2003
Regulated electricity	$	95	$	106		$	191		$	162
Marketing and trading		—		(6	)		(6	)		(3	)
Net income	$	95	$	100		$	185		$	159

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.

     In accordance with the 1999 Settlement Agreement, we completed amortizing substantially all of our regulatory assets as of June 30, 2004.

Operating Results – Three-month period ended September 30, 2004 compared with the three-month period ended September 30, 2003

     Our net income for the three months ended September 30, 2004 was $95 million compared with $100 million for the prior-year period. The $5 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:

• Regulated Electricity Segment – Net income decreased approximately $11 million primarily due to increased operations and maintenance costs related to customer service and personnel costs, the effects of weather on retail sales, and increased purchased power and fuel costs due to higher fuel and power prices. These negative factors were partially offset by lower replacement power costs due to fewer unplanned outages, the absence of regulatory asset amortization, and the benefit of customer growth.

• Marketing and Trading Segment – Net income increased approximately $6 million primarily due to higher forward and realized prices for wholesale sales of electricity.

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     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:
Lower replacement power costs due to fewer unplanned outages, partially offset by higher prices for replacement power	$	24		$	14
Higher retail sales volumes due to customer growth, excluding weather effects		17			10
Effects of weather on retail sales		(20	)		(12	)
Increased purchased power and fuel costs due to higher fuel and power prices		(5	)		(3	)
Miscellaneous factors, net		(2	)		(1	)
Net increase in regulated electricity segment gross margin		14			8
Marketing and trading segment gross margin:
Higher mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity		4			2
Higher realized margins on energy trading primarily due to higher electricity prices		3			2
Miscellaneous factors, net		1			1
Net increase in marketing and trading segment gross margin		8			5
Net increase in regulated electricity and marketing and trading segments’ gross margins		22			13
Higher operations and maintenance expense primarily related to higher customer service costs and personnel costs		(22	)		(13	)
Depreciation and amortization decreases (increases):
Absence of regulatory asset amortization		21			13
Increased delivery and other assets		(5	)		(3	)
Lower income resulting from our return to the AFUDC method of capitalizing construction finance costs in the third quarter of 2003		(5	)		(8	)
Lower income tax credits		—			(5	)
Miscellaneous items, net		(4	)		(2	)
Net increase (decrease) in net income	$	7		$	(5	)

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $1 million lower for the three months ended September 30, 2004 compared with the prior-year period, primarily as a result of:

• a $44 million decrease in retail revenues related to weather;

• a $38 million increase in retail sales volumes related to customer growth and higher average usage, excluding weather effects; and

• a $5 million increase due to miscellaneous factors.

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Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $19 million higher for the three months ended September 30, 2004 compared with the prior-year period, primarily as a result of:

• $19 million of higher realized wholesale revenues primarily due to higher prices and volumes;

• $3 million in higher mark-to-market gains for future-period deliveries primarily as a result of higher forward prices for wholesale electricity; and

• a $3 million decrease from generation sales other than Native Load primarily due to sales volumes and wholesale market prices.

Operating Results – Nine-month period ended September 30, 2004 compared with the nine-month period ended September 30, 2003

     Our net income for the nine months ended September 30, 2004 was $185 million compared with $159 million for the prior-year period. The $26 million increase in the period-to-period comparison reflects the following changes in earnings by segment:

• Regulated Electricity Segment – Net income increased approximately $29 million primarily due to lower regulatory asset amortization, the benefit of customer growth, lower fuel and purchased power costs due to lower fuel and power prices and lower replacement power costs due to fewer unplanned outages. These factors were partially offset by increased operations and maintenance costs related to customer service and personnel costs, higher depreciation and property taxes related to increased delivery and other assets, a retail electricity price reduction and effects of weather on retail sales.

• Marketing and Trading Segment – net income decreased approximately $3 million primarily due to lower margins on wholesale sales.

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

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Higher retail sales volumes due to customer growth, excluding weather effects	$	41		$	25
Decreased purchased power due to lower capacity costs		28			17
Lower replacement power costs due to fewer unplanned outages		7			4
Retail electricity price reduction effective July 1, 2003		(13	)		(8	)
Effects of weather on retail sales		(10	)		(6	)
Net increase in regulated electricity segment gross margin		53			32
Marketing and trading segment gross margin:
Lower realized margins on energy trading primarily due to lower electricity prices		(12	)		(7	)
Higher mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity		6			4
Miscellaneous items, net		(1	)		(1	)
Net decrease in marketing and trading segment gross margin		(7	)		(4	)
Net increase in regulated electricity and marketing and trading segments’ gross margins		46			28
Higher operations and maintenance expense primarily related to customer service costs and personnel costs		(23	)		(14	)
Depreciation and amortization decreases (increases):
Decreased regulatory asset amortization		47			28
Increased delivery and other assets		(16	)		(10	)
Lower income tax credits		—			(4	)
Miscellaneous items, net		(2	)		(2	)
Net increase in net income	$	52		$	26

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $57 million higher for the nine months ended September 30, 2004 compared with the prior-year period, primarily as a result of:

• an $86 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

• a $27 million decrease in retail revenues related to weather;

• a $13 million decrease in retail revenues related to a reduction in retail electricity prices; and

• an $11 million increase due to miscellaneous factors.

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Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $6 million higher for the nine months ended September 30, 2004 compared with the prior-year period, primarily as a result of:

• $30 million of higher realized wholesale revenues primarily due to higher prices and higher volume;

• $6 million in higher mark-to-market gains for future-period deliveries primarily as a result of higher forward prices for wholesale electricity; and

• a $30 million decrease from generation sales other than Native Load primarily due to lower wholesale market prices and lower volumes.

Liquidity and Capital Resources

     Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for the nine months ended September 30, 2004 and estimated capital expenditures for the next three years (dollars in millions):

	Nine Months Ended		Estimate for the Year
	September 30,		Ended December 31,
	2004		2004		2005		2006
Delivery	$	246	$	326	$	390	$	453
Generation (a) (b)		69		108		350		202
Other (c)		16		29		30		18
Total	$	331	$	463	$	770	$	673

(a) As discussed in Note 5 under “General Rate Case; 2004 Settlement Agreement,” as part of our general rate case, we have requested rate base treatment of the PWEC Dedicated Assets. Pinnacle West Energy’s actual capital expenditures related to the PWEC Dedicated Assets are estimated to be $15 million in 2004, $14 million in 2005 and $14 million in 2006.

(b) Estimate for 2005 includes about $190 million for acquisition of the Sundance Generating Station. See Note 5 for a discussion of the asset purchase agreement between us and PPL Sundance.

(c) Primarily information systems and facilities projects.

     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

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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 to us 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 nine months ended September 30, 2004:

• Our purchased power and fuel commitments increased approximately $44 million to $306 million primarily related to fourth quarter 2004 obligations.

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

• Our purchase obligations for 2005 increased approximately $190 million for our proposed acquisition of the Sundance Generating Station. See Note 5, “Regulatory Matters – Request for Proposals and Asset Purchase Agreement,” for a discussion of the asset purchase agreement between us and PPL Sundance, including required regulatory approvals.

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

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     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 September 30, 2004, we would have been required to assume approximately $250 million of debt and pay the equity participants approximately $195 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 16 for additional information regarding guarantees and letters of credit.

     Credit Ratings

      The ratings of our securities as of November 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).

	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 our mortgage and deed of trust.

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     Debt Provisions

     Our debt covenants related to our bank 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 September 30, 2004, the ratio was approximately 53%. 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, except that we do not have a material adverse change restriction for revolver borrowings equal to outstanding commercial paper amounts.

     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, including current maturities of long-term debt. At September 30, 2004 our common equity ratio was approximately 46%.

     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, Navajo County, Arizona Pollution Control Corporation issued $166 million of variable interest rate pollution control bonds, 2004 Series A-E, due 2034.

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The bonds were issued to refinance $166 million of outstanding pollution control bonds. The Series A-E bonds are payable solely from revenues obtained from us pursuant to a loan agreement between us and 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. The Series A 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.

     In May 2004, we renewed our $250 million revolving credit facility, while increasing its size to $325 million and extending its term to three years. The revolver provides liquidity support for our $250 million commercial paper program, as well as an additional $75 million for other liquidity needs and miscellaneous letters of credit.

     On June 29, 2004, we issued $300 million of 5.80% senior unsecured notes due June 30, 2014. The proceeds from the sale of the notes will be used to redeem all or a portion of $100 million in aggregate principal amount of our 6.25% Notes due January 15, 2005 and/or all or a portion of $300 million in aggregate principal amount of our 7.625% Notes due August 1, 2005.

     We have retired all first mortgage bonds issued by us under our 1946 mortgage and deed of trust, including the first mortgage bonds securing our senior notes. On April 30, 2004, we terminated our mortgage and deed of trust and, as a result, we are not 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 comprised of 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. Under this new legislation, Pinnacle West’s required pension contribution in 2004 is $35 million, which Pinnacle West contributed in the third quarter. Pinnacle West has contributed approximately $14 million to the other postretirement benefits plan in 2004 through September.

     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,

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revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting 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.

Business Outlook

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

     General Rate Case

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

     Wholesale Power Market Conditions

     The marketing and trading division focuses primarily on managing our purchased power and fuel risks in connection with our cost of serving retail customer demand. Pinnacle West moved this division to us 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 is 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.

     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 3.8% per year from 2004 to 2006. We currently estimate that total retail electricity sales in kilowatt-hours will grow 4.6% 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 nine-month period ended September 30, 2004 compared with the prior year period was 3.7%.

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     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; 2004 Settlement Agreement” 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 through June 30, 2004 under the 1999 Settlement Agreement were 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 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.

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     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. In addition to the Risk Factors noted above (see Exhibit 99.1), 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 ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;

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

• market prices for electricity and natural gas;

• power plant performance and outages, including transmission outages and constraints;

• weather variations affecting local and regional customer energy usage;

• customer growth and energy usage;

• regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile 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;

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• the uncertainty that current credit ratings will remain in effect for any given period of time;

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

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

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

• the performance of the stock market and the changing interest rate environment, which affect the 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.

     Interest Rate and Equity Risk

     Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt.

     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

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correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

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

• Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for 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 nine months ended September 30, 2004 and 2003 (dollars in millions):

	Nine Months Ended						Nine Months Ended
	September 30, 2004						September 30, 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/(losses) for future period deliveries		10			2			(1	)		(5	)
Changes in cash flow hedges recorded in OCI		68			—			26			2
Ineffective portion of changes in fair value recorded in earnings		1			—			7			—
Mark-to-market losses (gains) realized during the period		(11	)		2			—			(4	)
Change in valuation techniques		—			(1	)		—			—
Mark-to-market of net positions at end of period	$	68		$	(1	)	$	(18	)	$	(7	)

     The tables below show the fair value of maturities of our regulated electricity and trading derivative contracts (dollars in millions) at September 30, 2004 by maturities and by the type of valuation that is performed to calculate the fair values. See “Critical Accounting

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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	$	7		$	49		$	14	$	70
Prices provided by other external sources		—			1			—		1
Prices based on models and other valuation methods		(2	)		(1	)		—		(3	)
Total by maturity	$	5		$	49		$	14	$	68

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		—			2			1			—			3
Prices based on models and other valuation methods		(2	)		(2	)		(1	)		(1	)		(6	)
Total by maturity	$	—		$	—		$	—		$	(1	)	$	(1	)

     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 September 30, 2004 (dollars in millions).

	September 30, 2004
	Gain (Loss)
Commodity	Price Up 10%			Price Down 10%
Mark-to-market changes reported in earnings (a):
Electricity	$	(1	)	$	1
Natural gas		1			(1	)
Mark-to-market changes reported in OCI (b):
Electricity		8			(8	)
Natural gas		31			(31	)
Total	$	39		$	(39	)

(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

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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 Form10-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

     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 1. Legal Proceedings

     See Note 12 of Notes to Condensed Financial Statements in regard to pending or threatened litigation or other disputes.

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

     ADEQ issued a Notice of Violation to us in January 2004 alleging that, among other things, the discharge limit for lead was exceeded at the Saguaro Power Plant. See “Environmental Matters – Arizona Department of Environmental Quality” in Part I, Item 1 of the 2003 10-K. In August 2004, ADEQ closed the Notice of Violation without issuing any penalty.

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

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Item 6. Exhibits

(a) Exhibits

Exhibit No.		Description
	12.1	Ratio of Earnings to Fixed Charges
	31.1	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
	31.2	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
	32.1	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	3.1 to June 30, 2004	1-4473	8-9-04
	June 23, 2004	Form 10-Q Report
10.1	Amendment to Agreement	10.2 to Pinnacle West’s September 30,	1-8962	11-8-04
	between APS and	2004 Form 10-Q Report
	James M. Levine

^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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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: November 8, 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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