10-Q

FORM 10-Q

Securities and Exchange Commission

Washington, D.C. 20549

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

For the quarterly period ended June 30, 2004

OR

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

For the transition period from _______________________ to _____________

Commission file number 1-4473

ARIZONA PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)

Arizona	86-0011170
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona	85072-3999
(Address of principal executive offices)	(Zip Code)
Registrant’s telephone number, including area code: (602) 250-1000

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

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

Yes x No o

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

Yes o 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 August 6, 2004: 71,264,947

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

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONDENSED STATEMENTS OF INCOME
		CONDENSED BALANCE SHEETS (Unaudited)
		CONDENSED STATEMENTS OF CASH FLOWS (Unaudited)
		NOTES TO CONDENSED FINANCIAL STATEMENTS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Market Risks
	Item 4. Controls and Procedures
PART II – OTHER INFORMATION
	Item 5. Other Information Construction and Financing Programs
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
Exhibit Index
Exhibit 3.1
Exhibit 12.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 99.1

Glossary

ACC – Arizona Corporation Commission

ALJ – administrative law judge

APS – Arizona Public Service Company, the Company

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

CC&N – Certificate of Convenience and Necessity

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

VIE – variable interest entity

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

	Three Months
	Ended June 30,
	2004			2003
	(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	523,973		$	504,582
Marketing and trading segment		45,685			28,740
Total		569,658			533,322
PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment		162,667			148,464
Marketing and trading segment		45,886			24,443
Total		208,553			172,907
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS		361,105			360,415
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs		127,947			130,543
Depreciation and amortization		88,385			96,557
Income taxes		32,371			29,193
Other taxes		29,874			27,864
Total		278,577			284,157
OPERATING INCOME		82,528			76,258
OTHER INCOME (DEDUCTIONS):
Income taxes		(1,301	)		294
Allowance for equity funds used during construction		2,184			—
Other income (Note 15)		4,668			3,362
Other expense (Note 15)		(1,220	)		(3,743	)
Total		4,331			(87	)
INTEREST DEDUCTIONS:
Interest on long-term debt		31,997			35,166
Interest on short-term borrowings		1,215			1,463
Debt discount, premium and expense		1,188			829
Capitalized interest		(1,399	)		(4,462	)
Total		33,001			32,996
NET INCOME	$	53,858		$	43,175

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

	Six Months
	Ended June 30,
	2004			2003
	(Dollars in Thousands)
ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	944,272		$	886,468
Marketing and trading segment		66,488			78,791
Total		1,010,760			965,259
PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment		251,259			232,564
Marketing and trading segment		71,644			68,876
Total		322,903			301,440
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS		687,857			663,819
OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs		254,935			252,380
Depreciation and amortization		177,233			192,114
Income taxes		49,733			40,159
Other taxes		57,454			56,078
Total		539,355			540,731
OPERATING INCOME		148,502			123,088
OTHER INCOME (DEDUCTIONS):
Income taxes		(3,770	)		798
Allowance for equity funds used during construction		4,186			—
Other income (Note 15)		15,903			4,825
Other expense (Note 15)		(6,124	)		(6,259	)
Total		10,195			(636	)
INTEREST DEDUCTIONS:
Interest on long-term debt		67,643			68,134
Interest on short-term borrowings		3,716			2,722
Debt discount, premium and expense		2,383			1,549
Capitalized interest		(2,256	)		(9,061	)
Total		71,486			63,344
NET INCOME	$	87,211		$	59,108

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

ASSETS

	June 30,			December 31,
	2004			2003
	(Dollars in Thousands)
UTILITY PLANT:
Electric plant in service and held for future use	$	8,950,002		$	8,826,033
Less accumulated depreciation and amortization		3,156,436			3,089,645
Total		5,793,566			5,736,388
Construction work in progress		169,458			187,478
Intangible assets, net of accumulated amortization		100,712			94,181
Nuclear fuel, net of accumulated amortization		52,347			52,011
Utility plant — net		6,116,083			6,070,058
INVESTMENTS AND OTHER ASSETS:
Notes receivable from associated companies (Notes 5 and 17)		498,177			497,865
Decommissioning trust accounts		253,522			240,645
Assets from risk management and trading activities — long-term (Note 10)		31,301			18,001
Other assets		71,742			64,119
Total investments and other assets		854,742			820,630
CURRENT ASSETS:
Cash and cash equivalents		243,892			112,002
Accounts receivable:
Service customers		184,760			190,884
Other (Note 17)		77,806			67,540
Allowance for doubtful accounts		(3,255	)		(3,743	)
Accrued utility revenues		109,627			71,501
Materials and supplies, at average cost		79,654			80,682
Fossil fuel, at average cost		25,972			28,360
Assets from risk management and trading activities (Note 10)		92,617			52,448
Other		9,805			6,969
Total current assets		820,878			606,643
DEFERRED DEBITS:
Regulatory assets		167,493			164,804
Unamortized debt issue costs		23,102			19,797
Other		71,843			73,056
Total deferred debits		262,438			257,657
TOTAL ASSETS	$	8,054,141		$	7,754,988

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)

CAPITALIZATION AND LIABILITIES

	June 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		832,779			830,569
Accumulated other comprehensive income/(loss):
Minimum pension liability adjustment		(57,158	)		(57,158	)
Derivative instruments		30,235			5,253
Common stock equity		2,230,822			2,203,630
Long-term debt less current maturities		2,450,980			2,135,606
Total capitalization		4,681,802			4,339,236
CURRENT LIABILITIES:
Current maturities of long-term debt		265,707			487,067
Accounts payable		155,689			131,383
Accrued taxes		144,716			90,474
Accrued interest		33,202			42,702
Customer deposits		48,651			45,481
Deferred income taxes		631			631
Liabilities from risk management and trading activities (Note 10)		81,177			58,138
Other		58,614			60,008
Total current liabilities		788,387			915,884
DEFERRED CREDITS AND OTHER:
Deferred income taxes		1,282,558			1,248,397
Liabilities from risk management and trading activities — long-term (Note 10)		5,308			4,502
Regulatory liabilities		523,880			510,423
Unamortized gain — sale of utility plant		52,621			54,909
Customer advances for construction		56,526			52,783
Pension liability		186,780			160,639
Liability for asset retirement		242,687			234,440
Other		233,592			233,775
Total deferred credits and other		2,583,952			2,499,868
COMMITMENTS AND CONTINGENCIES (Notes 5, 12 and 13) TOTAL LIABILITIES AND EQUITY	$	8,054,141		$	7,754,988

See Notes to Condensed Financial Statements.

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

	Six Months
	Ended June 30,
	2004			2003
	(Dollars in Thousands)
Cash Flows from Operating Activities:
Net Income	$	87,211		$	59,108
Items not requiring cash:
Depreciation and amortization		177,233			192,114
Nuclear fuel amortization		14,501			14,858
Allowance for equity funds used during construction		(4,186	)		--
Deferred income taxes		8,770			(20,526	)
Change in mark-to-market valuations		4,423			(15,072	)
Changes in certain current assets and liabilities:
Accounts receivable		(4,630	)		106,571
Accrued utility revenues		(38,126	)		(33,565	)
Materials, supplies and fossil fuel		3,416			(3,455	)
Other current assets		(2,836	)		8,034
Accounts payable		28,686			25,121
Accrued taxes		54,242			62,617
Accrued interest		(9,500	)		204
Other current liabilities		1,776			4,469
Increase in regulatory assets		(5,342	)		(4,565	)
Change in risk management trading — assets		7,203			6,385
Change in customer advances		3,743			(681	)
Change in pension liability		26,141			(13,157	)
Change in other long-term assets		7,007			(10,629	)
Change in other long-term liabilities		6,223			44,459
Net cash flow provided by operating activities		365,955			422,290
Cash Flows from Investing Activities:
Trust fund for bond redemption		—			(54,150	)
Capital expenditures		(224,259	)		(212,021	)
Capitalized interest		(2,256	)		(9,061	)
Loans to associated companies		(312	)		(497,500	)
Other		(13,345	)		(1,066	)
Net cash flow used for investing activities		(240,172	)		(773,798	)
Cash Flows from Financing Activities:
Issuance of long-term debt		476,240			491,654
Repayment and reacquisition of long-term debt		(385,133	)		(34,408	)
Dividends paid on common stock		(85,000	)		(85,000	)
Net cash flow provided by financing activities		6,107			372,246
Net increase in cash and cash equivalents		131,890			20,738
Cash and cash equivalents at beginning of period		112,002			42,549
Cash and cash equivalents at end of period	$	243,892		$	63,287
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest)	$	78,604		$	61,463
Income taxes paid/(refunded)	$	(1,726	)	$	729

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 June 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; therefore, $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 payments due on total long-term debt and capitalized lease requirements as of June 30, 2004:

• $166 million in 2004;

• $459 million in 2005;

• $84 million in 2006;

• $174 million in 2007;

• $0 million in 2008; and

• $1.843 billion thereafter.

5. Regulatory Matters

Electric Industry Restructuring

State

     Overview of Pending Rate Case

     On June 27, 2003, we filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in our annual retail electricity revenues, to become effective July 1, 2004. An ACC ALJ has issued various procedural orders staying the existing schedule until at least August 18, 2004, as the parties continue settlement discussions. Based on these recent procedural orders, hearings could begin no earlier than mid to late September 2004. The major components of the request are described under “General Rate Case and Retail Rate Adjustment Mechanisms” below.

1999 Settlement Agreement

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

• We have reduced rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. Based on the price reductions authorized in the 1999 Settlement Agreement, there

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	were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; approximately $28 million ($17 million after taxes), effective July 1, 2002; and approximately $29 million ($18 million after taxes), effective July 1, 2003. For customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.
•	Unbundled rates being charged by 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, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor us was prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constituted an emergency, such as an inability to finance on reasonable terms; material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.
•	We 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 and Retail Rate Adjustment Mechanisms” below.
•	Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory.

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• Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also states that we will not be allowed to recover $183 million net present value (in 1999 dollars) ($234 million pre-tax) of the $533 million. The 1999 Settlement Agreement provides that we will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As discussed below under “General Rate Case and Retail Rate Adjustment Mechanisms,” we are seeking to recover amounts written off by us as a result of the 1999 Settlement Agreement.

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

Retail Electric Competition Rules

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

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

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

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

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

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• 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 affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of our property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute.

Provider of Last Resort Obligation

     Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are, under the Rules, the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. There can be no assurance that we would be able to fully recover the costs of this power. See “General Rate Case and Retail Rate Adjustment Mechanisms” below for a discussion of retail rate adjustment mechanisms that were the subject of ACC hearings in April 2003.

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     Track A Order

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

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

• 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.

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

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

     Track B Order

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

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

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

(1)	Pinnacle West Energy agreed to provide 1,700 MW in July through September of 2003 and in June through September of 2004, 2005 and 2006, by means of a unit contingent contract.
(2)	PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.
(3)	Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.

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     ACC Financing Order

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

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

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

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

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

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

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

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

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

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

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

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• Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy’s (a) West Phoenix Unit 5, located in Phoenix, and (b) Silverhawk plant, located near Las Vegas; and

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

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

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

     General Rate Case and Retail Rate Adjustment Mechanisms

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

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

• complying with the provisions of the 1999 Settlement Agreement;

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

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

• obtaining rate recognition of the PWEC Dedicated Assets;

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

• recovering restructuring and compliance costs associated with the Rules.

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

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	Annual Revenue		Percent
Increase in base rates	$	166.8		9.3	%
Rules compliance charge		8.3		0.5	%
Total increase	$	175.1		9.8	%

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

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

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

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

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

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

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

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

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

• the ACC “litigation” staff;

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

• other approved rate case interveners.

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

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

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

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

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

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

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

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

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

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

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

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

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

     Estimated Timeline We have asked the ACC to approve the requested rate increase by July 1, 2004. Hearings on the rate case were previously scheduled to begin on May 25, 2004. On April 15, 2004, the ACC ALJ issued a procedural order revising the schedule and timing of the rate case. On April 29, 2004, the ACC ALJ issued an order staying the existing procedural schedule for 30 days while the parties discuss settlement. The ALJ issued subsequent procedural orders continuing the stay through at least August 18, 2004 and indicating that she would schedule a future procedural conference on the status of settlement discussions. Based on these recent procedural orders, hearings could begin no earlier than mid to late September 2004.

     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 need 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 current general rate case before the ACC.

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

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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 expects 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.

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.

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” (Act). One feature of the Act is a government subsidy for prescription drug costs provided the benefit plan is considered actuarially equivalent to Medicare Part D. Pinnacle West believes that its plan is considered actuarially equivalent to Medicare Part D, and thus would qualify for the federal subsidy.

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     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 for companies that sponsor postretirement health care benefit plans that provide prescription drug benefits. The guidance allows a retroactive or prospective adoption and is effective July 1, 2004. Although our current financial statements do not reflect any amount for the subsidy, Pinnacle West estimates a reduction in Pinnacle West’s accumulated postretirement benefit obligation of approximately $65 million. Based upon various assumptions, we estimate an annual after-tax reduction in our net periodic postretirement benefit expense of approximately $4 million, excluding amounts capitalized as construction overhead or billed to electric plant participants.

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

	Pension Benefits												Other Benefits
	Three Months						Six Months						Three Months						Six Months
	Ended June 30,						Ended June 30,						Ended June 30,						Ended June 30,
	2004			2003			2004			2003			2004			2003			2004			2003
Service cost-benefits earned during the period	$	11		$	9		$	22		$	18		$	5		$	4		$	10		$	8
Interest cost on benefit obligation		21			19			43			37			8			7			16			15
Expected return on plan assets		(21	)		(16	)		(42	)		(31	)		(6	)		(4	)		(11	)		(9	)
Amortization of:
Transition (asset)/obligation		(1	)		(1	)		(2	)		(2	)		1			1			1			1
Prior service cost		1			1			1			1			—			—			—			—
Net actuarial loss		4			4			9			9			3			2			5			5
Net periodic benefit cost	$	15		$	16		$	31		$	32		$	11		$	10		$	21		$	20
Our share of costs charged to expense	$	6		$	6		$	12		$	12		$	4		$	4		$	8		$	8

Contributions

     The United States 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 currently plans to contribute in the third quarter. Pinnacle West has contributed approximately $14 million to the other postretirement benefits plan in 2004 through June. Our share of these contributions is approximately 89%.

7. Business Segments

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

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

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

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2004			2003		2004			2003
Operating Revenues:
Regulated electricity	$	524		$	504	$	944		$	886
Marketing and trading		46			29		67			79
Total	$	570		$	533	$	1,011		$	965
Net Income (Loss):
Regulated electricity	$	55		$	42	$	93		$	56
Marketing and trading		(1	)		1		(6	)		3
Total	$	54		$	43	$	87		$	59

	As of		As of
	June 30, 2004		December 31, 2003
Assets:
Regulated electricity	$	8,029	$	7,747
Marketing and trading		25		8
Total	$	8,054	$	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

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any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities.

     In 1986, we entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs.

     We are exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that we do not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of June 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. 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 six months ended June 30, 2004 and 2003 were comprised of the following (dollars in thousands):

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	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2004			2003		2004		2003
Gains on the ineffective portion of derivatives qualifying for hedge accounting	$	124		$	4,329	$	1,535	$	5,893
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		(17	)		—		63		—
Gains from the discontinuance of cash flow hedges		—			—		575		—

     As of June 30, 2004, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions was approximately three years. During the twelve months ending June 30, 2005, we estimate that a net gain of $32 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect on earnings of market price changes for the related hedged transactions.

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

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

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

     The following table summarizes our assets and liabilities from risk management and trading activities at June 30, 2004 and December 31, 2003 (dollars in thousands):

June 30, 2004

	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated
Electricity:
Mark-to-market	$	70,000	$	24,095	$	(27,609	)	$	(3,417	)	$	63,069
Options at cost and margin account		—		4,898		(27,122	)		—			(22,224	)
Marketing and Trading:
Mark-to-market		22,617		2,308		(26,446	)		(1,891	)		(3,412	)
Total	$	92,617	$	31,301	$	(81,177	)	$	(5,308	)	$	37,433

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December 31, 2003

	Current				Current			Other			Net Asset/
	Assets		Investments		Liabilities			Liabilities			(Liability)
Regulated
Electricity:
Mark-to-market	$	44,079	$	5,900	$	(47,268	)	$	(3,028	)	$	(317	)
Options		—		12,101		—			—			12,101
Marketing and Trading:
Mark-to-market		8,369		—		(10,870	)		(1,474	)		(3,975	)
Total	$	52,448	$	18,001	$	(58,138	)	$	(4,502	)	$	7,809

     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. No collateral was provided to counterparties at June 30, 2004 and December 31, 2003. Collateral provided to us by counterparties was $15 million at June 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 and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

11. Comprehensive Income

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

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	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2004			2003		2004			2003
Net income	$	53,858		$	43,175	$	87,211		$	59,108
Other comprehensive income:
Minimum pension liability adjustment, net of tax		—			—		—			(112	)
Unrealized gain on derivative instruments, net of tax (a)		10,802			11,976		29,117			20,628
Reclassification of realized (gain) loss to income, net of tax (b)		(3,005	)		3,457		(4,135	)		1,537
Total other comprehensive income		7,797			15,433		24,982			22,053
Comprehensive income	$	61,655		$	58,608	$	112,193		$	81,161

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

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station — Spent Fuel and Waste Disposal

     Nuclear power plant 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 June 30, 2004, we had spent $8 million and recorded a liability of $42 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 $50 million and are seeking recovery of these costs through future rates (see “General Rate Case and Retail Rate Mechanisms” in Note 5).

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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 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 Litigation On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present. State of California v. British Columbia Power Exchange et al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint has been dismissed by the FERC and the State of California is now appealing the matter to the Ninth Circuit Court of Appeals. In addition, the State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including 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.

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     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.

Natural Gas Supply

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

     On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement. In order for us and Pinnacle West Energy to meet our natural gas supply and capacity requirements, we 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.

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. We and Pinnacle West are currently negotiating with the EPA regarding the performance of remedial

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investigation activities of our facilities. Because the ultimate remediation requirements are not yet finalized, we cannot currently estimate the expenditures which may be required.

Asset Purchase Agreement

     See Note 5 for a description of an asset purchase agreement between us and PPL Sundance.

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.”

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     The following chart compares our net income and stock compensation expense for the three and six months ended June 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 June 30, 2004 (dollars in thousands):

	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2004		2003		2004		2003
Net income, as reported	$	53,858	$	43,175	$	87,211	$	59,108
Add: Stock compensation expense included in reported net income (net of tax)		192		232		412		328
Deduct: Total stock compensation expense determined under fair value method (net of tax)		370		412		792		694
Pro forma net income	$	53,680	$	42,995	$	86,831	$	58,742

15. Other Income and Other Expense

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

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2004			2003			2004			2003
Other income:
Interest income	$	5,015		$	3,210		$	10,053		$	3,644
Asset sales		(1,189	)		21			2,462			302
Investment gains – net		350			—			2,397			578
Miscellaneous		492			131			991			301
Total other income	$	4,668		$	3,362		$	15,903		$	4,825
Other expense:
Non-operating costs(a)	$	(2,310	)	$	(2,970	)	$	(4,542	)	$	(5,577	)
Asset sales		1,871			(268	)		(268	)		(918	)
Investment losses – net		—			(326	)		—			—
Miscellaneous		(781	)		(179	)		(1,314	)		236
Total other expense	$	(1,220	)	$	(3,743	)	$	(6,124	)	$	(6,259	)

(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 June 30, 2004, approximately $200 million of letters of credit were

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outstanding to support existing pollution control bonds of approximately $200 million. See Note 4 for more information. The letters of credit are available to fund the payment of principal and interest of such debt obligations. 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 Palo Verde sale leaseback transactions). These letters of credit expire in 2005. Additionally, we have approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2004. We intend to provide from either 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 Ended				Six Months Ended
	June 30,				June 30,
	2004		2003		2004		2003
Electric operating revenues:
Pinnacle West – marketing and trading	$	4	$	2	$	8	$	3
Pinnacle West Energy		—		—		1		—
Total	$	4	$	2	$	9	$	3
Purchased power and fuel costs:
Pinnacle West Energy (a)	$	19	$	25	$	29	$	39
Total	$	19	$	25	$	29	$	39
Other:
Pinnacle West Energy interest income (b)	$	4	$	—	$	9	$	—
Total	$	4	$	—	$	9	$	—

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	As of
	June 30,			As of December 31,
	2004			2003
Net intercompany receivables/(payables):
Pinnacle West Energy (b)	$	456		$	463
Pinnacle West – marketing and trading		27			16
APS Energy Services		13			10
Pinnacle West		(6	)		(8	)
Total	$	490		$	481

(a)	Includes a debit of $6 million related to mark-to-market on an intercompany contract for the three months ended June 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

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

Introduction

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

Overview

     We are a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona. Through our marketing and trading division, we generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading division also sells, in the wholesale market, Pinnacle West Energy’s generation output that is not needed for our Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. Our 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.

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

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BUSINESS SEGMENT

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

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

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

     The following table summarizes net income by business segment for the three and six months ended June 30, 2004 and the comparable prior year period (dollars in millions):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2004			2003		2004			2003
Regulated electricity	$	55		$	42	$	93		$	56
Marketing and trading		(1	)		1		(6	)		3
Net income	$	54		$	43	$	87		$	59

Results of Operations

     General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs.

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

     Our net income for the three months ended June 30, 2004 was $54 million compared with $43 million for the prior year period. The $11 million increase in the period-to-period comparison reflects the following changes in earnings by segment:

• Regulated Electricity Segment – Net income increased approximately $13 million primarily due to lower regulatory asset amortization; customer growth; and lower purchased power and fuel costs resulting from lower hedged fuel and power prices. These positive factors were partially offset by higher costs related to higher replacement power costs from unplanned plant outages due to higher market prices; a retail electricity price reduction; and higher depreciation expense related to increased delivery and other assets.

• Marketing and Trading Segment – Net income decreased approximately $2 million primarily due to lower unit 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	$	11		$	7
Decreased purchased power and fuel costs due to lower hedged fuel and power prices		10			6
Higher replacement power costs from unplanned plant outages due to higher market prices		(8	)		(5	)
Retail electricity price reduction effective July 1, 2003		(7	)		(4	)
Miscellaneous factors, net		(1	)		(1	)
Net increase in regulated electricity segment gross margin		5			3
Marketing and trading segment gross margin:
Higher mark-to-market gains for future delivery due to higher forward prices for wholesale electricity		2			1
Lower realized margins on wholesale sales primarily due to lower unit margins		(6	)		(3	)
Net decrease in marketing and trading segment gross margin		(4	)		(2	)
Net increase in regulated electricity and marketing and trading segments’ gross margins		1			1
Depreciation and amortization decreases (increases):
Decreased regulatory asset amortization		13			8
Increased delivery and other assets		(5	)		(3	)
Lower interest expense primarily due to lower debt balances		2			1
Miscellaneous items, net		4			4
Net increase in income	$	15		$	11

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Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $19 million higher for the three months ended June 30, 2004 compared with the prior year period, primarily as a result of:

• a $28 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

• a $7 million decrease in retail revenues related to a reduction in retail electricity prices; and

• a $2 million decrease in retail revenues related to weather.

Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $17 million higher for the three months ended June 30, 2004 compared with the prior year period, primarily as a result of:

• $10 million of higher realized wholesale revenues primarily due to higher prices and higher volumes;

• a $5 million increase from generation sales other than Native Load primarily due to higher prices and sales volumes; and

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

Operating Results – Six-month period ended June 30, 2004 compared with the six-month period ended June 30, 2003

     Our net income for the six months ended June 30, 2004 was $87 million compared with $59 million for the prior year period. The $28 million increase in the period-to-period comparison reflects the following changes in earnings by segment:

• Regulated Electricity Segment – Net income increased approximately $37 million primarily due to lower purchased power and fuel costs resulting from lower hedge gas and power prices; customer growth and favorable weather; lower regulatory asset amortization; and higher other income primarily due to increased interest income. These positive factors were partially offset by higher replacement power costs from plant outages due to higher market prices and more unplanned outages; a retail electricity price reduction; and higher depreciation expense related to increased delivery and other assets.

• Marketing and Trading Segment – Net income decreased approximately $9 million primarily due to lower unit 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:
Decreased purchased power and fuel costs due to lower hedged gas and power prices	$	36		$	22
Higher retail sales volumes due to customer growth, excluding weather effects		24			15
Effects of weather on retail sales		10			6
Higher replacement power costs from plant outages due to higher market prices and more unplanned outages		(17	)		(10	)
Retail electricity price reduction effective July 1, 2003		(13	)		(8	)
Miscellaneous factors, net		(1	)		(1	)
Net increase in regulated electricity segment gross margin		39			24
Marketing and trading segment gross margin:
Lower realized margins on wholesale sales primarily due to lower unit margins		(14	)		(8	)
Lower mark-to-market gains for future delivery		(1	)		(1	)
Net decrease in marketing and trading segment gross margin		(15	)		(9	)
Net increase in regulated electricity and marketing and trading segments’ gross margins		24			15
Higher interest expense primarily due to lower capitalized interest		(4	)		(2	)
Higher other income primarily due to increased interest income		11			7
Depreciation and amortization decreases (increases):
Decreased regulatory asset amortization		25			15
Increased delivery and other assets		(10	)		(5	)
Miscellaneous items, net		(4	)		(2	)
Net increase in income	$	42		$	28

Regulated Electricity Segment Revenues

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

• a $48 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

• a $16 million increase in retail revenues related to weather;

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

• a $6 million increase due to miscellaneous factors.

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Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $12 million lower for the six months ended June 30, 2004 compared with the prior year period, primarily as a result of:

• a $28 million decrease from generation sales other than Native Load primarily due to lower sales volumes and lower prices;

• $17 million of higher realized wholesale revenues primarily due to higher prices and higher volumes; and

• $1 million in lower mark-to-market gains for future-period deliveries.

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Liquidity and Capital Resources

       Capital Expenditure Requirements

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

	Six Months
	Ended June 30,		Estimated
	2004		2004		2005		2006
Delivery	$	161	$	326	$	390	$	453
Generation (a)(b)		54		108		350		202
Other (c)		9		29		30		18
Total	$	224	$	463	$	770	$	673

(a)	As discussed in Note 5 under “General Rate Case and Retail Rate Adjustment Mechanisms,” as part of our general rate case, we have requested rate base treatment of the PWEC Dedicated Assets. Pinnacle West Energy’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 APS and PPL Sundance Energy, LLC.
(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 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

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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 six months ended June 30, 2004:

• Our purchased power and fuel commitments increased approximately $154 million with respect to 2004 payment 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.

     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 June 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.

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     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 August 4, 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 the mortgage and deed of trust.

     Debt Provisions

     Our debt covenants related to our 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 June 30, 2004, the ratio was approximately 54%. 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.

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     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 June 30, 2004 our common equity ratio was approximately 45%.

     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. 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.

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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.

     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 United States 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 plans to contribute in the third quarter. Pinnacle West has contributed approximately $14 million to the other postretirement benefits plan in 2004 through June.

     Critical Accounting Policies

     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting 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.

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Business Outlook

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

     General Rate Case

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

     Wholesale Power Market Conditions

     The marketing and trading division focuses primarily on managing our 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, 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

     General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are 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 Growth Customer 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 3.6% per year from 2004 to 2006. We currently estimate that total retail electricity sales in kilowatt-hours will grow 4.8% 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 six-month period ended June 30, 2004 compared with the prior year period was 3.6%.

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     Retail Rate Changes As part of the 1999 Settlement Agreement, we agreed to a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. The final price reduction was implemented July 1, 2003. See “1999 Settlement Agreement” in Note 5 for further information. In addition, the Company has requested a 9.8% retail rate increase to be effective July 1, 2004. See “General Rate Case and Retail Rate Adjustment Mechanisms” in Note 5 for further information.

     Other Factors Affecting Future Financial Results

     Purchased Power and Fuel Costs Purchased 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 Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to 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 Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for us, was 9.3% of assessed value for 2003 and 9.7% for 2002.

     Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation. 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 Competition The 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

45

a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory.

     General Our 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;

• 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

46

	transmission construction in the region, which could affect customer growth and the cost of power supplies;
•	the cost of debt and equity capital and access to capital markets;
•	our ability to compete successfully outside traditional regulated markets (including the wholesale market);
•	the performance of our marketing and trading activities due to volatile market liquidity and deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);
•	changes in accounting principles generally accepted in the United States of America;
•	the performance of the stock market and the changing interest rate environment, which affect the amount of our required contributions to our pension plan and nuclear decommissioning trust funds, as well as our reported costs of providing pension and other postretirement benefits;
•	technological developments in the electric industry;
•	conservation programs; and
•	other uncertainties, all of which are difficult to predict and many of which are beyond our control.

Item 3. Market Risks

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

     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

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allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

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

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

	Six Months Ended					Six Months Ended
	June 30, 2004					June 30, 2003
	Regulated		Marketing and			Regulated			Marketing 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		11		1			6			(1	)
Changes in cash flow hedges recorded in OCI		48		—			34			—
Ineffective portion of changes in fair value recorded in earnings		1		—			6			—
Mark-to-market losses realized during the period		3		—			7			—
Mark-to-market of net positions at end of period	$	63	$	(3	)	$	3		$	(1	)

     The tables below show the fair value of maturities of our regulated electricity and trading derivative contracts (dollars in millions) at June 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	$	19	$	27	$	8	$	54
Prices provided by other external sources		8		1		—		9
Prices based on models and other valuation methods		—		—		—		—
Total by maturity	$	27	$	28	$	8	$	63

Marketing and Trading

Source of Fair Value	2004			2005			2006			2007		Total fair value
Prices actively quoted	$	3		$	—		$	—		$	—	$	3
Prices provided by other external sources		—			1			1			—		2
Prices based on models and other valuation methods		(5	)		(2	)		(1	)		—		(8	)
Total by maturity	$	(2	)	$	(1	)	$	—		$	—	$	(3	)

     The table below shows the impact that hypothetical price movements of 10% would have had on the market value of our risk management and trading assets and liabilities included on the Condensed Balance Sheets at June 30, 2004 (dollars in millions).

	June 30, 2004
	Gain (Loss)
Commodity	Price Up 10%			Price Down 10%
Mark-to-market changes reported in earnings (a):
Electricity	$	(1	)	$	1
Natural gas		—			—
Mark-to-market changes reported in OCI (b):
Electricity		7			(7	)
Natural gas		34			(34	)
Total	$	40		$	(40	)

(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

49

substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

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

Item 4. Controls and Procedures

     (a) Evaluation of Disclosure Controls and Procedures

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

     (b) Change in Internal Control over Financial Reporting

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

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PART II – OTHER INFORMATION

Item 5. Other Information Construction and Financing Programs

Construction and Financing Programs

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

Regulatory Matters

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

Environmental Matters

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

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Item 6. Exhibits and Reports on Form 8-K

     (a) Exhibits

Exhibit No.	Description
3.1	Bylaws, amended as of June 23, 2004
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	Certificate 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
3.2	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

52

		Originally Filed		Date
Exhibit No.	Description	as Exhibit:	File No. a	Effective
10.1	Asset Purchase Agreement by and between PPL Sundance Energy, LLC, as Seller, and the Company, as Purchaser, dated as of June 1, 2004	10.1 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.2 b	Form of Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.2 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.3 b	Form of Performance Share Agreement under Pinnacle West Capital Corporation 2002 Long- Term Incentive Plan	10.3 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.4 b	Form of Stock Ownership Incentive Agreement under Pinnacle West Capital Corporation 2002 Long- Term Incentive Plan	10.4 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.5 b	Form of Restricted Stock Award Agreement under Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan	10.5 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04

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

^bAgreements, substantially identical in all material respects to this Exhibit, have been entered into with officers and key employees of the Company. Although such additional documents may differ in other respects (such as stock amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

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     (b) Reports on Form 8-K

     During the quarter ended June 30, 2004, and the period from July 1 through August 6, 2004, we filed the following reports on Form 8-K:

     Report dated March 31, 2004 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7, Item 9 and Item 12).

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

     Report dated May 26, 2004 regarding the Asset Purchase Agreement entered into between us and PPL Sundance Energy, LLC and the issuance of a procedural order extending the stay of the procedural schedule and discovery in our general rate case (Item 5).

     Report dated June 14, 2004 regarding a shutdown of the Palo Verde units, the issuance by an ACC ALJ of a procedural order extending the stay of the procedural schedule in our general rate case and a FERC audit of us and our affiliates (Item 5).

     Report dated June 24, 2004 containing the exhibits to our Registration Statement on Form S-3 (No. 333-106772)(Item 7).

     Report dated June 30, 2004 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7, Item 9 and Item 12).

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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: August 6, 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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Exhibit Index

     (a) Exhibits

Exhibit No.	Description
3.1	Bylaws, amended as of June 23, 2004
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	Certificate 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
3.2	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

^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.

		Originally Filed		Date
Exhibit No.	Description	as Exhibit:	File No. a	Effective
10.1	Asset Purchase Agreement by and between PPL Sundance Energy, LLC, as Seller, and the Company, as Purchaser, dated as of June 1, 2004	10.1 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.2 a	Form of Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.2 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.3 a	Form of Performance Share Agreement under Pinnacle West Capital Corporation 2002 Long- Term Incentive Plan	10.3 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.4 a	Form of Stock Ownership Incentive Agreement under Pinnacle West Capital Corporation 2002 Long- Term Incentive Plan	10.4 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04
10.5 a	Form of Restricted Stock Award Agreement under Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan	10.5 to Pinnacle West’s June 2004 Form 10-Q Report	1-8962	8-9-04

     ^a Agreements, substantially identical in all material respects to this Exhibit, have been entered into with officers and key employees of the Company. Although such additional documents may differ in other respects (such as stock amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

EX-3.1

                                                                     EXHIBIT 3.1


                                     BYLAWS
                                       OF
                         ARIZONA PUBLIC SERVICE COMPANY
                          (AMENDED AS OF JUNE 23, 2004)

                            I. REFERENCES; SENIORITY

      1.01. REFERENCES. Any reference herein made to law will be deemed to refer
to the law of the State of Arizona, including any applicable provision or
provisions of Chapters 1-17 and Chapter 23 of Title 10, Arizona Revised Statutes
(or its successor), as at any given time in effect. Any reference herein made to
the Articles will be deemed to refer to the applicable provision or provisions
of the Articles of Incorporation of the Company, and all amendments thereto, as
at any given time on file with the Arizona Corporation Commission (this
reference to that Commission being intended to include any successor to the
incorporating and related functions being performed by that Commission at the
date of the initial adoption of these Bylaws).

      1.02. SENIORITY. Except as indicated in Part X of these Bylaws, the law
and the Articles (in that order of precedence) will in all respects be
considered senior and superior to these Bylaws, with any inconsistency to be
resolved in favor of the law and the Articles (in that order of precedence), and
with these Bylaws to be deemed automatically amended from time to time to
eliminate any such inconsistency which may then exist.

      1.03. SHAREHOLDERS OF RECORD. Except as otherwise required by law and
subject to any procedure established by the Company pursuant to Arizona Revised
Statutes Section 10-723 (or any comparable successor provision), the word
"shareholder" as used herein shall mean one who is a holder of record of shares
of capital stock in the Company.

                            II. SHAREHOLDERS MEETINGS

      2.01. ANNUAL MEETINGS. An annual meeting of shareholders shall be held for
the election of directors at such date, time and place, either within or without
the State of Arizona, as may be designated by resolution of the Board of
Directors from time to time. Any other proper business may be transacted at the
annual meeting. A special meeting may be called and held in lieu of an annual
meeting pursuant to the provisions of Section 2.02 below, and the same
proceedings (including the election of directors) may be conducted thereat as at
a regular meeting. Any director elected at any annual meeting, or special
meeting in lieu of an annual meeting, will continue in office until the election
of his or her successor, subject to his or her (a) earlier resignation pursuant
to Section 6.01 below, (b) removal pursuant to Section 3.12 below, or (c) death
or disqualification.

      2.02. SPECIAL MEETINGS. Except as otherwise required by law, special
meetings of the shareholders may be held whenever and wherever called by the
Chairman of the

Board, the President, or a majority of the Board of Directors, but such special
meetings may not be called by any other person or persons. Business transacted
at any special meeting of shareholders shall be limited to the purposes stated
in the notice.

      2.03. NOTICE. Notice of any meeting of the shareholders will be given as
provided by law to each shareholder entitled to vote at such meeting and, if
required by law, to each other shareholder of the Company.  Any such notice may
be waived as provided by law.

      2.04. RIGHT TO VOTE. For each meeting of the shareholders, the Board of
Directors will fix in advance a record date as contemplated by law, and the
shares of stock and the shareholders "entitled to vote" (as that or any similar
term is herein used) at any meeting of the shareholders will be determined as of
the applicable record date. If no record date is so fixed by the Board of
Directors, the record date for determination of shareholders shall be as
provided by law. The Secretary (or in his or her absence an Assistant Secretary)
will see to the making and production of any record of shareholders entitled to
vote or otherwise entitled to notice of shareholders meetings, in either case
which is required by law. Any voting entitlement may be exercised through proxy,
or in such other manner as specifically provided by law, in accordance with the
applicable law. In the event of contest, the burden of proving the validity of
any undated or irrevocable proxy will rest with the person seeking to exercise
the same. A telegram, cablegram, or facsimile appearing to have been transmitted
by a shareholder (or by his or her duly authorized attorney-in-fact) or other
means of voting by telephone or electronic transmission may be accepted as a
sufficiently written and executed proxy if otherwise permitted by law.

      2.05. RIGHT TO ATTEND. Except only to the extent of persons designated by
the Board of Directors or the Chairman of the meeting to assist in the conduct
of the meeting (as referred to in Sections 2.07 and 2.08 below) and except as
otherwise permitted by the Board or such Chairman, the persons entitled to
attend any meeting of shareholders may be confined to (i) shareholders entitled
to vote thereat and other shareholders entitled to notice of the meeting and
(ii) the persons upon whom proxies valid for purposes of the meeting have been
conferred or their duly appointed substitutes (if the related proxies confer a
power of substitution); provided, however, that the Board of Directors or the
Chairman of the meeting may establish rules limiting the number of persons
referred to in clause (ii) as being entitled to attend on behalf of any
shareholder so as to preclude such an excessively large representation of such
shareholder at the meeting as, in the judgment of the Board or such Chairman,
would be unfair to other shareholders represented at the meeting or be unduly
disruptive of the orderly conduct of business at such meeting (whether such
representation would result from fragmentation of the aggregate number of shares
held by such shareholder for the purpose of conferring proxies, from the naming
of an excessively large proxy delegation by such shareholder or from employment
of any other device). A person otherwise entitled to attend any such meeting
will cease to be so entitled if, in the judgment of the Chairman of the meeting,
such person engages thereat in disorderly conduct impeding the proper conduct of
the meeting in the interests of all shareholders as a group.


                                     - 2 -

      2.06. QUORUM. Except as otherwise provided by law, the Articles or these
Bylaws, at each meeting of shareholders the presence in person or by proxy of
the holders of a majority in voting power of the outstanding shares of stock
entitled to vote at the meeting shall be necessary and sufficient to constitute
a quorum.

      2.07. ELECTION INSPECTORS. The Board of Directors, in advance of any
shareholders meeting may appoint an election inspector or inspectors to act at
such meeting (and any adjournment thereof). If an election inspector or
inspectors are not so appointed, the Chairman of the meeting may or, upon the
request of any person entitled to vote at the meeting will, make such
appointment. If any person appointed as an inspector fails to appear or to act,
a substitute may be appointed by the Chairman of the meeting. If appointed, the
election inspector or inspectors (acting through a majority of them if there be
more than one) will determine the number of shares outstanding, the
authenticity, validity and effect of proxies, the credentials of persons
purporting to be shareholders or persons named or referred to in proxies, and
the number of shares represented at the meeting in person and by proxy; they
will receive and count votes, ballots and consents and announce the results
thereof; they will hear and determine all challenges and questions pertaining to
proxies and voting; and, in general, they will perform such acts as may be
proper to conduct elections and voting with complete fairness to all
shareholders. No such election inspector need be a shareholder of the Company.

      2.08. ORGANIZATION AND CONDUCT OF MEETINGS. Each shareholders meeting will
be called to order and thereafter chaired by the Chairman of the Board if there
then is one; or, if not, or if the Chairman of the Board is absent or so
requests, then by the President; or if both the Chairman of the Board and the
President are unavailable, then by such other officer of the Company or such
shareholder as may be appointed by the Board of Directors. The Secretary (or in
his or her absence an Assistant Secretary) of the Company will act as secretary
of each shareholders meeting; if neither the Secretary nor an Assistant
Secretary is in attendance, the Chairman of the meeting may appoint any person
(whether a shareholder or not) to act as secretary thereat. After calling a
meeting to order, the Chairman thereof may require the registration of all
shareholders intending to vote in person, and the filing of all proxies, with
the election inspector or inspectors, if one or more have been appointed (or, if
not, with the secretary of the meeting). After the announced time for such
filing of proxies has ended, no further proxies or changes, substitutions or
revocations of proxies will be accepted. If directors are to be elected, a
tabulation of the proxies so filed will, if any person entitled to vote in such
election so requests, be announced at the meeting (or adjournment thereof) prior
to the closing of the election polls.

      Absent a showing of bad faith on his or her part, the Chairman of a
meeting will, among other things, have absolute authority to determine the order
of business to be conducted at such meeting and to establish rules for, and
appoint personnel to assist in, preserving the orderly conduct of the business
of the meeting (including any informal, or question and answer, portions
thereof). Rules, regulations or procedures regarding the conduct of the business
of a meeting, whether adopted by the Board of Directors or prescribed by the
Chairman of the meeting, may include, without limitation, the


                                     - 3 -

following: (i) the establishment of an agenda or order of business for the
meeting; (ii) rules and procedures for maintaining order at the meeting and the
safety of those present; (iii) limitations on attendance at or participation in
the meeting to shareholders of record of the Company, their duly authorized and
constituted proxies (subject to Section 2.05) or such other persons as the
Chairman of the meeting shall determine; (iv) restrictions on entry to the
meeting after the time fixed for the commencement thereof; and (v) limitations
on the time allotted to questions or comments by participants. Unless and to the
extent determined by the Board of Directors or the Chairman of the meeting,
meetings of shareholders shall not be required to be held in accordance with the
rules of parliamentary procedure. Any informational or other informal session of
shareholders conducted under the auspices of the Company after the conclusion of
or otherwise in conjunction with any formal business meeting of the shareholders
will be chaired by the same person who chairs the formal meeting, and the
foregoing authority on his or her part will extend to the conduct of such
informal session.

      2.09. VOTING. The number of shares voted on any matter submitted to the
shareholders which is required to constitute their action thereon or approval
thereof will be determined in accordance with applicable law, the Articles, and
these Bylaws, if applicable. No ballot or change of vote will be accepted after
the polls have been declared closed following the ending of the announced time
for voting.

      2.10. SHAREHOLDER APPROVAL OR RATIFICATION. The Board of Directors may
submit any contract or act for approval or ratification at any duly constituted
meeting of the shareholders, the notice of which either includes mention of the
proposed submittal or is waived as provided in Section 2.03 above. Except as
otherwise required by law (e.g., Arizona Revised Statutes Section 10-863), if
any contract or act so submitted is approved or ratified by a majority of the
votes cast thereon at such meeting, the same will be valid and as binding upon
the Company and all of its shareholders as it would be if approved and ratified
by each and every shareholder of the Company.

      2.11. ADJOURNMENTS. Any meeting of shareholders, annual or special, may
adjourn from time to time to reconvene at the same or some other place, and
notice need not be given of any such adjourned meeting if the time and place
thereof are announced at the meeting at which the adjournment is taken. At the
adjourned meeting the Company may transact any business that might have been
transacted at the original meeting. If the adjournment is for more than one
hundred and twenty days, or if after the adjournment a new record date is fixed
for the adjourned meeting, notice of the adjourned meeting shall be given to
each shareholder of record entitled to vote at the meeting.

      2.12. SHAREHOLDER ACTION BY WRITTEN CONSENT. Any action required or
permitted to be taken at a meeting of the shareholders may be taken without a
meeting if one (1) or more consents in writing, setting forth the action so
taken, shall be signed by all of the shareholders entitled to vote with respect
to the subject matter thereof. The consents shall be delivered to the Company
for inclusion in the minutes or filing with the Company's records. Action taken
by consent is effective when the last shareholder signs the consent, unless the
consent specifies a different effective date, except that if,


                                     - 4 -

by law, the action to be taken requires that notice be given to shareholders who
are not entitled to vote on the matter, the effective date shall not be prior to
ten (10) days after the Company shall give such shareholders written notice of
the proposed action, which notice shall contain or be accompanied by the same
material that would have been required if a formal meeting had been called to
consider the action. A consent signed under this section has the effect of a
meeting vote and may be described as such in any document.

                             III. BOARD OF DIRECTORS

      3.01. MEMBERSHIP AND QUALIFICATION. The Board of Directors will have the
exclusive power to increase or decrease its size within the limits fixed in the
Articles (Art. Fifth). Any vacancy occurring in the Board, whether by reason of
death, resignation, disqualification or otherwise, may be filled by the
directors as contemplated by law and as provided in the Articles (Art. Fifth).
Any such increase in the size of the Board, and the filling of any vacancy
created thereby, will require action by a majority of the whole membership of
the Board as comprised immediately before such increase. A person will not
qualify for election or appointment as a director, whether initially or on
re-election and whether by the shareholders at their annual meeting or by the
Board of Directors as contemplated in this Section 3.01, if such person's 72nd
birthday occurs on or has occurred before the date of such election, appointment
or re-election. A person who has been a full-time employee of the Company within
twelve months prior to the date of any election will not qualify for election as
a director on that date unless he or she then remains a full-time employee of
the Company or unless the Board of Directors specifically authorizes the
election of such person (but it is not intended that any such authorization will
extend a person's service on the Board beyond the age limitation set out in the
preceding sentence). A person who has qualified by age or employment status for
his or her most recent election as a director may serve throughout the term for
which such person was elected, notwithstanding the occurrence of his or her 72nd
birthday or cessation of full-time employment by the Company between the date of
such election and the end of such term, subject, however, to his or her
otherwise remaining qualified for such office.

      3.02. REGULAR MEETINGS. A regular annual meeting of the directors is to be
held as soon as practicable after the adjournment of each annual shareholders
meeting either at the place of the shareholders meeting or at such other place
as the directors elected at the shareholders meeting may have been informed of
at or before the time of their election. Regular meetings, other than the annual
ones, may be held at such intervals at such places and at such times as the
Board of Directors may provide.

      3.03. SPECIAL MEETINGS.  Special meetings of the Board of Directors may
be held whenever and wherever called for by the Chairman of the Board, the
President or the number of directors which would be required to constitute a
quorum.

      3.04. NOTICE. No notice need be given of regular meetings of the Board of
Directors. Notice of the time and place (but not necessarily the purpose or all
of the purposes) of any special meeting will be given to each director in person
or by


                                     - 5 -

telephone, or via mail, telegram, facsimile, or other electronic transmission
addressed in the manner appearing on the Company's records. Notice to any
director of any such special meeting will be deemed given sufficiently in
advance when (i) if given by mail, the same is deposited in the United States
mail at least four days before the meeting date, with postage thereon prepaid,
(ii) if given by telegram, the same is delivered to the telegraph office for
fast transmittal at least 48 hours prior to the convening of the meeting, (iii)
if given by facsimile or other electronic transmission, the same is received by
the director or an adult member of his or her office staff or household, at
least 24 hours prior to the convening of the meeting, or (iv) if personally
delivered or given by telephone, the same is handed, or the substance thereof is
communicated over the telephone to the director or to an adult member of his or
her office staff or household, at least 24 hours prior to the convening of the
meeting. Any such notice may be waived as provided by law. No call or notice of
a meeting of directors will be necessary if each of them waives the same in
writing or by attendance. Any meeting, once properly called and noticed (or as
to which call and notice have been waived as aforesaid) and at which a quorum is
formed, may be adjourned to another time and place by a majority of those in
attendance.

      3.05. QUORUM; VOTING. A quorum for the transaction of business at any
meeting or adjourned meeting of the directors will consist of a majority of
those then in office. Any matter submitted to a meeting of the directors will be
resolved by a majority of the votes cast thereon, except as otherwise required
by these Bylaws (Section 3.01 above and Section 3.06 below), by law or by any
applicable Article. Where action by a majority of the whole membership is
required, such requirement will be deemed to relate to a majority of the
directors in office at the time the action is taken. In computing any such
majority, whether for purposes of determining the presence of a quorum or the
adequacy of the vote on any proposed action, any unfilled vacancies at the time
existing in the membership of the Board will be excluded from the computation.

      3.06. EXECUTIVE COMMITTEE. The Board of Directors may, by resolution
adopted by a majority of the whole Board, name three or more of its members as
an Executive Committee. Such Executive Committee will have and may exercise the
powers of the Board of Directors in the management of the business and affairs
of the Company while the Board is not in session, except only as precluded by
law or where action other than by a majority of the votes cast is required by
these Bylaws, or the law (all as referred to in Section 3.05 above), and subject
to such limitations as may be included in any applicable resolution passed by a
majority of the whole membership of the Board. A majority of those named to the
Executive Committee will constitute a quorum.

      3.07. OTHER COMMITTEES. The Board of Directors may designate one or more
additional committees, each committee to consist of one or more of the directors
of the Company. The Board of Directors may designate one or more directors as
alternate members of any committee, who may replace any absent or disqualified
member at any meeting of the committee. Any such committee, to the extent
permitted by law and to the extent provided in the resolution of the Board of
Directors, shall have and may exercise all the powers and authority of the Board
of Directors in the management of the


                                     - 6 -

business and affairs of the Company, and may authorize the seal of the Company
to be affixed to all papers that may require it.

      3.08. COMMITTEE FUNCTIONING. Notice requirements (and related waiver
provisions) for meetings of the Executive Committee and other committees of the
Board will be the same as those set forth in Section 3.04 above for meetings of
the Board of Directors. Except as provided in the next two succeeding sentences,
a majority of those named to the Executive Committee or any other committee of
the Board will constitute a quorum at any meeting thereof (with the effect of
departure of committee members from a meeting and the computation of a majority
of committee members to be in accordance with the applicable policies of Section
3.05 above), and any matter submitted to a meeting of any such committee will be
resolved by a majority of the votes cast thereon. No distinction will be made
among ex-officio or other members of any such committee for quorum, voting or
other purposes, except that the membership of any committee (including the
Executive Committee), in performing any function vested in it as herein
contemplated, may be deemed to exclude any officer or employee of the Company,
in either case, or other person, having a direct or indirect personal interest
in any proposed exercise of such function, whose exclusion for that purpose is
deemed appropriate by a majority of the other members of such committee
proposing to perform such function. All committees are to keep regular minutes
of the transactions of their meetings.

      3.09. ACTION BY TELEPHONE OR CONSENT. Any meeting of the Board or any
committee thereof may be held by conference telephone or similar communications
equipment as permitted by law in which case any required notice of such meeting
may generally describe the arrangements (rather than the place) for the holding
thereof, and all other provisions herein contained or referred to will apply to
such meeting as though it were physically held at a single place. Action may
also be taken by the Board or any committee thereof without a meeting if the
members thereof consent in writing thereto as contemplated by law.

      3.10. PRESUMPTION OF ASSENT. A director of the Company who is present at a
meeting of the Board of Directors, or of any committee when corporate action is
taken is deemed to have assented to the action taken unless either (i) the
director objects at the beginning of the meeting or promptly on the director's
arrival to holding it or transacting business at the meeting; (ii) the
director's dissent or abstention from the action taken is entered in the minutes
of the meeting; or (iii) the director delivers written notice of the director's
dissent or abstention to the presiding officer of the meeting before its
adjournment or to the Company before 5:00 P.M. on the next business day after
the meeting. The right of dissent or abstention is not available to a director
who votes in favor of the action taken.

      3.11. COMPENSATION. By resolution of the Board, the directors may be paid
their expenses, if any, of attendance at each meeting of the Board of Directors,
or of any committee, and may be paid a fixed sum for attendance at each such
meeting and/or a stated salary as a director or committee member. No such
payment will


                                     - 7 -

preclude any director from serving the Company in any other capacity and
receiving compensation therefor.

      3.12. REMOVAL. Any director or the entire Board of Directors may be
removed, with or without cause, only at a special meeting of shareholders called
for that purpose, if the votes cast in favor of such removal exceed the votes
cast against such removal, except that if less than the entire Board of
Directors is to be removed, no one of the directors may be removed if the votes
cast against the director's removal would be sufficient to elect the director if
then cumulatively voted at an election for the class of directors of which the
director is a part.

                             IV. OFFICERS - GENERAL

      4.01. ELECTIONS AND APPOINTMENTS. The directors may elect or appoint one
or more of the officers of the Company contemplated in Part V below. Any such
election or appointment will regularly take place at the annual meeting of the
directors, but elections of officers may be held at any other meeting of the
Board. A person elected or appointed to any office will continue to hold that
office until the election or appointment of his or her successor, subject to
action earlier taken pursuant to Section 4.04 or 6.01 below. Any person may hold
more than one office.

      4.02. ADDITIONAL APPOINTMENTS. In addition to the officers contemplated in
Part V below, the Board of Directors may create other corporate positions, and
appoint persons thereto, with such authority to perform such duties as may be
prescribed from time to time by the Board of Directors, by the President or by
the superior officer of any person so appointed. Notwithstanding such additional
appointments, only those persons whose offices are described in Part V are to be
considered an officer of the Company unless the resolution or other Board action
appointing such person expressly states that such person is to be considered an
officer of the Company. Each of such persons (in the order designated by the
Board or the superior officer of such person) will be vested with all of the
powers and charged with all of the duties of his or her superior officer in the
event of such superior officer's absence or disability.

      4.03. BONDS AND OTHER REQUIREMENTS. The Board of Directors may require any
officer or other appointee to give bond to the Company (with sufficient surety,
and conditioned upon the faithful performance of the duties of his or her office
or position) and to comply with such other conditions as may from time to time
be required of him or her by the Board.

      4.04. REMOVAL OR DELEGATION. Provided that a majority of the whole
membership thereof concurs therein, the Board of Directors may remove any
officer of the Company as provided by law and declare his or her office or
offices vacant or abolished or, in the case of the absence or disability of any
officer or for any other reason considered sufficient, may temporarily delegate
his or her powers and duties to any other officer or to any director. Similar
action may be taken by the Board of Directors in regard to appointees designated
pursuant to Section 4.02 above.


                                     - 8 -

      4.05. SALARIES.  Officer salaries may from time to time be fixed by the
Board of Directors or (except as to his or her own) be left to the discretion
of the Chief Executive Officer or the President. No officer will be prevented
from receiving a salary by reason of the fact that he or she is also a
director of the Company.

                   V. SPECIFIC OFFICERS, FUNCTIONS AND POWERS

      5.01. CHAIRMAN OF THE BOARD. The Board of Directors may elect a Chairman
to serve as a general executive officer of the Company and, if specifically
designated as such by the Board, as the Chief Executive Officer of the Company.
If elected, the Chairman will preside at all meetings of the directors and be
vested with such other powers and duties as the Board may from time to time
delegate to him or her.

      5.02. CHIEF EXECUTIVE OFFICER. Subject to the control of the Board of
Directors exercised as hereinafter provided, the Chief Executive Officer of the
Company will supervise its business and affairs and the performance of their
respective duties by all other officers, by appointees designated pursuant to
Section 4.02 above, and by such additional appointees to such additional
positions (corporate, divisional or otherwise) as the Chief Executive Officer
may designate, with authority on his or her part to delegate the foregoing duty
of supervision to such extent and to such person or persons as may be determined
by the Chief Executive Officer. Except as otherwise indicated from time to time
by resolution of the Board of Directors, its management of the business and
affairs of the Company will be implemented through the office of the Chief
Executive Officer.

      5.03. PRESIDENT AND VICE PRESIDENTS. Unless specified to the contrary by
resolution of the Board of Directors, the President will be the Chief Executive
Officer of the Company. In addition to the supervisory functions above set forth
on the part of the Chief Executive Officer or in lieu thereof if a contrary
specification is made by the Board relative to the Chief Executive Officer, the
President will be vested with such powers and duties as the Board may from time
to time designate. Vice Presidents may be elected by the Board of Directors to
perform such duties as may be designated by the Board or be assigned or
delegated to them by their respective superior officers. The Board may identify
(i) one or more Vice Presidents as "Executive" or "Senior" Vice Presidents and
(ii) the President or any Vice President as "General Manager" of the Company and
the title of any Vice President may include words indicative of his or her
particular area of responsibility and authority. Vice Presidents will succeed to
the responsibilities and authority of the President, in the event of his or her
absence or disability, in the order consistent with their respective titles or
regular duties or as specifically designated by the Board of Directors.

      5.04. TREASURER AND SECRETARY. The Treasurer and Secretary each will
perform all such duties normally associated with his or her office (including,
in the case of the Secretary, the giving of notice and the preparation and
retention of minutes of corporate proceedings and the custody of corporate
records and the seal of the Company) as are not assigned to a Vice President of
the Company, along with such other duties as may be designated by the Board or
be assigned or delegated to them by


                                     - 9 -

their respective superior officers. The Board may appoint one or more Assistant
Treasurers or Assistant Secretaries, each of whom (in the order designated by
the Board or their respective superior officers) will be vested with all of the
powers and charged with all of the duties of the Treasurer or the Secretary (as
the case may be) in the event of his or her absence or disability.

      5.05. SPECIFIC POWERS. Except as may otherwise be specifically provided in
a resolution of the Board of Directors, any of the officers referred to in this
Part V will be a proper officer to authenticate records of the Company and to
sign on behalf of the Company any deed, bill of sale, assignment, option,
mortgage, pledge, note, bond, debenture, evidence of indebtedness, application,
consent (to service of process or otherwise), agreement, indenture or other
instrument of importance to the Company. Any such officer may represent the
Company at any meeting of the shareholders or members of any corporation,
association, partnership, joint venture or other entity in which this Company
then has an interest, and may vote such interest in person or by proxy appointed
by him or her, provided that the Board of Directors may from time to time confer
the foregoing authority upon any other person or persons.

                         VI. RESIGNATIONS AND VACANCIES

      6.01. RESIGNATIONS.  Any director, committee member or officer may
resign from his or her office at any time by written notice as specified in
accordance with Arizona Revised Statutes Sections 10-807 and 10-843.  The
acceptance of a resignation will not be required to make it effective.

      6.02. VACANCIES.  If the office of any director, committee member or
officer becomes  vacant by reason of his or her death, resignation,
disqualification, removal or otherwise, the  Board of Directors may choose a
successor to hold office for the unexpired term.

                      VII. INDEMNIFICATION AND RATIFICATION

      7.01. INDEMNIFICATION. In order to induce qualified persons to serve the
Company (and any other corporation, joint venture, partnership, trust or other
enterprise at the request of the Company) as directors and officers, the Company
shall indemnify any and all of its directors and officers, or former directors
and officers to the fullest extent permitted by applicable law as it presently
exists or may hereafter be amended.

      7.02. RATIFICATION; SPECIAL COMMITTEE. Any transaction involving the
Company, any of its subsidiary corporations or any of its directors, officers,
employees or agents which at any time is questioned in any manner or context
(including a shareholders derivative suit), on the ground of lack of authority,
conflict of interest, misleading or omitted statement of fact or law,
nondisclosure, miscomputation, improper principles or practices of accounting,
inadequate records, defective or irregular execution or any similar ground, may
be investigated and/or ratified (before or after judgment), or an election may
be made not to institute or pursue a claim or legal proceedings on account
thereof or to accept or approve a negotiated settlement with


                                     - 10 -

respect thereto (before or after the institution of legal proceedings), by the
Board of Directors or by a special committee thereof comprised of one or more
disinterested directors (that is, a director or directors who did not
participate in the questioned transaction with actual knowledge of the
questioned aspect or aspects thereof). Such a special committee may be validly
formed and fully empowered to act, in accordance with the purposes and duties
assigned thereto, by resolution or resolutions of the Board of Directors,
notwithstanding (i) the inclusion of Board members who are not disinterested as
aforesaid among those who form a quorum at the meeting or meetings at which one
or more members of such special committee are elected or appointed to the Board
or to such special committee or at which such committee is formed or empowered,
or their inclusion among the directors who vote upon or otherwise participate in
taking any of the foregoing actions, or (ii) the taking of any of such actions
by the disinterested members of the Board (or a majority of such members) whose
number is not sufficient to constitute a quorum or a majority of the membership
of the full Board. Any such special committee so comprised will, to the full
extent consistent with its purposes and duties as expressed in such resolution
or resolutions, have all of the authority and powers of the full Board and its
Executive Committee (the same as though it were the full Board and/or its
Executive Committee in carrying out such purposes and duties) and will function
in accordance with Section 3.08 above. No other provisions of these Bylaws which
may at any time appear to conflict with any provisions of this Section 7.02, and
no defect or irregularity in the formation, empowering or functioning of any
such special committee, will serve to impede, impair or bring into question any
action taken or purported to be taken by such committee or the validity of any
such action. Any ratification of a transaction pursuant to this Section 7.02
will have the same force and effect as if the transaction has been duly
authorized originally. Any such ratification, and any election made pursuant to
this Section 7.02 with respect to claims, legal proceedings or settlements, will
be binding upon the Company and its shareholders and will constitute a bar to
any claim or the execution of any judgment in respect of the transaction
involved in such ratification or election.

                                   VIII. SEAL

      8.01. FORM THEREOF.  The seal of the Company will have inscribed
thereon the name of the Company, the state and year of its incorporation and
the words "SEAL".

                             IX. STOCK CERTIFICATES

      9.01. FORM THEREOF. Each certificate representing stock of the Company
will be in such form conforming to law as may from time to time be approved by
the Board of Directors, and will bear the manual facsimile signatures and seal
of the Company as required or permitted by law.

      9.02. OWNERSHIP. The Company will be entitled to treat the registered
owner of any share as the absolute owner thereof and accordingly, will not be
bound to recognize any beneficial, equitable or other claim to, or interest in,
such share on the part of any other person, whether or not it has notice
thereof, except as may expressly be provided


                                     - 11 -

by Chapter 8 of Title 47, Arizona Revised Statutes (or its successor), as at the
time in effect, or other applicable law.

      9.03. TRANSFERS. Transfer of stock will be made on the books of the
Company only upon surrender of the certificate therefor, duly endorsed by an
appropriate person, with such assurance of the genuineness and effectiveness of
the endorsement as the Company may require, all as contemplated by Chapter 8 of
Title 47, Arizona Revised Statutes (or its successor), as at the time in effect,
and/or upon submission of any affidavit, other document or notice which the
Company considers necessary.

      9.04. LOST CERTIFICATES. In the event of the loss, theft or destruction of
any certificate representing capital stock of this Company, the Company may
issue (or, in the case of any such stock as to which a transfer agent and/or
registrar have been appointed, may direct such transfer agent and/or registrar
to countersign, register and issue) a replacement certificate in lieu of that
alleged to be lost, stolen or destroyed, and cause the same to be delivered to
the owner of the stock represented thereby, provided that the owner shall have
submitted such evidence showing the circumstances of the alleged loss, theft or
destruction, and his or her ownership of the certificate as the Company
considers satisfactory, together with any other factors which the Company
considers pertinent, and further provided that an indemnity agreement and/or
indemnity bond shall have been provided in form and amount satisfactory to the
Company and to its transfer agent and/or registrar, if applicable.

                               X. EMERGENCY BYLAWS

      10.01. EMERGENCY CONDITIONS. The emergency Bylaws provided in this Part X
will be effective in the event of an emergency as prescribed in Arizona Revised
Statutes Section 10-207.D. To the extent not inconsistent with the provisions of
this Part X, these Bylaws will remain in effect during such emergency and upon
its termination these emergency Bylaws will cease to be operative.

      10.02. BOARD MEETINGS. During any such emergency, a meeting of the Board
of Directors or any of its committees may be called by any officer or director
of the Company. Notice of the time and place of the meeting will be given by the
person calling the same to those of the directors whom it may be feasible to
reach by any available means of communication. Such notice will be given so much
in advance of the meeting as circumstances permit in the judgment of the person
calling the same. At any Board or committee meeting held during any such
emergency, a quorum will consist of a majority of those who could reasonably be
expected to attend the meeting if they were willing to do so, but in no event
more than a majority of those to whom notice of such meeting is required to have
been given as above provided.

      10.03. CERTAIN ACTIONS. The Board of Directors, either before or during
any such emergency, may provide and from time to time modify lines of succession
in the event that during such an emergency any or all officers, appointees,
employees or agents of the Company are for any reason rendered incapable of
discharging their duties. The Board, either before or during any such emergency,
may, effective in the emergency,


                                     - 12 -

change the head office or designate several alternative head offices of the
Company, or authorize the officers to do so.

      10.04. LIABILITY. No director, officer, appointee, employee or agent
acting in accordance with these emergency Bylaws will be liable except for
willful misconduct.

      10.05. MODIFICATIONS. These emergency Bylaws will be subject to repeal or
change by further action of the Board of Directors, but no such repeal or change
will modify the provisions of Section 10.04 with respect to action taken prior
to the time of such repeal or change. Any amendment of these emergency Bylaws
may make any further or different provisions that may be practical and necessary
for the circumstances of the emergency.

                                  XI. DIVIDENDS

      11.01. DECLARATION. Subject to such restrictions or requirements as may be
imposed by law or the Company's Articles or as may otherwise be binding upon the
Company, the Board of Directors may from time to time declare dividends on stock
of the Company outstanding on the dates of record fixed by the Board, to be paid
in cash, in property or in shares of the Company's stock on or as of such
payment or distribution dates as the Board may prescribe.

                                 XII. AMENDMENTS

      12.01. PROCEDURE. These Bylaws may be amended, supplemented, repealed or
temporarily or permanently suspended, in whole or in part, or new bylaws may be
adopted, at any duly constituted meeting of the Board of Directors, the notice
of which meeting either includes mention of the proposed action relative to the
Bylaws or is waived as provided in Section 3.04 above. If, however, the chairman
of any such meeting or a majority of directors in attendance thereat in good
faith determines that any such action has arisen as a matter of necessity at the
meeting and is otherwise proper, no notice of such action will be required.

      12.02. AMENDMENT OF BYLAWS. These Bylaws may be altered, amended,
supplemented, repealed, or temporarily or permanently suspended, in whole or in
part, or replacement Bylaw provisions adopted by: (i) the affirmative vote of a
majority of the directors then in office; or (ii) the affirmative vote of a
majority of the votes cast on such matter(s) at a meeting of shareholders.

                 -----------------------------------------------

                                   CERTIFICATE

      I, NANCY C. LOFTIN, the Vice President, General Counsel, and Secretary of
ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, do HEREBY CERTIFY that
the foregoing is a true and correct copy of the Company's Bylaws, as


                                     - 13 -

amended and that such Bylaws, as amended, are in full force and effect as of the
date hereof.

      IN WITNESS WHEREOF, I have hereunto set my hand and affixed the seal of
the corporation this 23rd day of June, 2004.


                                 /s/ Nancy C. Loftin
                                 ------------------------------
                                 NANCY C. LOFTIN
                                 Vice President, General Counsel, and Secretary


                                     - 14 -

EX-12.1

Exhibit 12.1

ARIZONA PUBLIC SERVICE COMPANY
COMPUTATION OF EARNINGS TO FIXED CHARGES
($000’s)

	Six Months
	Ended		Twelve Months
	June 30,		Ended December 31,
	2004		2003		2002		2001		2000		1999
Earnings:
Income from continuing operations	$	87,211	$	180,937	$	199,343	$	280,688	$	306,594	$	268,322
Income taxes		53,503		86,854		126,805		183,136		195,665		133,015
Fixed charges		89,336		181,793		168,985		166,939		179,381		179,088
Total earnings	$	230,050	$	449,584	$	495,133	$	630,763	$	681,640	$	580,425
Fixed Charges:
Interest charges	$	71,359	$	147,610	$	133,878	$	130,525	$	141,886	$	140,948
Amortization of debt discount		2,383		3,337		2,888		2,650		2,105		2,084
Estimated interest portion of annual rents		15,594		30,846		32,219		33,764		35,390		36,056
Total fixed charges.	$	89,336	$	181,793	$	168,985	$	166,939	$	179,381	$	179,088
Ratio of Earnings to Fixed Charges (rounded down)		2.57		2.47		2.93		3.77		3.79		3.24

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Jack E. Davis, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2004.

/s/ Jack E. Davis Jack E. Davis
President and Chief Executive Officer  

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EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Donald E. Brandt, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s second fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 6, 2004.

/s/ Donald E. Brandt Donald E. Brandt
Executive Vice President &
Chief Financial Officer

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EX-32.1

EXHIBIT 32.1

CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     I, Jack E. Davis, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the fiscal quarter ended June 30, 2004 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

     Date: August 6, 2004.

/s/ Jack E. Davis Jack E. Davis
President and Chief Executive Officer
 

     I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the fiscal quarter ended June 30, 2004 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.

Date: August 6, 2004.

/s/ Donald E. Brandt Donald E. Brandt
Executive Vice President and
Chief Financial Officer
 

EX-99.1

Exhibit 99.1

APS RISK FACTORS
(Report on Form 10-Q for the Fiscal Quarter ending June 30, 2004 )

     Set forth below and in other documents we file with the Securities and Exchange Commission are risks and uncertainties that could affect our financial results.

     We cannot predict the outcome of our general rate case pending before the Arizona Corporation Commission (the “ACC”).

     As required by a 1999 settlement agreement among us and various parties (the “1999 Settlement Agreement”), on June 27, 2003, we filed a general rate case with the ACC. We requested a $175.1 million, or 9.8%, increase in our annual retail electricity revenues, to become effective July 1, 2004. The major reasons for the request include:

• complying with the provisions of the 1999 Settlement Agreement;

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

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

• obtaining rate base recognition of the generating plants built in Arizona by Pinnacle West Energy Corporation (“Pinnacle West Energy”) since 1999 to serve our retail electricity customers, specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3 (the “PWEC Dedicated Assets”);

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

• recovering restructuring and compliance costs associated with the ACC’s electric competition rules (the “Rules”).

     The general rate case will also address the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized in 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. If we do not have a rate adjustment mechanism that allows us to fully recover our power supply costs, then changes in these costs may harm our financial performance. On November 4, 2003, the ACC approved the issuance of an order which authorizes a rate adjustment mechanism allowing us to recover changes in purchased power costs (but not changes in fuel costs) incurred after July 1, 2004. The other rate adjustment mechanisms authorized in the 1999 Settlement Agreement (such as the costs associated with complying with the Rules) were also tentatively approved for subsequent implementation in the general rate case. The purchased power rate adjustment mechanism will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend or modify, in all respects, this November 4 order during the rate case.

     In its filed testimony in the rate case, the ACC staff recommended, among other things, that the ACC decrease our rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in our rate base, and not allow us to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings, and access to capital markets. We cannot predict the outcome of the rate case and the resulting levels of regulated revenues.

We are subject to complex government regulation which may have a negative impact on our business and our results of operations.

     We are subject to governmental regulation that may have a negative impact on our business and results of operations. We are a “subsidiary company” of a “holding company” within the meaning of the Public Utility Holding Company Act (“PUHCA”); however, we are exempt from the provisions of PUHCA by virtue of the filing of an annual exemption statement with the SEC by our parent company, Pinnacle West Capital Corporation (“Pinnacle West”).

     We are subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. The Federal Energy Regulatory Commission (“FERC”), the Nuclear Regulatory Commission (“NRC”), the Environmental Protection Agency (“EPA”), and the ACC regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. We believe the necessary permits, approvals and certificates have been obtained for our existing operations. However, changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations. We are also unable to predict the impact on our business and operating results from the future regulatory activities of any of these agencies. For example, in connection with an audit of us and our affiliates by the FERC, certain instances of noncompliance with FERC regulations related to the administration of our transmission tariff have been identified. 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.

The procurement of wholesale power by us without the ability to adjust retail rates could have an adverse impact on our business and financial results.

     Although the Rules allow retail customers to have access to competitive providers of energy and energy services, under the Rules we are the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. There can be no assurance that we would be able to fully recover the costs of this power. In addition, we filed a general rate case with the ACC on June 27, 2003 (see discussion above). Among other things, the rate case will address the implementation of rate adjustment mechanisms, which 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.

If we are not able to access capital at competitive rates, our ability to implement our financial strategy will be adversely affected.

     We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of our credit rating may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:

• an economic downturn;

• capital market conditions generally;

• the bankruptcy of an unrelated energy company;

• market prices for electricity and gas;

• terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies; or

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• the overall health of the utility industry.

     Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:

• increasing the cost of future debt financing;

• increasing our vulnerability to adverse economic and industry conditions;

• requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; and

• placing us at a competitive disadvantage compared to our competitors that have less debt.

A significant reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

     We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing costs, which would diminish our financial results. We would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under certain of our existing credit facilities depend on our credit ratings. A downgrade could also require us to provide additional support in the form of letters of credit or cash or other collateral to various counterparties. If our short-term ratings were to be lowered, it could limit our access to the commercial paper market. We note that the ratings from rating agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.

Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on our business and our financial results.

     Retail competition could have a significant adverse financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Under the Rules, as modified by the 1999 Settlement Agreement, we were required to transfer all of our competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. To satisfy this requirement, we planned to transfer generation assets to Pinnacle West Energy. Pursuant to an ACC order dated September 10, 2002, the ACC unilaterally modified the 1999 Settlement Agreement and directed us to cancel any plans to divest interests in any of our generating assets. The ACC further established a requirement that we solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. Pinnacle West Energy bid on and entered into contracts to supply most of our requirements in the summer months through September 2006. These regulatory developments and legal challenges to the Rules 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 offering 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 a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, and wholesale power marketers and brokers. This increased competition could affect our load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and the relatively low barriers to entry, we expect wholesale competition to increase. As competition continues to increase, our financial position and results of operations could be adversely affected.

3

Recent events in the energy markets that are beyond our control may have negative impacts on our business.

     As a result of the energy crisis in California during the summer of 2001, the recent volatility of natural gas prices in North America, the filing of bankruptcy by the Enron Corporation, and investigations by governmental authorities into energy trading activities, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. The capital markets and rating agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws, but it is difficult or impossible to predict or control what effect these or related issues may have on our business or our access to the capital markets.

Our results of operations can be adversely affected by milder weather.

     Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our overall operating results fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.

There are inherent risks in the operation of nuclear facilities, such as environmental, health and financial risks and the risk of terrorist attack.

     We have an ownership interest in and operate, on behalf of a group of owners, the Palo Verde Nuclear Generating Station (“Palo Verde”), which is the largest nuclear electric generating facility in the United States. Palo Verde is subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks and unscheduled outages due to equipment and other problems. We maintain nuclear decommissioning trust funds and external insurance coverage to minimize our financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage.

     The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.

     The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.

The use of derivative contracts in the normal course of our business and changing interest rates and market conditions could result in financial losses that negatively impact our results of operations.

     Our operations include managing market risks related to commodity prices and, subject to specified risk parameters, engaging in marketing and trading activities intended to profit from market price movements. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances and credits. We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity.

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     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material adverse impact on our earnings for a given period.

     Changing interest rates will affect interest paid on variable-rate debt and interest earned by our pension plan and nuclear decommissioning trust funds. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan is also impacted by the discount rate, which is the interest rate used to discount future pension obligations. Continuation of recent decreases in the discount rate would result in increases in pension costs, cash contributions, and charges to other comprehensive income. The pension plan and nuclear decommissioning trust funds also have risks associated with changing market values of equity investments. A significant portion of the pension costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices.

The uncertain outcome regarding the creation of regional transmission organizations, or RTOs, and implementation of the FERC’s standard market design may materially impact our operations, cash flows or financial position.

     In a December 1999 order, the FERC established characteristics and functions that must be met by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and nondiscriminatory markets and exclusive authority to maintain short-term reliability. Additionally, in a pending notice of proposed rulemaking, the FERC is considering implementing a standard market design for wholesale markets. On October 16, 2001, we and other owners of electric transmission lines in the Southwest filed with the FERC a request for a declaratory order confirming that our proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic framework for a standard market design for the Southwest. On September 15, 2003, the FERC issued an order granting clarification and rehearing, in part, of its prior orders. In particular, this order approved the use of a physical congestion management scheme, which is used to allocate transmission rights on congested lines, for WestConnect for an initial phase-in period. FERC indicated that the WestConnect utilities and the appropriate regional state advisory committee should develop a market based congestion management scheme for subsequent implementation. We are now participating in a cost/benefit analysis of implementing WestConnect, the results of which are expected to be completed in 2004.

     If we ultimately join an RTO, we could incur increased transmission-related costs and reduced transmission service revenues; we may be required to expand our transmission system according to decisions made by the RTO rather than our internal planning process; and we may experience other impacts on our operations, cash flows or financial position that will not be quantifiable until the final tariffs and other material terms of the RTO are known.

We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact our business plans, or expose us to environmental liabilities.

     We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.

     In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental

5

matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

     We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

Actual results could differ from estimates used to prepare our financial statements.

     In preparing the financial statements in accordance with accounting principles generally accepted in the United States of America, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

• Regulatory Accounting — Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $167 million of regulatory assets on our balance sheet at June 30, 2004.

• Pensions and Other Postretirement Benefit Accounting - Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings, plan funding requirements and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

• Derivative Accounting — Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)).

• Mark-to-Market Accounting — The market value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.

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