FORM 10-Q

ARIZONA PUBLIC SERVICE COMPANY

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

Yes  [ X ]            No  [  ]

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

Yes  [  ]            No [ X ]

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

Number of shares of common stock, $2.50 par value,
outstanding as of November 8, 2004: 71,264,947

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

Glossary

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – administrative law judge

APS – Arizona Public Service Company, the Company

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

CC&N – Certificate of Convenience and Necessity

Company – Arizona Public Service Company

CPUC – California Public Utility Commission

DOE – United States Department of Energy

EPA – United States Environmental Protection Agency

ERMC – Energy Risk Management Committee

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

FIN – FASB Interpretation

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

FSP – FASB Staff Position

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

IRS – United States Internal Revenue Service

Moody’s – Moody’s Investors Service

MW – megawatt, one million watts

MWh – megawatt-hours, one million watts per hour

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

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

NRC – United States Nuclear Regulatory Commission

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

OCI – other comprehensive income

Palo Verde – Palo Verde Nuclear Generating Station

PG&E – PG&E Corp.

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

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

PPL Sundance – PPL Sundance Energy, LLC

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

PX – California Power Exchange

Rules – ACC retail electric competition rules

SEC – United States Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

SNWA – Southern Nevada Water Authority

SPE – special-purpose entity

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

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

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

T&D – transmission and distribution

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

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

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

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

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

VIE — variable interest entity

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Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

ARIZONA PUBLIC SERVICE COMPANY

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

See Notes to Condensed Financial Statements

4

ARIZONA PUBLIC SERVICE COMPANY

ASSETS

See Notes to Condensed Financial Statements.

5

ARIZONA PUBLIC SERVICE COMPANY

CAPITALIZATION AND LIABILITIES

See Notes to Condensed Financial Statements.

6

ARIZONA PUBLIC SERVICE COMPANY

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY

1. Our unaudited condensed financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature. We suggest that these condensed financial statements and notes to condensed financial statements be read along with the financial statements and notes to financial statements included in our 2003 Form 10-K. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.

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

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

4. Changes in Liquidity

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

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

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

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

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

     At September 30, 2004, we had $566 million of pollution control bonds under which interest rates are reset on a daily, weekly or annual basis. The holders of $387 million of these bonds have the right to cause us to purchase their bonds on the applicable reset date if the bonds are not remarketed. Of these bonds, $164 million of such bonds are classified as current maturities of long-term debt. The remaining $223 million of bonds are classified as long-term debt because we have the intent and ability, as demonstrated by credit agreements in place that extend for more than one year, to refinance any bonds that we are required to purchase.

     The following is a list of principal payments due on total long-term debt and capitalized lease requirements as of September 30, 2004:

•		zero in 2004;
•		$616 million in 2005;
•		$86 million in 2006;
•		$175 million in 2007;
•		$1 million in 2008; and
•		$1.847 billion thereafter.

5. Regulatory Matters

Electric Industry Restructuring

State

     General Rate Case; 2004 Settlement Agreement

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

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

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

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

•		We would receive an annual retail rate increase of approximately $75.5 million, or 4.21%. The increase would consist of an increase in base rates of approximately 3.77% and an increase of approximately 0.44% for recovery over five years of the past costs of compliance with the ACC’s retail electric competition rules.
•		We would acquire the PWEC Dedicated Assets from Pinnacle West Energy and rate base the PWEC Dedicated Assets at a rate base value of $700 million, which would result in a mandatory rate base disallowance of $148 million. As a result, for financial reporting purposes, we would recognize a one-time, after-tax net plant write-off of approximately $88 million in the period when the plant transfer to us is completed, and would reduce annual depreciation expense by approximately $5 million.
•		To bridge the time between the effective date of the rate increase and the actual date the PWEC Dedicated Assets transfer, we and Pinnacle West Energy would enter into a cost-based purchase power agreement (the “Bridge PPA”), which would be based on the value of the PWEC Dedicated Assets described in the previous bullet point. The Bridge PPA would remain in effect until the FERC approves the transfer of the PWEC Dedicated Assets to us and the transfer is completed.

•		If the FERC were to issue an order denying our request to acquire the PWEC Dedicated Assets, the Bridge PPA would become a 30-year purchased power agreement, with prices reflecting cost-of-service as if we had acquired and rate-based the PWEC Dedicated Assets at the value described above.
•		If the FERC were to issue an order (a) approving our request to transfer the PWEC Dedicated Assets at a value materially less than $700 million, (b) approving the transfer of fewer than all of the PWEC Dedicated Assets, or (c) that was materially inconsistent with the 2004 Settlement Agreement, we would file an appropriate application with the ACC so that rates could be adjusted. In these circumstances, the Bridge PPA would continue at least until the conclusion of the subsequent proceeding to consider any appropriate adjustment to our rates.

•		A power supply adjuster would provide for the recovery of fuel and purchased power costs, subject to specified parameters and procedures.
•		We would not restore and recover in rates the $234 million write-off recorded in 1999 as a result of a 1999 settlement agreement approved by the ACC related to the implementation of retail electric competition in Arizona. As a result, annual amortization expense for financial reporting purposes would be

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

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

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

     ACC Financing Order

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

     The ACC granted the Financing Order subject to various conditions. One of these conditions is that we must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce our common equity ratio below that threshold, unless otherwise waived by the ACC.

     In addition, the Financing Order required the ACC staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003, we submitted our report on these matters to the ACC staff. As part of the 2004 Settlement Agreement, this inquiry would be concluded with no further action by the ACC.

     Retail Electric Competition Rules

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

•		They apply to virtually all Arizona electric utilities regulated by the ACC, including us.
•		Effective January 1, 2001, retail access became available to all of our retail electricity customers.

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•		Electric service providers that get CC&N’s from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.
•		Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.
•		The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.
•		Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our competitive electric assets and services to affiliates no later than December 31, 2002. However, as discussed below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require us to transfer our generation assets.

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

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

     Track A Order

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

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•

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

•

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

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

•

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

•		the generating assets to be included in our rate base, including the question of whether the PWEC Dedicated Assets should be included in our rate base;
•		the appropriate treatment of the $234 million pretax asset write-off agreed to by us as part of the 1999 Settlement Agreement; and
•		the appropriate treatment of costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy.

•

As a result of the ACC’s issuance of the Financing Order, our appeals of the Track A Order are limited to the issues described in the preceding bullet points.

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

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

     Track B Order

     On March 14, 2003, the ACC issued the Track B Order, which required us to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1,

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

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

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

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

     Provider of Last Resort Obligation

     Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are, under the Rules, the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. There can be no assurance that we would be able to fully recover the costs of this power. The proposed settlement of our general rate case, discussed above, would, among other things, allow us to recover purchased power costs.

     1999 Settlement Agreement

     The following are the major provisions of a settlement agreement entered into in 1999, as approved by the ACC:

•

We have reduced rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. Based on the price reductions authorized in the 1999 Settlement Agreement, there were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after

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

•		Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.
•		There was a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004.
•		We are being permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004, or when the rate case is decided. See “General Rate Case; 2004 Settlement Agreement” above.
•		Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” above), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001.
•		Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement stated that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also stated that we will not be allowed to recover $183 million net present value (in 1999 dollars) ($234 million pre-tax) of the $533 million. The 1999 Settlement Agreement provided that we will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As part of our general rate case request, we sought the recovery of amounts written off by us as a result of the 1999 Settlement Agreement. That claim would be given up under the terms of the 2004 Settlement Agreement (see above).

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•

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

     General

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

     Request for Proposals and Asset Purchase Agreement

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

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

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

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

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

Federal

     In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.

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

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

6. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit pension plan, a nonqualified supplemental excess benefit retirement plan, and other postretirement benefits for the employees of Pinnacle West and their subsidiaries. In 2003 and 2004, we represented 89% of the total cost of the plans.

     On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug cost. The FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to address the accounting for the effects of the Act. During the third quarter of 2004, Pinnacle West retroactively adopted the provisions of FSP 106-2, resulting in the remeasurement of its postretirement benefit plans’ accumulated postretirement benefit obligation (APBO) as of December 31, 2003. The impact of the subsidy for Pinnacle West is a decrease in the accumulated projected benefit obligation of approximately $65 million and a decrease of approximately $11 million in the net periodic postretirement benefit cost for 2004. The annual after-tax reduction to our expense is approximately $4 million, excluding amounts capitalized as construction overhead or billed to electric plant participants.

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     The following table provides details of the benefit costs of Pinnacle West’s plans for the three and nine months ended September 30, 2004 and 2003. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants on amounts capitalized as overhead construction (dollars in millions):

(a)

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

Contributions

     The Pension Stability Act was signed into law on April 10, 2004. Under this new legislation, Pinnacle West’s required pension contribution in 2004 is $35 million, which Pinnacle West contributed in the third quarter. Pinnacle West has contributed approximately $14 million to the other postretirement benefits plan in 2004 through September. Our share of these contributions is approximately 89%.

7. Business Segments

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

•

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

•

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

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

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8. Accounting Matters

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

•		Note 6 for FSP 106-2 regarding the Medicare Prescription Drug, Improvement and Modernization Act related to retirement plans and other benefits; and
•		Note 9 for FIN No. 46R related to variable interest entities.

9. Variable Interest Entities

     In 2003, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities,” as it applies to special-purpose entities. FIN No. 46R requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities.

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

     We are exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that we do not consider to be reasonably likely to occur.

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Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2004, we would have been required to assume approximately $250 million of debt and pay the equity participants approximately $195 million.

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

10. Derivative Instruments and Energy Trading Activities

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of September 30, 2004, we hedge exposures to the price variability of these commodities for a maximum of eight years. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Cash Flow Hedges

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

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

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income as an offset to the effect on earnings of market price changes for the related hedged transactions.

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

•

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

•

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

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

September 30, 2004

December 31, 2003

     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties at

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September 30, 2004 was $1 million. No collateral was provided to counterparties at December 31, 2003. Collateral provided to us by counterparties was $9 million at September 30, 2004 and $12 million at December 31, 2003, and is included in other current liabilities on the Condensed Balance Sheets.

     Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties. Our risk management process assesses and monitors the financial exposure of our counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

11. Comprehensive Income

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

(a)

These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and gas requirements to serve Native Load.

(b)

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

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12. Commitments and Contingencies

Palo Verde Nuclear Generating Station

     Spent Fuel and Waste Disposal

     Nuclear power plant owners are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including us (on behalf of ourself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. Arizona Public Service Company v. United States of America, United States Court of Federal Claims, 03-2832C.

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

California Energy Market Issues and Refunds in the Pacific Northwest

     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. We were a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, we should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. We do not anticipate material changes in our exposure and still believe, subject to the finalization of the revised proxy prices, that we will be entitled to a net refund.

     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Court of Appeals (Ninth Circuit). Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.

     On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and

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2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including us, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. After reviewing the matter, along with the data supplied by us, the FERC staff moved to dismiss the claims against us and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

     California Energy Market 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 under market-based rates. State of California v. British Columbia Power Exchange et al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. State of California ex rel. Bill Lockyer, Attorney General v. FERC, No. 02-73093. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The outcome of the further proceedings cannot be predicted at this time.

     In addition, the State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including us, attempting to expand those matters to such other participants. We have not yet filed a responsive pleading in the matter, but we believe the claims by Reliant and Duke as they relate to us are without merit.

     We were also named in a lawsuit regarding wholesale contracts in California, which, after moving to state court, has been removed to the federal court for a second time. James Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court, Case No. 407867, U.S. District Court (Northern District) C-04-0519 SBA. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against us and numerous other PX participants. Cal PX v. The State of California, Superior Court in and for the County of Sacramento, JCCP No. 4203. Various motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations or liquidity.

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Natural Gas Supply

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

     On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement. In order for us and Pinnacle West Energy to meet our natural gas supply and capacity requirements, we now expect that the combined increase in costs associated with the natural gas supply and the transportation capacity to result in an overall average increase of approximately $4 million per year in 2004 and 2005. We and Pinnacle West Energy have sought appellate review of the FERC’s July 9 order and related issues on the grounds that the FERC decision to abrogate the full requirements contracts is arbitrary and capricious and is not supported by substantial evidence. Arizona Public Service Company and Pinnacle West Energy Corporation v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1209. This petition for review was consolidated with a petition filed by the ACC and other full requirements contract holders. Arizona Corporation Commission et al v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1206. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements.

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

Environmental Matters - Superfund

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

Asset Purchase Agreement

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

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13. Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. The Price Anderson Act currently limits the combined public liability of nuclear reactor owners to $10.76 billion for claims that could arise from a single nuclear incident. The Palo Verde participants purchase the maximum available commercial insurance of $300 million. The balance of the $10.46 billion is provided by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $10 million per incident. Based on our interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $9 million.

     The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). We are subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The estimated maximum amount of retrospective assessments we could incur under the current NEIL policies totals $16 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

14. Stock-Based Compensation

     Pinnacle West offers stock-based compensation plans for our officers and key employees. In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”

     The following chart compares our net income and stock compensation expense for the three and nine months ended September 30, 2004 and 2003 to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through September 30, 2004 (dollars in thousands):

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15. Other Income and Other Expense

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

(a)

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

16. Guarantees

     We have entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2004, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. See Note 4 for more information. In July 2004, $150 million of these letters of credit were renewed for a three-year term and expire in 2007. The remainder expire in 2005. We have also entered into approximately $102 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the

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Palo Verde sale leaseback transactions). These letters of credit expire in 2005. Additionally, we have approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2005. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     We provide indemnifications relating to liabilities arising from or related to certain of our agreements. We have provided indemnifications to the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnifications and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnifications is likely and therefore no related liability has been recorded.

17. Related Party Transactions

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

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(a)

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

(b)

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

     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. We purchase electricity from and sell electricity to APS Energy Services; however, these transactions are settled net and reported net. Intercompany receivables primarily include the amounts related to the loan we made to Pinnacle West Energy and intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

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ARIZONA PUBLIC SERVICE COMPANY

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

Introduction

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

Overview

     We are a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona. We are a wholly-owned subsidiary of Pinnacle West. Through our marketing and trading division, we generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading division also sells, in the wholesale market, Pinnacle West Energy’s generation output that is not needed for our Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. Our marketing and trading division focuses primarily on managing purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. Our service territory growth is about three times the national average and remains a fundamental driver of our revenues and earnings.

     Pinnacle West Energy is our unregulated generation affiliate. Pinnacle West formed Pinnacle West Energy in 1999 as a result of the ACC’s requirement that we transfer all of our competitive assets and services to an affiliate or to a third party by the end of 2002. We planned to transfer our generation assets to Pinnacle West Energy. Additionally, Pinnacle West Energy constructed several power plants to meet growing energy needs (1790 MW in Arizona and 570 MW in Nevada). In September 2002, the ACC issued the Track A Order, which prohibited us from transferring our generation assets to Pinnacle West Energy. As a result of the Track A Order, we are seeking to transfer the plants built by Pinnacle West Energy in Arizona to us to unite the Arizona generation under one common owner, as originally intended. The 2004 Settlement Agreement would provide for that transfer.

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

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

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

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•

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

•

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

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

General

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

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

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

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

•

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

•

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

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

Regulated Electricity Segment Revenues

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

•

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

•

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

•

a $5 million increase due to miscellaneous factors.

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Marketing and Trading Segment Revenues

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

•

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

•

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

•

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

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

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

•

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

•

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

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

Regulated Electricity Segment Revenues

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

•

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

•

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

•

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

•

an $11 million increase due to miscellaneous factors.

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Marketing and Trading Segment Revenues

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

•

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

•

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

•

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

Liquidity and Capital Resources

     Capital Expenditure Requirements

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