ARIZONA PUBLIC SERVICE CO - 10-Q Quarterly 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 þ 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 þ

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 14, 2003: 71,264,947, all of which are held beneficially and of record by Pinnacle West Capital Corporation.

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.

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

Financing Order — ACC order issued on April 4, 2003 relating to our request to provide up to $500 million of financing or credit support to Pinnacle West Energy or Pinnacle West

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

Interim Financing Order — ACC order issued on November 22, 2002 relating to our request to provide up to $125 million of financing or credit support to Pinnacle West

June 2003 10-Q — Arizona Public Service Company Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2003

March 2003 10-Q — Arizona Public Service Company Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2003

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

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

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

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

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

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

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

2002 10-K — the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002

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 with the exception of the transition adjustment for asset retirement obligations (see Note 13). 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 2002 10-K. We have reclassified certain prior year amounts to conform to the current year presentation.

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

4. Our debt structure as of September 30, 2003 differed from our debt structure as of December 31, 2002 in the ways discussed in this Note. On April 7, 2003, we redeemed approximately $33 million of our First Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, we redeemed approximately $54 million of our First Mortgage Bonds, 7.25% Series due 2023.

On May 12, 2003, we issued $500 million of debt as follows: $300 million aggregate principal amount of our 4.650% Notes due 2015 and $200 million aggregate principal amount of our 5.625% Notes due 2033. Also on May 12, 2003, we made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund Pinnacle West’s repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. See “ACC Financing Orders” in Note 5 for additional information.

On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved the 1999 Settlement Agreement, a comprehensive settlement agreement among us and various parties related to the implementation of retail electric competition in Arizona. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed us not to transfer our generation assets to Pinnacle West Energy, as previously required under the Rules and the 1999 Settlement Agreement. See “Track A Order” below. The Track A Order 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.

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. Pinnacle West Energy bid on and entered into a contract to supply most of our requirements in the summer months through September 2006. See “Track B Order” below.

On April 4, 2003, the ACC issued the Financing Order authorizing us to lend up to $500 million to Pinnacle West Energy. See “ACC Financing Orders” 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 incurred to finance the construction of the PWEC Dedicated Assets. See Note 4.

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

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


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

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

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

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

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

	•	Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also states that we will not be allowed to recover $183 million net present value (in 1999 dollars) 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 noted above and discussed in greater detail 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.


	•	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.

	•	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 noted above and discussed in greater detail 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 have appealed the ruling to the Arizona Court of Appeals, as a result of which the Superior Court’s ruling is automatically stayed pending further judicial review. That appeal is still pending. In a similar appeal concerning the issuance of competitive telecommunications CC&N’s, the Arizona Court of Appeals invalidated rates for competitive carriers due to the ACC’s failure to establish a fair value rate base for such

carriers. The Arizona Supreme Court agreed that the ACC had to determine a fair value rate base but vacated the Court of Appeals’ requirement that competitive rates be set based only on such fair value rate base.

Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in 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. Unless we are able to obtain an adjustment of our rates under the emergency provisions of the 1999 Settlement Agreement, 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.

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. We and the ACC are the only parties to the Track A Order appeals. The major provisions of the principles include, among other things, the following:


	•	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 will be limited to the issues described in the preceding bullet points.

On February 21, 2003, a Notice of Claim was filed with the ACC and the Arizona Attorney General on behalf of Pinnacle West, Pinnacle West Energy and us to preserve their and our rights relating to the Track A Order. The period within which the ACC and the Arizona Attorney General could respond to the claim expired on April 22, 2003. Accordingly, APS, Pinnacle West, and Pinnacle West Energy filed a lawsuit in August 2003 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. CV 2003-016372.

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 bid amounts are expected to increase in 2004 and 2005 based largely on growth in our retail load and our retail energy sales. The Track B Order also confirmed that it was “not intended to change the current rate base status of [APS’] existing assets.”

The order recognizes our right to reject any bids that are unreasonable, uneconomical or unreliable. The ACC Staff and an independent monitor participated in the Track B procurement process. The Track B Order also contains requirements relating to standards of conduct between us and any affiliate of ours participating in the competitive solicitation, requires that we treat bidders in a non-discriminatory manner and requires us to file a protocol regarding short-term and emergency procurements. The order permits the provision by us of corporate oversight, support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with our confidential 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.

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:


	•	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;

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

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

The ACC also ordered the ACC Staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003, we submitted our report on these matters to the ACC Staff.

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 incurred to finance the construction of the PWEC Dedicated Assets. See Note 4.

On November 22, 2002, the ACC issued an order (the “Interim Financing Order”) approving our request to permit us to (a) make short-term advances to Pinnacle West in the form of an interaffiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West’s short-term debt, subject to certain conditions. As of September 30, 2003, there were no borrowings outstanding under this financing arrangement. This authority will expire on December 4, 2003.

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, to become effective July 1, 2004. In this rate case, we updated our cost of service and rate design.


	•	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 ACC’s 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):

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

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

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

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

Estimated Timeline We have asked the ACC to approve the requested rate increase by July 1, 2004. On August 15, 2003, the ACC issued a procedural schedule setting a hearing date on the application of April 7, 2004. We assume that the ACC will make a decision in this general rate case by the end of 2004.

The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow 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 ACC electric competition rules) were also tentatively approved for subsequent implementation in the general rate case. The provisions of this order will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend, modify or reconsider, in its entirety, this November 4 order during the rate case.

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. The FERC invited comments on the white paper, but has not yet set a due date for filing comments. 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 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.

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, 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 insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

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


	•	our regulated electricity segment, which consists of regulated traditional 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. See Note 18 for information about the transfers of the marketing and trading division and more information regarding our marketing and trading activities.

In August 2003, the EITF reached a consensus on EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.” EITF 03-11 addresses whether realized gains and losses should be shown gross or net in the income statement for contracts that are not held for trading purposes but are derivatives subject to SFAS No. 133. EITF 03-11 is effective for us on October 1, 2003.

We are currently evaluating the impacts of this new guidance on our financial statements. We believe EITF 03-11 may result in net reporting of certain of our derivative transactions. This change will reduce revenues and purchased power expense but will have no effect on our net income. Further, the new guidance may reduce cash flow hedge accounting for certain of our derivative transactions, which could result in increased volatility of net income. Because of varying interpretations, an electric industry group has requested that the FASB clarify the guidance related to cash flow hedge accounting.

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

In June 2003, the FASB’s Derivatives Implementation Group (DIG) issued DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of “Not Clearly and Closely Related” in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” To qualify for a normal purchases and sales scope exception under SFAS No. 133, the pricing in a contract must be clearly and closely related to the item being purchased or sold. DIG Issue C20 provides guidance on the clearly and closely related criteria and supercedes previous guidance. The new rules allow the use of broad-based market indicators in certain circumstances.

DIG Issue C20 is effective for us on October 1, 2003. It is to be applied prospectively to existing and future contracts. A special transition adjustment may be required in certain circumstances. While we continue to evaluate this new guidance, we currently do not expect DIG Issue C20 to have a material impact on our financial statements.

In May 2003, the FASB ratified EITF 01-8, “Determining Whether an Arrangement Contains a Lease.” This issue provides guidance for determining whether an arrangement contains a lease that is within the scope of SFAS No. 13, “Accounting for Leases.” Under EITF 01-8, an arrangement contains a lease if the specific property, plant or equipment has been explicitly or implicitly identified and the arrangement conveys to the purchaser the right to use the property, plant or equipment as defined in this issue. For us, the new guidance was effective for arrangements committed to or modified after June 30, 2003. The impact of this guidance was immaterial to our financial statements for the period ended September 30, 2003.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This statement requires that an issuer classify certain financial instruments, which were previously classified as equity, as liabilities (or assets in some circumstances). The adoption of this standard did not impact our financial statements for the period ended September 30, 2003.

In November 2002, the EITF reached a consensus on EITF 00-21, “Revenue Arrangements with Multiple Deliverables.” EITF 00-21 addresses certain aspects of the accounting by a vendor for arrangements under which it will perform multiple revenue-generating activities. EITF 00-21 specifically addresses how to determine whether an arrangement has identifiable, separable revenue-generating activities. EITF 00-21 does not address when the criteria for revenue recognition are met or provide guidance on the appropriate revenue recognition convention. For us, EITF 00-21 was effective for revenue arrangements entered into after June 30, 2003. The impact of this guidance was immaterial to our financial statements for the period ended September 30, 2003.

In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), “Accounting for Certain Costs Related to Property, Plant, and Equipment.” This proposed SOP would create a project timeline framework for capitalizing costs related to property, plant and equipment construction. It would require that property, plant and equipment assets be accounted for at the component level and require administrative and general costs incurred in support of capital projects to be expensed in the current period. We are waiting for further guidance from the FASB and the AICPA on the timing of the final guidance.


	•	Note 10 for an EITF issue (EITF 02-3) related to accounting for energy trading contracts;

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

	•	Note 15 for a new accounting standard (SFAS No. 148) on stock-based compensation; and

	•	Note 17 for a new interpretation (FIN No. 45) on guarantees.

In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities.” FIN No. 46 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. For us, FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective October 1, 2003 for VIEs created before February 1, 2003. We currently do not expect FIN No. 46 to have a material impact on our financial statements.

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. While we continue to evaluate the guidance, we currently do not expect that we will be required to consolidate the Palo Verde SPEs under FIN No. 46.

We are exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that we do not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2003, we would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

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 derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our 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 commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

We adopted EITF 02-3 guidance for all contracts in the fourth quarter of 2002. The impact of this guidance was immaterial to our financial statements. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Condensed Statements of Income on a net basis. Derivative instruments used for non-trading activities are accounted for in accordance with SFAS No. 133.

EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Conversely, all non-trading contracts and derivatives are to be

reported gross on the income statement. See Note 8 for additional information regarding gross or net presentation (EITF 03-11).

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


	•	Marketing and Trading — both non-trading and trading derivative instruments of our competitive business segment; and

	•	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.

The changes in derivative fair value of our regulated electricity positions included in the Condensed Statements of Income for the three, nine and twelve months ended September 30, 2003 and 2002 are comprised of the following (dollars in thousands):


(a)	Time value component of options excluded from assessment of hedge effectiveness.

As of September 30, 2003, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately 15 months. During the twelve months ending September 30, 2004, we estimate that a net loss of $5 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.

The following table summarizes our assets and liabilities from risk management and trading activities at September 30, 2003 and December 31, 2002 (dollars in thousands):

Cash or collateral may be required to serve as collateral against our open positions on certain energy-related contracts. No collateral was provided to counterparties at September 30, 2003. Collateral provided to counterparties was $5 million at December 31, 2002 and is included in investments and other assets on the Condensed Balance Sheet. Collateral provided to us by counterparties was $4 million at September 30, 2003 and $4 million at December 31, 2002 and is included in other long-term liabilities on the Condensed Balance Sheet.

Components of comprehensive income for the three, nine and twelve months ended September 30, 2003 and 2002, 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.

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. This order calls for a hearing, with findings of fact due to the FERC after the CAISO and PX provide necessary historical data. The FERC directed an ALJ to make findings of fact with respect to: (1) the mitigated price in each hour of the refund period; (2) the amount of refunds owed by each supplier according to the methodology established in the order; and (3) the amount

currently owed to each supplier (with separate quantities due from each entity) by the CAISO, the California Power Exchange, the investor-owned utilities and the State of California.

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. On December 12, 2002, an ALJ issued Proposed Findings of Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great majority of the proposed findings, revising only the calculation of natural gas prices for the final determination of mitigated prices in the California markets. Sellers who may actually have paid more for natural gas than the proxy prices adopted by the FERC are required to submit necessary data to the FERC, after which a technical conference will be held. Finalization of refund calculations is expected by the end of 2003. Subsequent to the foregoing refund decision by the FERC, the California parties filed a request for rehearing asking the FERC to expand the time period and transactions covered by the refund proceeding and provide for approximately $3 billion in additional refunds relating to sales by all sellers in the California markets. 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.

On November 20, 2002, the FERC reopened discovery in these proceedings pursuant to instructions of the United States Court of Appeals for the Ninth Circuit that the FERC permit parties to offer additional evidence of potential market manipulation for the period of January 1, 2000 through June 20, 2001. Parties submitted additional evidence and proposed findings, which the FERC continues to consider. On a parallel track, in March 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 to 2001 time period, including us, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the CAISO tariff. The report also recommended that the FERC issue an order to show cause why these transactions did not violate the CAISO tariff with potential disgorgement of any unjust profits.

On June 25, 2003, the FERC issued an order finding that certain identified entities appear to have potentially participated in activities that constitute gaming and/or anomalous market behavior in violation of the CAISO’s and PX’s tariffs during the period of January 1, 2000 through June 20, 2001. The FERC directed the CAISO, within 21 days of the date of the order to provide the identified entities with all of the specific transaction data for each of the specified potential gaming practices, and directed the identified entities to file responses within 45 days thereafter, absent a settlement. The FERC also established a hearing proceeding to be held before an ALJ for the identified entities to show cause, why they should not be found to have engaged in gaming practices in violation of the CAISO and PX tariffs. We were named as an identified entity in this order because of evidence of possible use of “paper trading” (the buy back of ancillary services) and “false import” (ricochet or megawatt laundering) strategies. Based on our review of the allegations, as outlined in the terms of the order, we believe that we were not improperly engaged in any of the identified gaming practices. On October 29, 2003, the FERC trial staff filed a motion to dismiss the alleged claims against us.

Also in June 2003, the FERC initiated an investigation of all bids in the CAISO and PX markets above $250 per MWh during the period of May 1, 2000 through October 1, 2000. The FERC Office of Market Oversight and Investigations has issued data requests and is required to report back to the FERC by year-end 2003. Although we bid over $250 per MWh during the time period in question, we believe that our bids were not improper.

With regard to the Pacific Northwest, the FERC, in 2001, ordered an evidentiary proceeding to discuss and evaluate possible refunds. The FERC required that the record establish the volume of the transactions, the identification of the net sellers and net buyers, the price and terms and conditions of the sales contracts and the extent of potential refunds. On September 24, 2001, an ALJ concluded that prices in the Pacific Northwest during the period of December 25, 2000 through June 20, 2001 were the result of a number of factors in addition to price signals from the California markets, including the shortage of supply, excess

demand, drought and increased natural gas prices. Under these circumstances, the ALJ ultimately concluded that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. On December 19, 2002, the FERC opened a new discovery period to permit the parties to offer additional evidence for the period of January 1, 2000 through June 20, 2001. Additional evidence was submitted in March 2003. In June 2003, the FERC issued a final order terminating this proceeding without refunds. Certain parties have sought rehearing of the FERC’s final order.

Although the FERC has not calculated the specific refund amounts due in California, concluded newly established investigations of behavior in the Western markets, or ruled upon the requests for rehearing in the Pacific Northwest cases, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or liquidity.

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

We are closely monitoring developments in the California energy market and the potential impact of these developments on us. In the second quarter of 2002, PG&E filed its Modified Second Amended Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization. Both plans generally indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstanding, undisputed debts. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us or the regional energy market in general.

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 CAISO 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. James Millar, et al. v. Allegheny Energy Supply, et al., United States District Court in and for the District of Northern California, Case No. C02-2855 EMC. The complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market. 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 preliminary motions are being filed and we cannot currently predict the outcome of this matter. The “United States Justice Foundation” is suing numerous wholesale energy contract suppliers to California, including Pinnacle West, as well as the California Department of Water Resources, based upon an alleged conflict of interest arising from the activities of a consultant for Edison International who also negotiated long-term contracts for the California Department of Water Resources. McClintock, et al. v.

Yudhraja, Superior Court in and for the County of Los Angeles, Case No. GC 029447. The California Attorney General has indicated that an investigation by his office did not find evidence of improper conduct by the consultant. We believe the claims against Pinnacle West and us in the lawsuits mentioned in this paragraph are without merit and will have no material adverse impact on our financial position, results of operations or liquidity.

We have a long history of contractual relations with Citizens relating to providing electricity and ancillary services to the utility in Arizona owned by Citizens. Under the current power sale agreement, Pinnacle West provides for deliveries of electricity and ancillary services through May 31, 2008. On August 11, 2003, Citizens sold its Arizona utility to a subsidiary of UniSource, UNS Electric, Inc. (“UNS Electric”). In connection with that sale, the above referenced power sale agreement was amended and assigned to UNS Electric. The Company does not expect any potential claims relating to the agreement and/or any prior related agreements, including as to any claims previously raised by Citizens, to have a material adverse impact on its financial statements.

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

Prior to September 1, 2003, Pinnacle West Energy’s and our natural gas supply was transported pursuant to a firm, full requirements transportation service agreement. On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement by requiring all firm, full requirements contract holders to convert to contract demand service agreements effective September 1, 2003. This required conversion has imposed additional limitations on the former full requirements contract holders’ ability to nominate firm transportation capacity. In order for us to meet our natural gas supply and capacity requirements, we must make market purchases, which we expect to increase costs by approximately $4 million per year for natural gas supply and by approximately $9 million per year for capacity, both of which amounts are reflected in the Company’s budgets. We and Pinnacle West Energy have sought appellate review of the FERC’s July 9 order 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.

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

the long-lived asset. Prior to January 1, 2003, we accrued asset retirement obligations over the life of the related asset through depreciation expense.

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

On January 1, 2003 and in accordance with SFAS No. 143, we recorded a liability of $219 million for our asset retirement obligations, including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a net regulatory liability of $40 million for the asset retirement obligations related to our regulated assets. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. The adoption of SFAS No. 143 did not have a material impact on our net income for the quarter or nine months ended September 30, 2003.

In accordance with SFAS No. 71, we will continue to accrue for removal costs for our regulated assets, even if there is no legal obligation for removal. At September 30, 2003, accumulated depreciation shown on our Condensed Balance Sheets included approximately $384 million of estimated future removal costs that are not considered legal obligations.

The following schedule shows the change in our asset retirement obligations during the nine-month period ended September 30, 2003 (dollars in millions):

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

To fund the costs we expect to incur to decommission the plant, we established external decommissioning trusts in accordance with NRC regulations. We invest the trust funds primarily in fixed income securities and domestic stock and classify them as available for sale. The following table shows the cost and fair value of our nuclear decommissioning trust fund assets which are on the Condensed Balance Sheets at September 30, 2003 and December 31, 2002 (dollars in millions):

The Company’s gross intangible assets (which are primarily software) were $226 million at September 30, 2003 and $193 million at December 31, 2002. The increase in gross intangible assets is primarily new software. The related accumulated amortization was $119 million at September 30, 2003 and $100 million at December 31, 2002. Amortization expense for the three months ended September 30 was $6 million in 2003 and $5 million in 2002. Amortization expense for the nine months ended September 30 was $19 million in 2003 and $13 million in 2002. Amortization expense for the twelve months ended September 30 was $24 million in 2003 and $19 million in 2002. Estimated amortization expense on existing intangible assets over the next five years is $25 million in 2003, $25 million in 2004, $24 million in 2005, $22 million in 2006 and $17 million in 2007.

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, nine, and twelve months ended September 30, 2003 and 2002 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, 2003 (dollars in thousands):

The following table provides detail of other income and other expense for the three, nine and twelve months ended September 30, 2003 and 2002 (dollars in thousands):

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

a prospective basis to guarantees issued or modified after December 31, 2002. We had no guarantees outstanding at September 30, 2003.

We have entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2003, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations. These letters of credit have expiration dates in 2004 and 2005. We have also entered into approximately $109 million of letters of credit to support certain equity lessors in 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 2003. 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.

In conjunction with our financing agreements, including our Palo Verde sale-leaseback transactions, we generally provide indemnifications relating to liabilities arising from or related to the agreements, except for certain limited exceptions depending on the particular agreement. We have also provided indemnifications to the equity participants and other parties in the Palo Verde sale-leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnifications is likely.

During 2001, we transferred most of our marketing and trading activities to Pinnacle West. In the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy (see Note 5). 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):

Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. Intercompany receivables primarily include the loan to Pinnacle West Energy (see Note 5), the amounts related to the transfer of marketing and trading activities discussed above and intercompany sales of electricity. Intercompany payables primarily include amounts related to the purchase of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

In the third quarter of 2003, we returned to the allowance for funds used during construction (“AFUDC”) method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This is consistent with us returning to a vertically integrated utility, as evidenced by our recent general rate case filing, which includes the request for rate recognition of generation assets. Previously, we capitalized interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of utility plant. Although AFUDC both increases the plant balance and results in higher current earnings during the construction period, AFUDC is realized in future revenues through depreciation provisions included in rates. AFUDC has been calculated using a composite rate of 8.51% in 2003. We compound AFUDC semiannually and cease to accrue AFUDC when construction is completed and the property is placed in service. This change increased earnings by $8 million in the third quarter of 2003.

In this Item, we explain our results of operations, general financial condition and outlook including:


	•	the changes in our earnings for the three, nine and twelve months ended September 30, 2003 and 2002;

	•	our capital needs, liquidity and capital resources;

	•	our business outlook and major factors that affect our financial outlook (see Note 5 to the Condensed Financial Statements and “Business Outlook” below); and

	•	our management of market risks.

We suggest this section be read along with the 2002 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.

We are an electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Electricity is delivered through a distribution system that we own. We also generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading segment sells, in the wholesale market, our and 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. In early 2003, the marketing and trading division was moved from Pinnacle West to us for future marketing and trading activities (existing wholesale contracts remain at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy. We do not distribute any products. Pinnacle West owns all of our outstanding common stock.

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


	•	our regulated electricity segment, which consists of regulated traditional 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. During 2001, we transferred most of our marketing and trading activities to Pinnacle West. Thus, we did not have any significant marketing and trading activity in 2002. Conversely, in the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts remain at Pinnacle West).

The following tables summarize net income by business segment for the three, nine and twelve months ended September 30, 2003 and the comparable prior periods (dollars in millions):

(a)

Consistent with our October 2001 ACC filing, we entered into contracts with our affiliates to buy power through June 2003. The contracts reflected prices based on the fully-dispatchable dedication of the Pinnacle West Energy generating assets to our Native Load customers (customers receiving power under traditional cost-based rate regulation). Beginning July 1, 2003, under the ACC Track B order, we were required to solicit bids for certain estimated capacity and energy requirements. Pinnacle West Energy bid on and entered into a contract to supply most of these purchase power requirements in summer months through September 2006. See “Track B Order” in Note 5 for more information.

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.

Consistent with returning to a vertically integrated utility, as evidenced by our recent general rate case filing, which includes the request for rate recognition of generation assets, we have also returned to the Allowance for Funds Used During Construction (“AFUDC”) method, which is a more traditional method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This change increased earnings by $8 million in the third quarter of 2003. See Note 19.

Our net income for the three months ended September 30, 2003 was $100 million compared with $87 million for the prior period. The $13 million increase in the period-to-period comparison reflects the following changes in earnings by segment:

Regulated Electricity Segment — Net income increased $18 million primarily due to higher retail sales related to customer growth and favorable weather effects; lower operating costs primarily related to severance costs recorded in 2002; higher capitalized construction finance costs related to our return to the AFUDC method of capitalizing such costs; an income tax benefit recorded in 2003; and lower regulatory asset amortization, consistent with the comprehensive settlement agreement related to the implementation of retail electric competition (the “1999 Settlement Agreement”). These favorable factors were partially offset by higher replacement power costs from plant outages due to more unplanned outages and higher market prices; higher prices for hedged gas and purchased power; a retail electricity price reduction that was effective July 1, 2003; and higher pension and other costs.

Marketing and Trading Segment — Net income decreased $5 million primarily due to the transfer of marketing and trading activities.

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

Regulated electricity segment revenues were $41 million lower in the three months ended September 30, 2003, compared with the same period in the prior year primarily as a result of:


	•	an $86 million decrease related to retail load hedge management wholesale sales primarily as a result of lower sales volumes;

	•	a $9 million decrease in retail revenues related to a reduction in retail electricity prices;

	•	a $33 million increase in retail revenues related to customer growth, excluding weather effects;

	•	a $14 million increase in retail revenues related to weather; and

	•	a $7 million net increase due to miscellaneous factors.

Marketing and trading segment revenues were $110 million higher in the three months ended September 30, 2003, compared with the same period in the prior year primarily as a result of:


	•	$108 million of higher marketing and trading revenues as a result of the transfer of marketing and trading activities; and

	•	a $2 million increase from generation sales other than Native Load primarily due to higher prices and higher sales volumes.

Our net income for the nine months ended September 30, 2003 was $159 million compared with $183 million for the prior year. The $24 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:


	•	Regulated Electricity Segment — Net income decreased $26 million primarily because of higher replacement power costs from plant outages due to higher market prices and more unplanned outages; higher prices for hedged gas and purchased power; two retail electricity price reductions; higher pension and other benefit costs; and higher depreciation expense related to increased delivery assets. These negative factors were partially offset by higher retail sales primarily due to customer growth; lower operating costs primarily related to severance costs recorded in 2002; lower regulatory asset amortization, consistent with the 1999 Settlement Agreement; higher income related to our return to the AFUDC method of capitalizing construction finance costs; and an income tax benefit recorded in 2003.

	•	Marketing and Trading Segment — Net income increased $2 million, due to increased generation sales other than Native Load due to higher sales volumes, partially offset by decreased margin due to the transfer of marketing and trading activities.

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

Regulated electricity segment revenues were $34 million lower in the nine months ended September 30, 2003, compared with the same period in the prior year primarily as a result of:


	•	a $94 million decrease related to retail load hedge management wholesale sales primarily as a result of lower sales volumes;

	•	a $21 million decrease in retail revenues related to reductions in retail electricity prices;

	•	a $69 million increase in retail revenues related to customer growth, excluding weather effects;

	•	a $6 million increase related to traditional wholesale sales as a result of higher sales volumes and higher prices; and

	•	a $6 million net increase due to miscellaneous factors.

Marketing and trading segment revenues were $297 million higher in the nine months ended September 30, 2003, compared with the same period in the prior year primarily as a result of:


	•	$239 million of higher marketing and trading revenues as a result of the transfer of marketing and trading activities; and

	•	a $58 million increase from generation sales other than Native Load primarily due to higher prices and higher sales volumes.

Our net income for the twelve months ended September 30, 2003 was $176 million compared with $222 million for the prior year. The $46 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:


	•	Regulated Electricity Segment — Net income decreased $45 million primarily due to higher operations and maintenance costs related to increased pension and other benefits; higher prices for hedged gas and purchased power; higher replacement power costs from plant outages due to higher market prices and more unplanned outages; two retail electricity price reductions; and higher depreciation expense related to increased delivery assets. These negative factors were partially offset by higher retail sales primarily due to customer growth; lower regulatory asset amortization, consistent with the 1999 Settlement Agreement; lower operating costs primarily related to severance costs recorded in 2002; 2001 charges related to purchase power contracts with Enron; higher income related to our return to the AFUDC method of capitalizing construction finance costs; and an income tax benefit recorded in 2003.

	•	Marketing and Trading Segment — Net income decreased $1 million, reflecting lower market liquidity in the wholesale power markets in the western United States. These negative factors were partially offset by increased generation sales other than Native Load primarily due to higher sales volumes, partially offset by lower unit margins.

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

Regulated electricity segment revenues were $46 million lower in the twelve months ended September 30, 2003, compared with the same period in the prior year primarily as a result of:


	•	a $99 million decrease related to retail load hedge management wholesale sales primarily as a result of lower prices and lower sales volumes;

	•	a $27 million decrease in retail revenues related to reductions in retail electricity prices;

	•	a $9 million decrease in retail revenues related to milder weather;

	•	a $70 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

	•	a $7 million increase related to traditional wholesale sales as a result of higher prices and higher sales volumes; and

	•	a $12 million net increase due to miscellaneous factors.

Marketing and trading segment revenues were $302 million higher in the twelve months ended September 30, 2003, compared with the same period in the prior year primarily as a result of:


	•	$249 million of higher realized wholesale revenues as a result of the transfer of marketing and trading activities and higher volumes, partially offset by lower prices;

	•	a $58 million increase from generation sales other than Native Load higher sales volumes and higher prices; and

	•	$5 million in lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and lower price volatility.

The following table summarizes the actual capital expenditures for the nine months ended September 30, 2003 and estimated capital expenditures for the next three years (dollars in millions):


(a)	As discussed in Note 5 under “General Rate Case and Retail Rate Adjustment Mechanisms,” as part of our 2003 general rate case, we requested rate base treatment of the PWEC Dedicated Assets.

Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. 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. In addition, we began several major transmission projects in 2001, with additional major projects scheduled to begin over the next several years. These projects are periodic in nature and are driven by strong regional customer growth. We expect to spend about $100 million on major transmission projects during the 2003 to 2005 time frame, and these amounts are included in “Delivery” in the table above.

Generation capital expenditures are comprised of various improvements for 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 contains nuclear fuel expenditures of approximately $30 million annually for 2003 to 2005.

Replacement of the steam generators in Palo Verde Unit 2 is presently scheduled for completion during the fall outage of 2003. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. We expect that these generators will be installed in Units 1 and 3 in the 2005 to 2007 time frame. Our portion of steam generator expenditures for Units 1, 2 and 3 is approximately $209 million, of which approximately $157 million will be spent from 2003 through 2008. In 2003 through 2005, $109 million of the costs are included in the generation capital expenditures table above and would be funded with internally-generated cash or external financings.

Contractual Obligations The following table summarizes actual contractual payments made during the nine months ended September 30, 2003 and estimated contractual commitments for the next five years and thereafter as of September 30, 2003 (dollars in millions):

We are exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that we do not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2003, we would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

The ratings of our securities as of November 12, 2003 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 our cost of and access to capital.

Our significant debt covenants related to our financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test (as defined in the agreements). We are in compliance with such covenants and anticipate that we will continue to meet all the significant covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65%. At September 30, 2003, our ratio was approximately 54%. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements. The coverage is approximately 4 times for our bank agreements and 14 times for our mortgage indenture at September 30, 2003. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants.

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

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

Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See “Business Outlook — Regulatory Matters” below and Notes 4 and 5 for discussion of the $500 million financing arrangement between Pinnacle West Energy and us authorized by the ACC pursuant to the Financing Order and our related issuance of $500 million of debt. See below and Note 5 for discussion of a $125 million interim financing arrangement between Pinnacle West and us.

On November 22, 2002, the ACC issued the Interim Financing Order, which permits us to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West’s short-term debt, subject to certain conditions. As of September 30, 2003, there were no borrowings outstanding under this financing arrangement. This authority will expire on December 4, 2003.

We pay for our capital requirements with cash from operations and, to the extent necessary, external financings. We have historically used cash from operations to pay dividends to Pinnacle West. As discussed in Note 5, we must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce our common equity below that threshold. As defined in the Financing Order, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At September 30, 2003, our common equity ratio was approximately 46%.

On April 7, 2003, we redeemed approximately $33 million of our First Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, we redeemed approximately $54 million of our First Mortgage Bonds, 7.25% Series due 2023.

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

We are part of a multi-employer 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. Pinnacle West elected to contribute cash to our pension plan in each of the last five years; the minimum required contributions during each of those years was zero. Specifically, Pinnacle West contributed $73 million for 2002 ($46 million of which was contributed in June 2003), $24 million for 2001, $44 million for 2000 ($20 million of which was contributed in 2001), $25 million for 1999 and $14 million for 1998. We fund our share of the pension contribution. We represent approximately 90% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions.

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 2002 10-K except for the impact of recent accounting pronouncements as discussed in Note 8. See “Critical Accounting Policies” in Item 7 of the 2002 10-K for further details about our critical accounting policies.

Consistent with returning to a vertically integrated utility, as evidenced by our recent general rate case filing, which includes the request for rate recognition of generation assets, we have also returned to the AFUDC method, which is a more traditional method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This change increased earnings by $8 million in the third quarter of 2003. See Note 19 for our AFUDC accounting policy.

See Note 5 for a discussion of ACC regulatory matters, including our general rate case filed on June 27, 2003.

The marketing and trading division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer demand. Pinnacle West moved this division to us in early 2003 for future marketing and trading activities (existing wholesale contracts remain at Pinnacle West) as a

result of the ACC’s Track A Order prohibiting our transfer of generating assets to Pinnacle West Energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels, and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities. Based on the erosion in the market and on the market outlook, we currently expect contributions from our trading activities (excluding gross margin from generation sales other than Native Load and gross margin attributable to structured transactions originated in years prior to 2003) to be negligible or slightly negative for the years 2003 and 2004.

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 3.6% a year for the three years 2000 through 2002; we currently expect customer growth to average about 3.5% per year from 2003 to 2005. We currently estimate that retail electricity sales in kilowatt-hours will grow 4.0% to 6.0% a year in 2003 through 2005, before the retail effects of weather variations. The customer and sales growth referred to in this paragraph applies to energy delivery customers. Customer growth for the nine-month period ended September 30, 2003 compared with the prior year period was 3.2%.

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.

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 and our hedging program for managing such costs. See “Natural Gas Supply” in Note 12 for more information on fuel costs.

During the third quarter of 2003, we experienced several unplanned baseload generating unit outages, the most significant of which occurred when, on August 2, 2003, the generator on Unit 3 of our Cholla Power Plant failed (“Cholla 3”). Cholla 3 is expected to be out of service until the end of November 2003.

Operations and Maintenance Expenses Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors. In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $34 million before taxes in voluntary severance costs in the second half of 2002.

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

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. Our average property tax rate was 9.7%

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. In addition, see Note 19 for discussion of AFUDC.

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 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.

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

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 “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include, but are not limited to:


	•	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 and legislative proceedings relating to the restructuring;

	•	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;

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

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

	•	energy usage;

	•	weather variations affecting local and regional customer energy usage;

	•	conservation programs;

	•	power plant performance;


	•	market prices for electricity and gas;

	•	changes in GAAP;

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

	•	our ability to manage our marketing and trading activities and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

	•	technological developments in the electric industry;

	•	the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommissioning trust funds; and

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

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

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 derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. The ERMC, consisting of senior officers, 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 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 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.

Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Condensed Balance Sheets. For non-trading derivative instruments that qualify for hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of accumulated other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss) and are recognized in income when the underlying transaction impacts earnings.

Derivatives associated with trading activities are adjusted to fair value through income. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered.

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


	•	Marketing and Trading — both non-trading and trading derivative instruments of our competitive business segment; and

	•	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.

The following tables show the changes in mark-to-market of our regulated electricity and marketing and trading derivative positions for the nine months ended September 30, 2003 and 2002 (dollars in millions):

As of September 30, 2003, a hypothetical adverse price movement of 10% in the market price of our risk management and trading assets and liabilities would have decreased the fair market value of these contracts by approximately $11 million, compared to a $15 million decrease that would have been realized as of September 30, 2002. A hypothetical favorable price movement of 10% would have increased the fair market value of these contracts by approximately $12 million, compared to a $17 million increase that would have been realized as of September 30, 2002. These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

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 related to 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. We also enter into credit default swap instruments to limit our credit risk related to certain counterparties. Valuation adjustments are

established representing our estimated credit losses on our overall exposure to counterparties. See “Critical Accounting Policies — Mark-to-Market Accounting” in Item 7 of our 2002 10-K for more discussion on our valuation methods.

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.

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.

See Note 12 of Notes to Condensed Financial Statements in Part 1, Item 1, of this report for a discussion of the Company’s appeal of a FERC order.

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

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

As previously reported, under the terms of a Consent Decree, we agreed to pay $2.72 million to settle the matter relating to the Indian Bend Wash Superfund Site, South Area. See “Environmental Matters — Superfund” in Part II, Item 5 of the March 2003 10-Q. On August 28, 2003, the United States District Court for the District of Arizona entered the Consent Decree. Pursuant to the Consent Decree, we paid $2.32 million to the EPA and $400,000 to the Arizona Department of Environmental Quality.

On September 3, 2003, the EPA advised us that the EPA considers us 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. The EPA has only recently begun to study the OU3 site. Based on the information to date, we do not expect this matter to have a material impact on our financial position, results of operations or liquidity.

The Four Corners region, in which the Four Corners power plant is located, has been experiencing drought conditions that may affect the water supply for the plant in 2003 and 2004, as well as later years if adequate moisture is not received in the watershed that supplies the area. See “Environmental Matters — Water Supply” in Item I, Part 1 of the 2002 10-K and in Part II, Item 5 of the June 2003 10-Q. We entered into agreements with various parties to provide backup supplies of water for 2003, if required, and are continuing to work with area stakeholders to implement additional agreements to minimize the effect, if any, on operations of the plant for 2004 and later years. The effect of the drought cannot be fully assessed at this time, and we cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from the Four Corners power plant.

See Note 12 of Notes to Condensed Financial Statements in Part 1, Item 1 of this report for a discussion of a recent FERC ruling.

In December 2002 FERC issued its order on rehearing of the order regarding the WestConnect proposal, and the WestConnect applicants sought further clarification of certain aspects of the rehearing order. See “Regulation and Competition — Regional Transmission Organizations” in Part I, Item 1 of the 2002 10-K. 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, and the results of this analysis are expected to be completed in the first quarter of 2004.

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:


(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.

During the quarter ended September 30, 2003, and the period from October 1 through November , 2003, we filed the following reports on Form 8-K:

Report dated June 30, 2003 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7 and Item 9).

Report dated September 2, 2003 comprised of slides presented by Pinnacle West at analysts meetings (Item 7 and Item 9).

Report dated September 30, 2003 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7 and Item 9).

Report dated October 6, 2003 regarding the earnings outlook of Pinnacle West and slides presented at Pinnacle West analysts and investors meetings (Item 5, Item 7 and Item 9).

Report dated November 4, 2003 regarding the ACC approval of the issuance of a rate adjustment mechanism order (Item 5).

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.


	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)


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

		For the quarterly period ended September 30, 2003

or

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

		For the transition period from to


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 (Address of principal executive offices)		85072-3999 (Zip Code)


Glossary
PART I -- FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONDENSED STATEMENTS OF INCOME
		CONDENSED STATEMENTS OF INCOME
		CONDENSED STATEMENTS OF INCOME
		CONDENSED BALANCE SHEETS
		CONDENSED BALANCE SHEETS
		CONDENSED STATEMENTS OF CASH FLOWS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
	Item 3. Market Risks
	Item 4. Controls and Procedures
PART II -- OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 5. Other Information
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
INDEX TO EXHIBITS
EX-12.1
Ex-31.1
Ex-31.2
Ex-32.1
EX-32.2
EX-99.1



			Three Months Ended
			September 30,

			2003			2002


			(Dollars in thousands)

			(Unaudited)
ELECTRIC OPERATING REVENUES:
	Regulated electricity segment		$	702,854		$	744,463
	Marketing and trading segment			119,332			9,126

		Total		822,186			753,589

PURCHASED POWER AND FUEL COSTS:
	Regulated electricity segment			279,218			306,244
	Marketing and trading segment			124,736			8,345

		Total		403,954			314,589

OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS				418,232			439,000

OTHER OPERATING EXPENSES:
	Operations and maintenance excluding purchased power and fuel costs			121,158			132,787
	Depreciation and amortization			97,643			100,603
	Income taxes			51,102			58,407
	Other taxes			27,914			26,751

		Total		297,817			318,548

OPERATING INCOME				120,415			120,452

OTHER INCOME (DEDUCTIONS):
	Income taxes			5,048			1,806
	Allowance for equity funds used during construction (Note 19)			11,194			—
	Other income (Note 16)			9,282			1,962
	Other expense (Note 16)			(3,395	)		(6,073	)

		Total		22,129			(2,305	)

INTEREST DEDUCTIONS:
	Interest on long-term debt			37,578			31,900
	Interest on short-term borrowings			1,062			2,609
	Debt discount, premium and expense			754			789
	Capitalized interest (Note 19)			2,794			(3,721	)

		Total		42,188			31,577

NET INCOME			$	100,356		$	86,570



			Nine Months Ended
			September 30,

			2003			2002


			(Dollars in thousands)

			(Unaudited)
ELECTRIC OPERATING REVENUES:
	Regulated electricity segment		$	1,602,483		$	1,635,915
	Marketing and trading segment			318,882			22,188

		Total		1,921,365			1,658,103

PURCHASED POWER AND FUEL COSTS:
	Regulated electricity segment			524,945			490,887
	Marketing and trading segment			314,369			20,712

		Total		839,314			511,599

OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS				1,082,051			1,146,504

OTHER OPERATING EXPENSES:
	Operations and maintenance excluding purchased power and fuel costs			373,538			365,053
	Depreciation and amortization			289,757			297,415
	Income taxes			91,261			123,681
	Other taxes			83,992			81,127

		Total		838,548			867,276

OPERATING INCOME				243,503			279,228

OTHER INCOME (DEDUCTIONS):
	Income taxes			5,846			4,176
	Allowance for equity funds used during construction (Note 19)			11,194			—
	Other income (Note 16)			14,107			4,510
	Other expense (Note 16)			(9,654	)		(13,981	)

		Total		21,493			(5,295	)

INTEREST DEDUCTIONS:
	Interest on long-term debt			105,712			95,938
	Interest on short-term borrowings			3,784			4,908
	Debt discount, premium and expense			2,303			2,129
	Capitalized interest (Note 19)			(6,267	)		(11,814	)

		Total		105,532			91,161

NET INCOME			$	159,464		$	182,772



			Twelve Months Ended
			September 30,

			2003			2002


			(Dollars in thousands)
			(Unaudited)
ELECTRIC OPERATING REVENUES:
	Regulated electricity segment		$	2,025,907		$	2,072,481
	Marketing and trading segment			330,748			28,383

		Total		2,356,655			2,100,864

PURCHASED POWER AND FUEL COSTS:
	Regulated electricity segment			629,426			597,150
	Marketing and trading segment			326,319			21,433

		Total		955,745			618,583

OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS				1,400,910			1,482,281

OTHER OPERATING EXPENSES:
	Operations and maintenance excluding purchased power and fuel costs			504,330			474,259
	Depreciation and amortization			391,982			404,198
	Income taxes			100,533			150,896
	Other taxes			110,790			102,133

		Total		1,107,635			1,131,486

OPERATING INCOME				293,275			350,795

OTHER INCOME (DEDUCTIONS):
	Income taxes			7,818			4,713
	Allowance for equity funds used during construction (Note 19)			11,194			—
	Other income (Note 16)			13,615			10,018
	Other expense (Note 16)			(13,880	)		(21,987	)

		Total		18,747			(7,256	)

INTEREST DEDUCTIONS:
	Interest on long-term debt			138,236			129,025
	Interest on short-term borrowings			4,292			5,508
	Debt discount, premium and expense			3,062			2,778
	Capitalized interest (Note 19)			(9,603	)		(15,431	)

		Total		135,987			121,880

NET INCOME			$	176,035		$	221,659


		September 30,			December 31,
		2003			2002


		(Dollars in thousands)
		(Unaudited)
ASSETS
UTILITY PLANT:
Electric plant in service and held for future use		$	8,641,225		$	8,299,131
Less accumulated depreciation and amortization			3,408,559			3,442,571

	Total		5,232,666			4,856,560
Construction work in progress			273,373			329,089
Intangible assets, net of accumulated amortization (Note 14)			106,546			93,259
Nuclear fuel, net of accumulated amortization			15,139			7,466

	Utility plant — net		5,627,724			5,286,374

INVESTMENTS AND OTHER ASSETS:
Notes receivable from associated companies (Notes 5 and 18)			497,708			—
Decommissioning trust accounts (Note 13)			226,709			194,440
Assets from risk management and trading activities — long-term (Note 10)			20,903			31,622
Other assets			15,564			19,964

	Total investments and other assets		760,884			246,026

CURRENT ASSETS:
Cash and cash equivalents			161,156			42,549
Accounts receivable:
Service customers			258,127			136,945
Other			61,886			202,597
Allowance for doubtful accounts			(1,574	)		(1,341	)
Accrued utility revenues			106,861			72,915
Materials and supplies, at average cost			78,689			79,985
Fossil fuel, at average cost			29,517			28,185
Deferred income taxes			4,094			4,094
Assets from risk management and trading activities (Note 10)			37,683			39,616
Other			54,215			45,361

	Total current assets		790,654			650,906

DEFERRED DEBITS:
Regulatory assets			186,479			241,045
Unamortized debt issue costs			19,150			16,696
Other			83,683			80,760

	Total deferred debits		289,312			338,501

	TOTAL ASSETS	$	7,468,574		$	6,521,807



			Nine Months
			Ended September 30,

			2003			2002


			(Dollars in thousands)
			(Unaudited)
Cash Flows from Operating Activities:
	Net Income		$	159,464		$	182,772
	Items not requiring cash:
		Depreciation and amortization		289,757			297,415
		Nuclear fuel amortization		22,781			23,639
		Allowance for equity funds used during construction		(11,194	)		—
		Deferred income taxes		(43,976	)		149,970
		Change in mark-to-market		7,994			(1,951	)
	Changes in certain current assets and liabilities:
		Accounts receivable		19,934			(85,842	)
		Accrued utility revenues		(33,946	)		(27,642	)
		Materials, supplies and fossil fuel		(36	)		(3,262	)
		Other current assets		(8,854	)		1,460
		Accounts payable		59,617			(10,636	)
		Accrued taxes		144,090			(35,562	)
		Accrued interest		(3,830	)		(9,140	)
		Other current liabilities		1,689			42,124
	Increase in regulatory assets			(10,681	)		(8,709	)
	Change in risk management trading — assets			8,323			(18,087	)
	Change in customer advances			4,081			(17,132	)
	Change in pension liability			2,133			57
	Change in other long-term assets			(14,348	)		(24,111	)
	Change in other long-term liabilities			63,897			11,217

Net cash flow provided by operating activities				656,895			466,580

Cash Flows from Investing Activities:
	Capital expenditures			(305,061	)		(361,701	)
	Capitalized interest			(6,267	)		(11,814	)
	Loans to associated companies			(497,708	)		—
	Other			(4,184	)		50,007

		Net cash flow used for investing activities		(813,220	)		(323,508	)

Cash Flows from Financing Activities:
	Issuance of long-term debt			491,654			369,930
	Repayment and reacquisition of long-term debt			(89,222	)		(247,083	)
	Short-term borrowings — net			—			(145,862	)
	Dividends paid on common stock			(127,500	)		(127,500	)

		Net cash flow provided by financing activities		274,932			(150,515	)

Net increase/(decrease) in cash and cash equivalents				118,607			(7,443	)
Cash and cash equivalents at beginning of period				42,549			16,821

Cash and cash equivalents at end of period			$	161,156		$	9,378

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the period for:
		Interest (excluding capitalized interest)	$	106,930		$	98,091
		Income taxes	$	26,003		$	38,405


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


	Annual Revenue		Percent

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

Total increase	$	175.1		9.8	%



			Three Months					Nine Months				Twelve Months
			Ended					Ended				Ended
			September 30,					September 30,				September 30,

			2003			2002		2003		2002		2003		2002

Operating Revenues:
	Regulated electricity		$	703		$	745	$	1,602	$	1,636	$	2,026	$	2,072
	Marketing and trading			119			9		319		22		331		29

		Total	$	822		$	754	$	1,921	$	1,658	$	2,357	$	2,101

Net Income (Loss):
	Regulated electricity		$	104		$	86	$	156	$	182	$	173	$	218
	Marketing and trading			(4	)		1		3		1		3		4

		Total	$	100		$	87	$	159	$	183	$	176	$	222


			As of		As of
			September 30,		December 31,
			2003		2002

Assets:
	Regulated electricity		$	7,463	$	6,522
	Marketing and trading			6		—

		Total	$	7,469	$	6,522


	•	Note 9 for a new interpretation (FIN No. 46) related to VIEs;



		September 30, 2003

		Current				Current			Other			Net Asset/
		Assets		Investments		Liabilities			Liabilities			(Liability)

Mark-to-Market:
	Marketing and Trading	$	5,849	$	18	$	(11,161	)	$	(1,540	)	$	(6,834	)
	Regulated Electricity		31,834		4,557		(46,917	)		(7,869	)		(18,395	)
Emission allowances — at cost			—		16,328		—			—			16,328

Total		$	37,683	$	20,903	$	(58,078	)	$	(9,409	)	$	(8,901	)



		December 31, 2002

		Current				Current			Other			Net Asset/
		Assets		Investments		Liabilities			Liabilities			(Liability)

Mark-to-Market
	Regulated Electricity	$	39,616	$	6,971	$	(59,773	)	$	(36,678	)	$	(49,864	)
Emission allowances — at cost			—		24,651		—			—			24,651

Total		$	39,616	$	31,622	$	(59,773	)	$	(36,678	)	$	(25,213	)


Item 1.	*Financial Statements*


	*Overview*


	*1999 Settlement Agreement*


	*Retail Electric Competition Rules*


Balance at January 1, 2003			$	219
	Changes attributable to:
		Liabilities incurred		—
		Liabilities settled		—
		Accretion expense		12
		Estimated cash flow revisions		—

Balance at September 30, 2003			$	231


		2002		2001

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

Balance at end of year		$	219	$	204


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


(a)		The net intercompany receivable as of September 30, 2003 related to Pinnacle West Energy primarily consists of the $500 million of debt we issued to Pinnacle West Energy pursuant to the Financing Order. (See “ACC Financing Orders” in Note 5.)


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


	*Operating Results — Three-month period ended September 30, 2003 compared with Three-month period ended September 30, 2002*



			Increase (Decrease)

			Pretax			After Tax

Regulated electricity segment gross margin:
	Higher replacement power costs from plant outages due to more unplanned outages and higher market prices		$	(22	)	$	(13	)
	Increased purchased power and fuel costs primarily due to higher prices for hedged gas and purchased power			(20	)		(12	)
	Retail electricity price reduction effective July 1, 2003			(9	)		(5	)
	Higher retail sales primarily due to customer growth, excluding weather effects			22			13
	Effects of weather on retail sales			7			4
	Miscellaneous items, net			8			5

		Net decrease in regulated electricity segment gross margin		(14	)		(8	)

Marketing and trading segment gross margin:
	Decrease in marketing and trading segment gross margin resulting primarily from the transfer of the marketing and trading activities (see Note 18)			(7	)		(5	)

		Net decrease in marketing and trading segment gross margin		(7	)		(5	)

Net decrease in regulated electricity and marketing and trading segments’ gross margins				(21	)		(13	)
Operations and maintenance expense:
	Severance costs recorded in 2002			23			14
	Increased pension and other benefit costs			(5	)		(3	)
	Other items, net			(6	)		(4	)
Depreciation and amortization:
	Primarily related to increased delivery and other assets			(4	)		(2	)
	Decreased regulatory asset amortization			7			4
Higher other income due to increased interest income and investment gains				7			4
Higher income resulting from our return to the AFUDC method of capitalizing construction finance costs				5			8
Higher interest expense				(4	)		(2	)
Miscellaneous factors, net				1			—
Income tax credits related to prior years				—			7

	Net increase in net income		$	3		$	13


	*Operating Results — Nine-month period ended September 30, 2003 compared with Nine-month period ended September 30, 2002*


	*Operating Results — Twelve-month period ended September 30, 2003 Compared with Twelve-month period ended September 30, 2002*



				Estimated
		Actual

		Nine Months Ended		Twelve Months Ended
		September 30,		December 31,

		2003		2003		2004		2005

Delivery		$	215	$	280	$	307	$	386
Generation(a)			86		132		108		159
Other			5		5		2		2

	Total	$	306	$	417	$	417	$	547


	Moody’s		Standard & Poor’s

Senior secured		A3		A-
Senior unsecured		Baa1		BBB
Secured lease obligation bonds		Baa2		BBB
Commercial paper		P-2		A-2
Outlook		Stable		Stable


1999		2000		2001		2002		2003		2004		Total

$	164	$	158	$	145	$	115	$	86	$	18	$	686


Exhibit
No.		Description

	12.1	Ratio of Earnings to Fixed Charges
	31.1	Certification of Jack E. Davis, the Registrant’s principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2	Certification of Donald E. Brandt, the Registrant’s principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32.1	Certification of Jack E. Davis, the Registrant’s principal executive officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	Certification of Donald E. Brandt, the Registrant’s principal financial officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	99.1	APS Risk Factors


Exhibit No.		Description

	12.1	Ratio of Earnings to Fixed Charges
	31.1	Certification of Jack E. Davis, the Registrant’s principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2	Certification of Donald E. Brandt, the Registrant’s principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32.1	Certification of Jack E. Davis, the Registrant’s principal executive officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	Certification of Donald E. Brandt, the Registrant’s principal financial officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	99.1	APS Risk Factors