FORM 10-Q

Securities and Exchange Commission

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

For the quarterly period ended June 30, 2004

OR

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

For the transition period from __________ to __________

Commission file number 1-8962

PINNACLE WEST CAPITAL CORPORATION

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

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

Yes x    Noo

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

Yes x    Noo

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, no par value,
outstanding as of August 4, 2004   91,318,091

Table of Contents

Glossary

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)

See Notes to Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(in thousands, except per share amounts)

See Notes to Condensed Consolidated Financial Statements.

4

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
ASSETS

See Notes to Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
LIABILITIES AND EQUITY

See Notes to Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)

See Notes to Condensed Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. The condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.

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

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

4. Changes in Liquidity

     On February 2, 2004, we used proceeds from the $165 million Floating Rate Notes issued on November 12, 2003 and short-term borrowings to pay down the maturing $215 million 4.5% Senior Notes due 2004.

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

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

     Also on March 31, 2004, Coconino County, Arizona Pollution Control Corporation issued $13 million of variable interest rate pollution control bonds, 2004 Series A, due 2034 to refinance $13 million of outstanding pollution control bonds. These bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and

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Coconino County, Arizona Pollution Control Corporation. The 2004 Series A bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets.

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

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

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

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

	•		$167 million in 2004;
	•		$619 million in 2005;
	•		$397 million in 2006;
	•		$175 million in 2007;
	•		$6 million in 2008; and
	•		$1.847 billion thereafter.

     As of May 2004, SNWA has paid Pinnacle West Energy $93 million for a 25% interest in the 570 MW Silverhawk combined cycle plant.

5. Regulatory Matters

Electric Industry Restructuring

State

     Overview of Pending Rate Case

     On June 27, 2003, APS filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, to become effective July 1, 2004. An ACC ALJ has issued various procedural orders staying the existing schedule until at least August 18, 2004, as the parties continue settlement discussions. Based on these recent procedural orders, hearings could begin no earlier than mid to late September 2004. The

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major components of the request are described under “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.

     1999 Settlement Agreement

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

	•		APS has 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 APS for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.
	•		There was a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor APS was prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constituted an emergency, such as an inability to finance on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.
	•		APS is being permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004, or when the rate case is decided. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.
	•		APS’ 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

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			Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. APS opened its 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 APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
	•		Prior to the 1999 Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its 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 APS will not be allowed to recover $183 million net present value (in 1999 dollars) ($234 million pre-tax) of the $533 million. The 1999 Settlement Agreement provides that APS 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 “APS General Rate Case and Retail Rate Adjustment Mechanisms,” APS is seeking to recover amounts written off by APS as a result of the 1999 Settlement Agreement.
	•		The 1999 Settlement Agreement required APS to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that APS would be allowed to defer and later collect, beginning July 1, 2004, 67% of its costs to accomplish the required transfer of generation assets to an affiliate. However, as discussed below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing the Track A Order, an order preventing APS from transferring its generation assets. APS is seeking to recover all costs incurred by APS in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.

     Retail Electric Competition Rules

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

•

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

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	•		Effective January 1, 2001, retail access became available to all APS 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, APS received a waiver to allow transfer of its competitive electric assets and services to affiliates no later than December 31, 2002. However, as discussed below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require APS to transfer its 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, APS 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 APS’ property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute.

     Provider of Last Resort Obligation

     Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is, under the Rules, the “provider of last resort” for

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

     Track A Order

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

	•		reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets either to an unrelated third party or to a separate corporate affiliate; and
	•		unilaterally modified the 1999 Settlement Agreement, which authorized APS’ transfer of its generating assets, and directed APS to cancel its activities to transfer its generation assets to Pinnacle West Energy.

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

•

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

•

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

•

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

•

the appropriate treatment of costs incurred by APS 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 APS’ request to provide $500 million of financing or credit support to Pinnacle West Energy or the Company, with appropriate

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conditions, APS’ 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, APS’ appeals of the Track A Order are limited to the issues described in the preceding bullet points.

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

     Track B Order

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

     The order recognized APS’ 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 APS and any affiliate of APS participating in the competitive solicitation, requires that APS treat bidders in a nondiscriminatory manner and requires APS to file a protocol regarding short-term and emergency procurements. The order permits the provision by APS of corporate oversight, support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with confidential APS bidding information that is not available to other bidders. The order directs APS 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 APS to prepare a report evaluating environmental issues relating to the procurement, and a series of workshops on environmental risk management will be commenced thereafter.

     APS issued requests for proposals in March 2003 and, by May 6, 2003, APS entered into contracts to meet all or a portion of its 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.

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(3)

Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.

     ACC Financing Order

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

	•		any debt issued by APS pursuant to the order must be unsecured;
	•		the APS Loan must be callable and secured by the PWEC Dedicated Assets;
	•		the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on APS 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 APS’ cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;
	•		APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its 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 APS and its 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:

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	•		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; 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, APS submitted its report on these matters to the ACC staff. The ACC has indicated that the preliminary investigation would be addressed in the pending general rate case (see below).

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

     APS General Rate Case and Retail Rate Adjustment Mechanisms

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

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

	•		complying with the provisions of the 1999 Settlement Agreement;
	•		incorporating significant increases in fuel and purchased power costs, including results of purchases through the ACC’s Track B procurement process;
	•		recognizing changes in APS’ cost of service, cost allocation and rate design;
	•		obtaining rate recognition of the PWEC Dedicated Assets;
	•		recovering $234 million written off by APS as a result of the 1999 Settlement Agreement; and

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•

recovering restructuring and compliance costs associated with the Rules.

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

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

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

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

     The requested rate base includes the PWEC Dedicated Assets, with a total combined capacity of approximately 1,800 MW. These assets were included at their then estimated July 1, 2004 net book value. Upon approval of the request, the PWEC Dedicated Assets would be transferred to APS 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 APS as a result of the 1999 Settlement Agreement. See “1999 Settlement Agreement” above.

     The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow APS 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 APS 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

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with complying with the Rules) were also tentatively approved for subsequent implementation in the general rate case. The provisions of this order will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend, modify or reconsider, in its entirety, this November 4 order during the rate case.

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

	•		the ACC “litigation” staff;
	•		the Arizona Residential Utility Consumers Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and
	•		other approved rate case interveners.

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

	•		decrease APS’ annual retail electricity revenues by at least $142.7 million, which would result in a rate decrease of approximately 8%, based on a 9% return on equity;
	•		not allow the PWEC Dedicated Assets to be included in APS’ rate base;
	•		not allow APS to recover any of the $234 million pretax written off as a result of the 1999 Settlement Agreement; and
	•		not implement any adjustment mechanisms for fuel and purchased power.

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

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

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

	•		decrease APS’ annual retail electricity revenues by $53.6 million, which would result in a rate decrease of approximately 2.84%, based on a 9.5% return on equity;
	•		not allow the PWEC Dedicated Assets to be included in APS’ rate base;
	•		not allow APS to recover any of the $234 million pretax written off as a result of the 1999 Settlement Agreement; and
	•		not implement any adjustment mechanisms for fuel and purchased power.

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

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

     Request for Proposals and Asset Purchase Agreement

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

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

     On June 1, 2004, APS and PPL Sundance filed a joint application with the ACC requesting approval of the transaction on or before December 31, 2004. APS also

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requested, among other things, that the Sundance Generating Station be included in APS’ rates in APS’ next rate case and that certain operating and capital costs be deferred until that time. APS is not requesting that the Sundance Generating Station be reflected in its current general rate case before the ACC.

     APS does not expect to enter into any additional transactions as a result of the RFP.

Federal

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

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

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

General

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

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6. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit pension plan, a nonqualified supplemental excess benefit retirement plan, and other postretirement benefits for the employees of Pinnacle West and our subsidiaries.

     On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy for prescription drug costs provided the benefit plan is considered actuarially equivalent to Medicare Part D. We believe that our plan is considered actuarially equivalent to Medicare Part D, and thus would qualify for the federal subsidy.

     The FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to address the accounting for the effects of the Act for companies that sponsor postretirement health care benefit plans that provide prescription drug benefits. The guidance allows a retroactive or prospective adoption and is effective July 1, 2004. Although our current financial statements do not reflect any amount for the subsidy, we estimate a reduction in the accumulated postretirement benefit obligation of approximately $65 million. Based upon various assumptions, we estimate an annual after-tax reduction in net periodic postretirement benefit expense of approximately $5 million, excluding amounts capitalized as construction overhead or billed to electric plant participants.

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

Contributions

     The United States Pension Stability Act was signed into law on April 10, 2004. Under this new legislation, our required pension contribution in 2004 is $35 million, which we

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plan to contribute in the third quarter. We have contributed approximately $14 million to our other postretirement benefits plan in 2004 through June.

7. Business Segments

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

	•		our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses and related activities, and includes electricity generation, transmission and distribution;
	•		our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services; and
	•		our real estate segment, which consists of SunCor’s real estate development and investment activities.

     The amounts in our other segment include activities principally related to El Dorado’s investment in NAC, as well as the parent company and APS Energy Services’ non-commodity services. Financial data for our business segments follows (dollars in millions):

(a)

Real estate net income includes income from discontinued operations (net of income taxes) in the following amounts: $0.3 million and $1 million for the three months ended June 30, 2004 and 2003, respectively; and $1 million and $6 million for the six months ended June 30, 2004 and 2003, respectively. See Note 18 for further discussion of our real estate activities.

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(b)

The three and six months ended June 30, 2004 include a $35 million gain ($21 million after tax) related to the sale of El Dorado’s limited partnership interest in the Phoenix Suns (see Note 19).

8. Accounting Matters

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

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

9. Variable Interest Entities

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

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

     APS is exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does 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), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of June 30, 2004, APS would have been required to assume approximately $250 million of debt and pay the equity participants approximately $195 million.

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

10. Derivative Instruments and Energy Trading Activities

     We are exposed to the impact of market fluctuations in interest rates and 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 instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge our exposure to changes in interest rates and 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 transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Cash Flow Hedges

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

     As of June 30, 2004, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions was approximately five years. During the twelve months ending June 30, 2005, we estimate that a net gain of $50 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect on earnings of market price changes for the related hedged transactions.

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

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	•		Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and
	•		Marketing and Trading – both non-trading and trading derivative instruments of our competitive business segment.

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

June 30, 2004

December 31, 2003

     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $1 million at June 30, 2004 and $1 million at December 31, 2003, and is included in investments and other assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $43 million at June 30, 2004 and $12 million at

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December 31, 2003, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.

     Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represented approximately 26% of our $373 million of risk management and trading assets as of June 30, 2004. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

Fair Value Hedges

     On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% senior note. The purpose of these hedges is to protect against significant fluctuations in the fair value of our debt. Our interest rate swaps are considered to be fully effective with any resulting gains or losses on the derivative offset by a similar loss or gain amount on the underlying fair value of debt. The fair value of the interest rate swaps was $2.4 million at June 30, 2004 and is included in other assets with the corresponding offset in long-term debt less current maturities on the Condensed Consolidated Balance Sheets.

11. Comprehensive Income

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

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(a)

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

(b)

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

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station — Spent Fuel and Waste Disposal

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

     Based upon current estimates of the amount of spent fuel and the cost of storage, APS currently estimates it will incur $115 million over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of June 30, 2004, APS had spent $8 million and recorded a liability of $42 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. APS has recorded a corresponding regulatory asset of $50 million and is seeking recovery of these costs through future rates (see “APS General Rate Case and Retail Rate Mechanisms” in Note 5).

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California Energy Market Issues and Refunds in the Pacific Northwest

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

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

     On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its Staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

     PG&E filed for bankruptcy protection in 2001. In the fourth quarter of 2003, the CPUC and the Bankruptcy Court accepted PG&E’s plan of reorganization. The plan indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstanding, undisputed debts. PG&E emerged from bankruptcy protection on April 12, 2004 and settled all outstanding, undisputed debts with us.

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

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other participants in the PX and California independent system operator markets, including APS, attempting to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit.

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

Natural Gas Supply

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

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

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

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Environmental Matters — Superfund

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

Asset Purchase Agreement

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

13. Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. The Price Anderson Act currently limits the combined public liability of nuclear reactor owners to $10.76 billion for claims that could arise from a single nuclear incident. The Palo Verde participants purchase the maximum available commercial insurance of $300 million. The balance of the $10.46 billion is provided by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS 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 APS’ interest in the three Palo Verde units, APS’ 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. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The estimated maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $16 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

14. Stock-Based Compensation

     Pinnacle West offers stock-based compensation plans for officers and key employees of the Company and our subsidiaries. In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123,

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“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, stock compensation expense and earnings per share for the three and six months ended June 30, 2004 and 2003 to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through June 30, 2004 (dollars in thousands, except per share amounts):

15. Other Income and Other Expense

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

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(a)

The three and six months ended June 30, 2004 include a $35 million gain ($21 million after tax) related to the sale of El Dorado’s limited partnership interest in the Phoenix Suns (see Note 19).

(b)

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

16. Guarantees

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction program, transmission service guarantees for West Phoenix Unit 5 and long-term service agreement guarantees for new power plants. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products and enable El Dorado to support the activities of NAC. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s guarantees on behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at June 30, 2004 are as follows (dollars in millions):

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     At June 30, 2004, we had entered into approximately $40 million of letters of credit which support various construction agreements. These letters of credit expire in 2004 and 2005. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required. Pinnacle West has approximately $3 million of letters of credit related to workers’ compensation expiring in 2004.

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At June 30, 2004, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. See Note 4 for more information. The letters of credit are available to fund the payment of principal and interest of such debt obligations. In July 2004, $150 million of these letters of credit were renewed for a three-year term and expire in 2007. The remainder expire in 2005. APS has also entered into approximately $102 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2005. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2004. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

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

17. Earnings Per Share

     The following table presents earnings per weighted average common share outstanding for the three and six months ended June 30, 2004 and 2003:

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     The following table reconciles weighted-average common shares outstanding – basic to weighted-average common shares outstanding – diluted that are used in the earnings per share calculation in the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2004 and 2003 (in thousands):

     Options to purchase 2,325,165 shares of common stock for the three month period ended June 30, 2004 and 2,355,287 shares of common stock for the six month period ended June 30, 2004 were outstanding but were not included in the computation of earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share for that same reason were 1,784,168 shares for the three month period ended June 30, 2003 and 2,026,228 shares for the six month period ended June 30, 2003.

     18. Real Estate Activities – Discontinued Operations

     For the three- and six-month periods ended June 30, 2003, SunCor recorded an after tax gain of $1 million ($2 million pretax) and $6 million ($10 million pretax), respectively, as a result of the sale of its water utility company. The amounts of the gain on the sale and operating income of the water utility company in the current and prior periods

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are classified as discontinued operations on our Condensed Consolidated Statements of Income.

19. Sale of Phoenix Suns Partnership Interest

     In June 2004, the Phoenix Suns Limited Partnership, in which El Dorado held a limited partnership interest, sold the partnership’s assets to a new investor group. The transaction resulted in a gain for El Dorado of approximately $35 million pretax ($21 million after income taxes), which is reflected in other income on the Condensed Consolidated Statement of Income. Additionally, $23 million in cash was received in July 2004 and $12 million will be received in 2007.

     20. Subsequent Event – Sale of NAC

     In July 2004, we entered into an agreement to sell our investment in NAC Holding Inc. and NAC International Inc. (NAC). The transaction is expected to close later this year and result in an after-tax gain of approximately $6 million, which will be classified as discontinued operations. The operating income related to NAC in the current and prior periods will also be classified as discontinued operations in our Condensed Consolidated Statements of Income in the third quarter.

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PINNACLE WEST CAPITAL CORPORATION

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