Indicate by check mark whether each 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.

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

PINNACLE WEST CAPITAL CORPORATION

     Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act Rule 12b-2).

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

          Arizona Public Service Company 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 allowed under that General Instruction.

          This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – Administrative Law Judge

APS – Arizona Public Service Company, a subsidiary of the Company

APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

EITF – FASB’s Emerging Issues Task Force

El Dorado – El Dorado Investment Company, a subsidiary of the Company

EPA – United States Environmental Protection Agency

ERMC – Energy Risk Management Committee

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

FIN – FASB Interpretation Number

Fitch – Fitch, Inc.

Four Corners – Four Corners Power Plant

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

IRS – United States Internal Revenue Service

kWh – kilowatt-hour, one thousand watts per hour

Moody’s – Moody’s Investors Service

MWh – megawatt-hour, one million watts per hour

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

Note – a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this report

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned or contracted by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts

Palo Verde – Palo Verde Nuclear Generating Station

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006

Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company

PRP – potentially responsible parties under Superfund

PSA – power supply adjustor

Salt River Project – Salt River Project Agricultural Improvement and Power District

SEC – United States Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

Silverhawk – Silverhawk Power Station

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

SunCor – SunCor Development Company, a subsidiary of the Company

Sundance Plant – 450-megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

2006 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2006

VIE – variable interest entity

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

     The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy (dissolved as of August 31, 2006), APS Energy Services, SunCor, El Dorado and Pinnacle West Marketing & Trading. 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 condensed certain prior year amounts on our condensed consolidated statements of cash flows to conform to current year presentations.

     Our unaudited condensed consolidated financial statements reflect all adjustments that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. 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 2006 Form 10-K.

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

     On January 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its market-based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of long-term debt.

     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions) as of March 31, 2007:

     On December 15, 2006, hearings concluded in APS’ general rate case before the ACC. APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues, designed to recover the following (dollars in millions):

     The request is based on (a) a rate base of $4.5 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.0325 per kWh based on estimated 2007 prices; and (c) a capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity). If the ACC approves the requested base rate increase for fuel and purchased power costs, subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates. See “Power Supply Adjustor” below.

     APS has also suggested three additional measures for the ACC’s consideration to improve APS’ financial metrics while benefiting APS’ customers in the long run:

     The following table summarizes key rate case positions of APS, the ACC staff and the Arizona Residential Utility Consumer Office (“RUCO”), which the Arizona legislature established to represent the interests of residential utility consumers before the ACC:

     Other intervenors in the rate case include Arizonans for Electric Choice and Competition (“AECC”), a business coalition that advocates on behalf of retail electric customers in Arizona; and

Phelps Dodge Mining Company (“Phelps Dodge”). In jointly-filed testimony, AECC and Phelps Dodge recommended that the ACC reduce APS’ requested annual increase by at least $134 million.

     On April 27, 2007, an ACC ALJ issued a recommended order in connection with the rate case and APS’ application to recover through a PSA surcharge approximately $45 million of deferrals related to unplanned 2005 Palo Verde outages. See “Power Supply Adjustor – PSA Deferrals Related to Unplanned Palo Verde Outages” below.

     The ALJ recommended an increase of approximately $286 million, or 13.5%, in APS’ annual base retail revenues, which includes a fuel-related increase of approximately $280 million and non-fuel related increases of approximately $6 million. The ALJ recommended that the rate increase take effect June 1, 2007, at which time the interim PSA adjustor approved on May 1, 2006 would terminate. See “Interim Rate Increase” below. The ALJ’s recommended rate increase is based on a return on equity of 10.75%; a 45%/55% long-term debt/common equity capital structure; a weighted-average cost of capital of 8.32%; an original cost rate base of $4.4 billion; and a base rate for fuel and purchased power costs of $0.0312 per kWh.

     The ALJ recommended various modifications to the PSA, including the following: (a) the annual PSA adjustor would be established based on projected, rather than historical, fuel and purchased power costs; (b) the 90/10 sharing arrangement under which APS absorbs 10% of retail fuel and purchased power costs above the base rate and retains 10% of the benefit below the base rate would be modified to exclude certain costs, such as renewable energy resources and the fixed element of long-term purchase power agreements acquired through competitive procurement; (c) the cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 per kWh limit to changes in the adjustor rate in any one year would remain in effect; and (d) there would not be a preset annual limit on the amount of fuel and purchased power costs that could be recovered through base rates and the PSA. The ALJ recommended that the modified PSA take effect June 1, 2007 based on the difference between APS’ proposed 2007 projected fuel and purchased power costs of $0.0325 per kWh and the base fuel rate of $0.0312 per kWh.

     The ALJ recommended that the ACC not adopt any of APS’ additional suggestions described above to improve APS’ financial metrics (accelerated depreciation, inclusion of construction work in process in rate base, and an attrition adjustment).

     The ALJ recommended (a) the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the PSA deferrals related to unplanned 2005 Palo Verde outages and (b) the recovery by APS of the balance of the PSA deferrals (approximately $34 million) over a twelve-month period through a temporary PSA surcharge to be effective concurrently with the implementation of new rates. As of May 1, 2007, these deferrals totaled approximately $48 million, including accrued interest. The ALJ also recommended that the ACC require APS and the ACC staff to develop “nuclear performance standards” for the ACC to consider in a separate proceeding. See “PSA Deferrals Related to Palo Verde Unplanned Outages” below.

     APS and other parties to the rate case may file exceptions to the recommended order no later than May 15, 2007. APS is currently evaluating the recommended order and expects to file its exceptions to the ALJ’s recommendations by that date. After the exceptions have been filed by APS and the other parties, the ACC will then consider the ALJ’s recommended order and the exceptions. We cannot predict the timing or the outcome of this rate case or the resulting levels of regulated revenues.

     On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006. APS later reduced this request to $232 million, or approximately 11%, due to a decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase was solely to address APS’ under-collection of higher annual fuel and purchased power costs. On May 2, 2006, the ACC approved an order in this matter that, among other things:

     On December 8, 2006, the ACC approved APS’ request to continue the interim PSA adjustor until rates become effective as a result of the general rate case.

     PSA Provisions

     The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for adjustment of retail rates to reflect variations in retail fuel and purchased power costs. Such adjustments are to be implemented by use of PSA adjustor rates and PSA surcharges. On January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject to specified parameters and procedures, including the following:

     2007 PSA Annual Adjustor

     The annual adjustor rate is set for twelve-month periods beginning February 1 of each year. The current PSA annual adjustor rate was set at $0.003987 per kWh effective February 1, 2007, down slightly from the maximum $0.004 annual adjustor rate effective February 1, 2006. The new adjustor rate (a) essentially maintains the approximate 5% retail rate increase that took effect February 1, 2006 as a result of the 2006 PSA Annual Adjustor and

which expired on February 1, 2007 and (b) is designed to recover approximately $109 million of deferred fuel and purchased power costs over the twelve-month period that began February 1, 2007.

     Surcharge for Certain 2005 PSA Deferrals

     On April 12, 2006, the ACC approved APS’ request to recover $15 million of 2005 PSA deferrals over a twelve-month period beginning May 2, 2006, representing a temporary rate increase of approximately 0.7%. Approximately $45 million of 2005 PSA deferrals remain subject to a pending application (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below).

     On February 2, 2006, APS filed with the ACC an application to recover approximately $45 million (plus interest) over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. During the course of the pending general rate case, the ACC staff recommended that the ACC disallow approximately $16 million ($10 million after income taxes) of the $45 million request. The ACC staff’s report alleges that four of the eleven Palo Verde outages in 2005 were “avoidable,” three of which resulted in the recommended disallowance. The report also finds, among other things, that:

     The report also recommends that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.

     APS disagrees with, and has contested, the report’s recommendation that the ACC disallow a portion of the $45 million of PSA deferrals. At the request of the ACC staff, this matter is being addressed by the ACC as part of APS’ pending general rate case. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of these deferrals. See “ALJ Recommended Order” above. APS believes the expenses in question were prudently incurred and, therefore, are recoverable.

     As noted under “Interim Rate Increase” above, the ACC has directed the ACC staff to conduct a “prudence audit” of unplanned 2006 Palo Verde outage costs. This prudence review has not yet been completed. PSA deferrals related to these 2006 outages are estimated to be about $79 million through December 31, 2006. APS believes these expenses were prudently incurred and, therefore, are recoverable.

     Proposed Modifications to PSA (Requested In General Rate Case)

     In its pending general rate case, APS has requested the following modifications to the PSA:

     The ACC staff has recommended the following potential changes to the PSA:

     The ALJ in the rate case has recommended various modifications to the PSA. See “ALJ Recommended Order” above.

     PSA Balance

     The following table shows the changes in the deferred fuel and purchase power regulatory asset for the three months ended March 31, 2007 and 2006 (dollars in millions):

     Price Mitigation Plan

     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. On February 13, 2006, the FERC increased this price cap to $400 per MWh for prospective sales. Sales at prices above the cap must be justified and are subject to potential refund. We do not expect this price cap to have a material impact on our financial statements.

     FERC Order

     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.

     On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ market-based rate authority in the APS control area (the “April 17 Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.

     As a result of the April 17 Order, the Pinnacle West Companies must charge cost-based rates, rather than market-based rates, in the APS control area for sales occurring after the date of the order, April 17, 2006. The Pinnacle West Companies are required to refund any amounts collected that exceed the default cost-based rates for all market rate sales within the APS control area from February 27, 2005 to April 17, 2006.

     The Pinnacle West Companies filed a Request for Rehearing and Clarification of the April 17 Order on May 17, 2006 and submitted a supplemental compliance filing on July 28, 2006. On December 21, 2006, FERC issued an order granting clarification and provided additional details on

what steps the Pinnacle West Companies could take to correct the transmission import study previously submitted. The Pinnacle West Companies complied with this order and filed additional transmission studies and generation market power analyses on February 20, 2007.

     Based upon an analysis of the April 17 Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the April 17 Order will have a material adverse effect on its financial position, results of operations or cash flows.

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a nonqualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries. Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.

     The following table provides details of the plans’ benefit costs for the three months ended March 31, 2007 and 2006. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or capitalized as overhead construction (dollars in millions):

     The contribution to our pension plan in 2007 is estimated to be approximately $22 million, and the contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $21 million. APS’ share is approximately 97% of both plans.

     Pinnacle West’s two principal business segments are:

     Financial data for the three months ended March 31, 2007 and 2006 and at March 31, 2007 and December 31, 2006 by business segment is provided as follows (dollars in millions):

     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2007, it is expected that the IRS will finalize its examination and will issue a settlement on the tax accounting method change. At this time an estimate of the range of reasonably possible change in the uncertain tax position cannot be made. However, we do not expect the ultimate outcome of this examination to have a material

adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows.

     We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.

     The total amount of unrecognized tax benefits recorded in accrued taxes as of January 1, 2007 was $186 million, of which $179 million related to APS. The majority of the unrecognized tax benefits relate to the 2001 tax return position described above. Included in the balance of unrecognized tax benefits at January 1, 2007 are approximately $5 million of tax positions for consolidated Pinnacle West that, if recognized, would decrease our effective tax rate. For APS, approximately $3 million would have the same effect.

     We continue to recognize potential accrued interest related to unrecognized tax benefits in the financial statements as income tax expense. As of January 1, 2007, the total amount of accrued interest expense related to uncertain tax positions was $54 million for consolidated Pinnacle West, which is included as a component of the $186 million unrecognized tax benefit noted above. APS’ share included in the total was approximately $53 million. Additionally, Pinnacle West has accrued $9 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS. The application of FIN 48 did not have a material impact for the quarter ended March 31, 2007.

     As of January 1, 2007, the tax year ending December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ending prior to December 31, 1999 may remain subject to examination by state taxing authorities.

     In 1986, APS entered into agreements with three separate VIE 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. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.

     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 March 31, 2007, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 million.

     We use derivative instruments (primarily forward purchases and sales, swaps, options and futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of fuel, electricity and emission allowances and credits. As of March 31, 2007, we hedged exposures to the price variability of the power and gas commodities for a maximum of 4.8 years. 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.

       The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2007 and 2006 are comprised of the following (dollars in thousands):

     During the next twelve months ending March 31, 2008, we estimate that a net gain of $76 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

     Our assets and liabilities from risk management and trading activities are presented in two categories.

     The following tables summarize our assets and liabilities from risk management and trading activities at March 31, 2007 and December 31, 2006 (dollars in thousands):

     During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps in the regulated electricity segment. We historically presented the buy side and the sell side of such swaps at fair value gross on our consolidated balance sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset/liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $19 million at March 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

     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 $5 million at March 31, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $60 million at March 31, 2007 and $54 million at December 31, 2006, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.

     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 one counterparty for which a worst case exposure represents approximately 11% of Pinnacle West’s $398 million of risk management and trading assets as of March 31, 2007. Our risk management process assesses and monitors the financial exposure of this and all other counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, including the counterparty discussed 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 financial institutions, 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. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

     Components of comprehensive income (loss) for the three months ended March 31, 2007 and 2006 are as follows (dollars in thousands):

Palo Verde Nuclear Generating Station

     Spent Nuclear Fuel and Waste Disposal

     Nuclear power plant operators 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 Policy 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 at least 2017. 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. APS is currently pursuing that damages claim.

     APS currently estimates it will incur $147 million (in 2006 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2007, APS had a regulatory liability of $2.8 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

     NRC Inspection

     In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator started but did not provide electrical output during routine inspections on July 25 and September 22, 2006.

     On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) for this matter. In connection with its finding, the NRC stated that it would “use the NRC Action Matrix to determine the most appropriate response and any increase in NRC oversight, or actions [APS needs] to take in response to the most recent performance deficiencies” and notify APS of its determination at a later date. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix, which will result in an enhanced NRC inspection regimen. APS continues to implement its plan to improve Palo Verde’s operational performance.

     FERC

     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. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.

     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On October 10, 2006, the State of California filed a motion to stay the issuance of the mandate (scheduled to be issued on November 2, 2006) until June 13, 2007. The request for stay was granted. The outcome of the further proceedings cannot be predicted at this time.

     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in 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 Ninth Circuit Court of Appeals and oral argument was held on January 8, 2007. Although the FERC ruling in this 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 cash flows.

     On March 26, 2003, the 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 Independent System Operator 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.

     See “FERC Order” in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.

     Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium through December 31, 2005.

     On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the cost responsibility associated with the changed contractual obligations in a way that would be less favorable to APS than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS’ annual capacity cost could be increased by approximately $3 million per year after income taxes for the period September 2003 through December 2005. This appeal had been stayed pending further consideration by the FERC. On May 26, 2006, the FERC issued an Order on Remand affirming its earlier decision that there is no basis for modifying the settlement rates during the remaining term of the settlement. The party seeking appellate review is continuing to pursue an appeal of this issue and has therefore sought rehearing of the May 26, 2006 order. The FERC’s next status report is due to the DC Circuit Court of Appeals by August 7, 2007.

     In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating

Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.

     In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.

     Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.

     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our results of operations, cash flows or liquidity.

     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 program 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 $15 million per incident, to be periodically adjusted for inflation. 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 $13 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 accidental 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 maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $18.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

     The following table provides detail of other income and other expense for the three months ended March 31, 2007 and 2006 (dollars in thousands):

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to commodity energy products. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our 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 current outstanding guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2007 are as follows (dollars in millions):

     At March 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in late 2007. 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.

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2007, 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 and expire in 2010. APS has also entered into approximately $86 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 2010. Additionally, at March 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2007. 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 enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify 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 provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions 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 indemnification provisions is likely.

     The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2007 and 2006:

     Dilutive stock options and performance shares increased average common shares outstanding by approximately 577,000 shares and 334,000 shares for the three months ended March 31, 2007 and March 31, 2006, respectively.

     For the three-month period ended March 31, 2007, there were no outstanding options to purchase shares excluded from the computation of earnings per share because the options’ exercise prices were less than the average market price of the common shares. Options to purchase shares of common stock that were excluded from the computation of diluted earnings per share were 747,874 shares for the three-month period ended March 31, 2006.

     SunCor (real estate segment) – In 2006 and 2007, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. The following table contains SunCor’s revenue, income before income taxes and income after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2007 and 2006 (dollars in millions):

     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we

record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of unrealized gains (losses) on investment securities in other regulatory liabilities/assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at March 31, 2007 and December 31, 2006 (dollars in millions):

     The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

     The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2007 is as follows (dollars in millions):

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance.

     See Note 8 for a discussion of FASB Interpretation No. 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial.