FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

(Mark One)

OR

     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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

     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 provided by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is providing 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 providing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

 

     The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado and Pinnacle West Marketing & Trading. By the end of 2008, substantially all of Pinnacle West Marketing & Trading’s contracts were transferred to APS or expired. 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.

     Our unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the Notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. These condensed consolidated statements and notes should be read in conjunction with the consolidated financial statements and related notes included in our 2008 Form 10-K. These condensed consolidated financial statements and notes have been prepared consistently with the 2008 Form 10-K with the exception of the reclassification of certain prior-year amounts on our Condensed Consolidated Statement of Income, Condensed Consolidated Balance Sheets and Condensed Consolidated Statement of Cash Flows in accordance with SFAS No. 160 (see Note 19) and SFAS No. 144 (see Note 17).

     Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate activities, such as the real estate impairment charge recorded in the first quarter of 2009 (see Note 21), can have significant impacts on our results for interim periods. For these reasons, results for interim periods do not necessarily represent results expected for the year.

     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements as of March 31, 2009 (dollars in millions):

     The credit and liquidity markets experienced significant stress beginning the week of September 15, 2008. While Pinnacle West’s and APS’ ability to issue commercial paper has been negatively impacted by market conditions, they have both been able to access existing credit facilities, ensuring adequate liquidity. Cash on hand is being invested in money market funds consisting of U.S. Treasury and government agency securities and repurchase agreements collateralized fully by U.S. Treasury and government agency securities.

     Pinnacle West (parent company) has a $283 million revolving credit facility that terminates in December 2010. The revolver is available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit of up to $94 million. At March 31, 2009, the parent company had outstanding $166 million of borrowings under its revolving credit facility and approximately $7 million of letters of credit. It also had no commercial paper outstanding at March 31, 2009. At March 31, 2009, the parent company had remaining capacity available under its revolver of approximately $110 million and had cash and investments of approximately $3 million.

     On February 26, 2009, APS issued $500 million of 8.75% unsecured senior notes that mature on March 1, 2019. Net proceeds from the sale of the notes were used to repay short-term borrowings under two committed revolving lines of credit incurred to fund capital expenditures and for general corporate purposes.

     APS has two committed revolving credit facilities totaling $866 million, of which $377 million terminates in December 2010 and $489 million terminates in September 2011. The revolvers are available either to support the issuance of up to $250 million in commercial paper (see discussion above) or to be used for bank borrowings, including issuances of letters of credit up to $583 million. At March 31, 2009, APS had borrowings of approximately $236 million and no letters of credit under its revolving lines of credit. At March 31, 2009, APS had remaining capacity available under its revolvers of $630 million and had cash and investments of approximately $18 million.

     The interest rates on eleven issues of APS’ pollution control bonds, in the aggregate amount of approximately $343 million, are reset every seven days through auction processes. These bonds are supported by bond insurance policies provided by Ambac Assurance Corporation (“Ambac”), and the interest rates on the bonds can be directly affected by the rating of the bond insurer. Certain bond insurers, including Ambac, have had downgrades of their credit ratings. Downgrades of bond insurers result in downgrades of the insured bonds, which increases the possibility of a “failed auction” and results in higher interest rates during the failed auction periods. When auctions of APS bonds fail, the APS bondholders receive the maximum 14% annual interest rate for the week of the failed auction. For the three months ended March 31, 2009, we had 15 failed auctions, which represented about 11% of all of our auctions. The average interest rate at March 31, 2009 on the auction rate securities was 7.0%. We continue to closely monitor this market and, if market and business conditions allow, we are planning on refunding and reissuing these bonds during 2009. We do not expect, however, that our auction rate interest exposure will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.

     An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At March 31, 2009, APS’ common equity ratio, as defined, was 49%. Its total common equity was approximately $3.2 billion,

     The SunCor Secured Revolver was recently extended for a twelve-month period to January 2010 and requires SunCor to reduce its outstanding borrowings by specified amounts over the term of the facility. As of March 31, 2009, approximately $108 million of borrowings were outstanding under the SunCor Secured Revolver and approximately $67 million of debt was outstanding under other SunCor credit facilities. SunCor intends to apply the proceeds of planned asset sales (see Note 21) to the accelerated repayment of the SunCor Secured Revolver and SunCor’s other outstanding debt, including several project loans totaling approximately $24 million which recently matured. The impairment charges discussed in Note 21 and the maturity and non-payment of the project loans resulted in violations of certain covenants contained in the SunCor Secured Revolver and SunCor’s other credit facilities. If SunCor is unable to obtain waivers or similar relief from its lenders, which it is currently seeking, SunCor could be required to immediately repay its outstanding indebtedness under the SunCor Secured Revolver and its other credit facilities. Such debt acceleration would have a material adverse impact on SunCor’s business and its financial position. Neither Pinnacle West nor any of its other subsidiaries has guaranteed any SunCor indebtedness. A SunCor debt default would not result in a cross-default of any of the debt of Pinnacle West or any of its other subsidiaries. As a result, Pinnacle West does not believe that SunCor’s inability to obtain waivers or similar relief from SunCor’s lenders would have a material adverse impact on Pinnacle West’s cash flows or liquidity.

     As of March 31, 2009, SunCor could not transfer any cash dividends to Pinnacle West as a result of the covenants mentioned above. The restriction does not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

     2008 General Retail Rate Case

     Summary of APS Request and Interim Rate Surcharge — On June 2, 2008, APS filed with the ACC updated financial statements, testimony and other data in the general rate case originally filed on March 24, 2008. In its filing, APS requested a net retail rate increase of $278.2 million effective no later than October 1, 2009, which represents a base rate increase of $448.2 million less the reclassification of $170 million of fuel and purchased power revenues from the existing PSA to base rates.

     On December 18, 2008, the ACC approved an emergency interim base rate surcharge for APS. This surcharge became effective for retail customer bills issued after December 31, 2008 and will continue in effect until a decision in the general rate case becomes effective. This surcharge increased annual pretax retail revenues by approximately $65.2 million, and is subject to refund with interest pending the final outcome of APS’ general retail rate case.

     The interim rate decision required APS to, among other things, examine its operations and expenses, targeting additional cuts of at least $20 million, report the results of its study to the ACC no later than March 18, 2009, and reinvest the savings and surcharge revenues in infrastructure and technology necessary to serve APS customers and reduce the need for external debt financing. On March 18, 2009, APS filed a letter with the ACC identifying a minimum of $25.9 million of specific pretax annualized cost reductions, including decreases in operations and maintenance and other expenses, as well as some capital expenditure reductions.

     Proposed Settlement— APS and the other parties to the rate case began settlement discussions on January 30, 2009 and, on May 4, 2009, they filed a term sheet with the ACC outlining the major terms for settlement of the rate case as agreed to by the parties. The parties also filed a request for procedural order, indicating that the parties will file the definitive settlement agreement on June 12, 2009, and proposing that testimony filings be made by APS and other parties to the case in July and August, and that the hearing begin on August 17, 2009. The ACC must approve any definitive settlement agreement entered into by the parties. We cannot predict whether the parties will enter into a definitive settlement agreement or, if the parties do so, whether or when the ACC would approve the agreement.

     The settlement term sheet includes the following key provisions:

     The parties also agreed to a rate case filing plan in which APS may file its next two general rate cases on or after June 1, 2011 and June 1, 2013, respectively. APS may not request its next general retail rate increase to be effective prior to July 1, 2012. In addition, the parties intend to process these subsequent rate cases within twelve months of sufficiency findings from the ACC staff.

     The following disclosure addresses the rate request that APS filed in June 2008 and the recommendations of various intervenors, including the ACC staff, in response to APS’ request. Although the settlement term sheet contains a framework for the settlement of the rate case, APS’ request and the intervenors’ recommendations would reflect the parties’ current positions if a settlement of the rate case is not reached or is not approved by the ACC.

     Key Provisions of APS’ June 2, 2008 Request — In its June 2, 2008 filing, APS requested a net retail rate increase of $278.2 million effective no later than October 1, 2009, which represents a base rate increase of $448.2 million less the reclassification of $170 million of fuel and purchased power revenues from the existing PSA to base rates. As proposed by APS, the updated request would result in an average rate increase of 8.5% for existing customers plus the establishment of a new growth-related impact fee to be charged to new connections.

     The key financial provisions of the updated request include:

     The update also requested that the ACC adopt certain goals for APS to improve its financial strength, which include: allowing APS’ internal cash flow generation to cover its operating and capital costs of providing service; stabilizing and improving APS’ credit ratings; and providing a meaningful and ongoing opportunity for APS to achieve a reasonable return on the fair value of its property.

     In addition, APS requested various modifications to the Environmental Improvement Surcharge and the Demand Side Management Adjustment Clause that would allow APS to expand its conservation and demand-side management programs and support environmental upgrades to APS facilities in response to and in anticipation of future environmental requirements.

     ACC Staff Rate Case Recommendation — On December 19, 2008, the ACC staff and other intervenors filed their initial written testimony with the ACC in the general retail rate case. In its filed testimony, the ACC staff recommended a number of cost disallowances and test-year adjustments that decrease APS’ base rate request by $141.6 million. The principal

components of the revenue increase recommended by the ACC staff are $155.1 million for non-fuel increases and $11.4 million for fuel and purchased power costs reflected in base rates (net of the reclassification of $140.1 million of existing PSA revenues to base rates).

     Other Intervenors’ Recommendations — Other intervenors in the rate case include the Arizona Residential Utility Consumer Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and Arizonans for Electric Choice and Competition (“AECC”), a coalition that advocates on behalf of commercial and industrial utility customers. RUCO recommended no net rate change after reclassification of $170.0 million of PSA revenues to base rates, based on a rate base of $4.9 billion, a base fuel rate of $0.0388 per kWh, APS’ proposed capital structure, and a return on common equity of 9.6%. AECC recommended that APS’ request be reduced by $101.4 million (of which $42.5 million was a reduction in fuel and purchased power expense).

     PSA Balance

     The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for the three-month period ended March 31, 2009 and 2008 (dollars in millions):

     The PSA annual adjustor rate is reset for a “PSA Year” effective for a twelve-month period beginning February 1 each year. The PSA rate for the PSA Year that began February 1, 2008 was set at $0.004 per kWh. The PSA rate for the PSA year that began February 1, 2009 was set at $0.0053 per kWh. The PSA rate may not be increased more than $0.004 per kWh in a year without permission of the ACC. The $49 million regulatory liability at March 31, 2009 reflects the seasonal nature of fuel and purchased power costs and lower average prices. Any uncollected (overcollected) deferrals during the 2009 PSA Year resulting from this limit will be included in the historical component of the PSA rate for the PSA Year beginning February 1, 2010.

     Formula Transmission Tariff

     In July 2008, the FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect the costs that APS incurs in providing transmission services. The formula rate is updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. A large portion of the rate represents charges for transmission services to serve APS’ retail

customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with the ACC under the transmission cost adjustor (“TCA”) mechanism, by which changes in Retail Transmission Charges can be reflected in APS’ retail rates.

     In 2008, APS was authorized to implement increases in its annual transmission revenues based on calculations filed with the FERC using data for its 2006 and 2007 fiscal years. Increases in APS’ annual transmission revenues of $28 million became effective March 1, 2008 and $15 million became effective June 1, 2008. The ACC allowed APS to reflect the related increased Retail Transmission Charges in its retail rates through the TCA, resulting in increases of annual retail revenues of $27 million effective March 1, 2008 and $13 million effective July 3, 2008.

     Equity Infusion Approval

     On May 2, 2008, Pinnacle West filed a notice with the ACC that would allow Pinnacle West to infuse up to $400 million of equity into APS in the event Pinnacle West deems it appropriate to do so to strengthen or maintain APS’ financial integrity. Under Arizona law and implementing regulatory decisions, Pinnacle West is required to give such notice at least 120 days prior to an equity infusion into APS that exceeds $150 million in a single calendar year. On August 6, 2008, the ACC issued an order permitting the infusion to occur on or before December 31, 2009. Pursuant to the terms of the proposed retail rate case settlement, APS would have authorization to obtain equity infusions of up to $700 million during the period beginning with the execution of the definitive settlement agreement through December 31, 2014, and such authorization would replace the $400 million authorization described above.

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified 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’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in millions):

     At December 31, 2008, we estimated the minimum contribution to our pension plan to be approximately $36 million in 2009 and approximately $25 million in 2010. A recent change in IRS regulations allows alternative measurement dates to determine the interest rate used to value pension liabilities for funding purposes. As a result of this change, we now estimate our minimum pension contribution to be zero in both 2009 and 2010. The expected contribution to our other postretirement benefit plans in 2009 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

     Pinnacle West’s two reportable business segments are:

     Financial data for the three months ended March 31, 2009 and 2008 and at March 31, 2009 and December 31, 2008 is provided as follows (dollars in millions):

     As of March 31, 2009, the tax year ended December 31, 2005 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 1999. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next 12 months.

     Pinnacle West expects to recognize approximately $100 million of cash tax benefits related to SunCor’s strategic asset sales (see Note 21) which will not be realized until the asset sale transactions are completed. Approximately $80 million of these benefits were recorded in the first quarter of 2009 as reductions to income tax expense related to the current impairment charges. The additional $20 million of tax benefits were recorded as reductions to income tax expense related to the SunCor impairment charge recorded in the fourth quarter of 2008.

     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, 2009, APS would have been required to assume approximately $174 million of debt and pay the equity participants approximately $162 million.

     SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Condensed Consolidated Balance Sheets related to these arrangements were approximately $29 million at March 31, 2009 and December 31, 2008.

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. 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 may use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of March 31, 2009, we hedged certain exposures to the price variability of commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

     We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales scope exception and are accounted for under the accrual method of accounting. Due to the scope exception, these derivative instruments are excluded from our derivative discussion and disclosures below.

     We enter into derivative instrument positions for economic hedging purposes. In some instances, these economic hedges may not qualify as accounting hedges, or have not been designated as hedges under SFAS No. 133. Those positions not designated or qualifying as accounting hedges under SFAS No. 133 are reported as “non-hedging” instruments in the tables below. The term “hedge,” as it is used in the following disclosure, is used to describe an accounting hedge. We may also invest in derivative instruments for trading purposes; however, for the quarter ended March 31, 2009, there was no material trading activity.

     We designate commodity forward contracts, futures, options and swaps as cash flow hedges. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. For cash flow hedges that are deemed an effective hedge, the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period during which the hedged transaction affects earnings. Hedge effectiveness is the degree to which the derivative contract and the hedged item are correlated and is measured based on the relative changes in

fair value between the derivative contract and the hedged item over time. We assess hedge effectiveness both at inception and on a continuing basis. These assessments exclude the time value of certain options. We recognize in current earnings the gains and losses representing hedge ineffectiveness, and the gains and losses on any hedge components which are excluded from our effectiveness assessment.

     In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Condensed Consolidated Statements of Income, but this does not impact our financial condition, net income or cash flows.

     For its regulated operations, APS defers for future rate treatment approximately 90% of gains and losses on certain derivatives that would otherwise be recognized in income pursuant to the PSA mechanism. Unless otherwise noted, gains and losses from derivatives in the following tables represent the amounts reflected as income after the effect of PSA deferrals.

     We adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” on January 1, 2009. This new standard requires enhanced disclosures about derivative instruments and hedging activities. The adoption of SFAS No. 161 did not have a material impact on our financial statements.

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements.”

     As of March 31, 2009, we had the following gross notional amount of derivatives, which represent both purchases and sales:

     The Effect of Derivative Instruments on the Condensed Consolidated Statements of
Income

     Amounts included in our Condensed Consolidated Statements of Income are net of amounts deferred under the PSA (see Note 5).

     Derivative Instruments in Hedging Relationships

     Gains and losses on derivative instruments in hedging relationships are reflected in operating expenses on the Regulated Electricity Segment Fuel and Purchased Power line on our Condensed Consolidated Statements of Income. This includes amounts reclassified from OCI into income (effective portion realized) and amounts recognized in income from derivatives (ineffective portion and amount excluded from effectiveness testing).

     The following table provides information about these gains and losses and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2009 (dollars in thousands):

     During the next twelve months, we estimate that a net loss of $157 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. In accordance with the PSA, at least 90% of these amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

     Derivative Instruments Not Designated as Hedges

     The following table provides information about our derivatives not designated as hedging instruments and their impact on our Condensed Consolidated Statements of Income during the three months ended March 31, 2009 (dollars in thousands):

     Fair Values of Derivative Instruments in the Condensed Consolidated Balance Sheets

     The following table provides information about the fair value of our derivative instruments. These amounts are located in the asset or liability from risk management and trading activities lines of our Condensed Consolidated Balance Sheets. Amounts are as of March 31, 2009 (dollars in thousands):

     Derivative assets and liabilities in the table are reported on a gross basis and exclude cash collateral and margin accounts. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet, including cash collateral and margin in accordance with FSP FIN 39-1.

     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 69% of Pinnacle West’s $98 million of risk management and trading assets as of March 31, 2009. This exposure relates to a long-term traditional wholesale contract with a counterparty that has very high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties’ securities is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period.  Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We

     Certain of our derivative instruments contain provisions that require our debt to maintain an investment grade credit rating from the major credit rating agencies. If our debt were to fall below investment grade, these provisions could be violated, and the counterparties to the derivative instruments could demand immediate and ongoing full collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position on March 31, 2009 was $515 million for which we had posted collateral of $219 million in the normal course of business. If the credit-risk-related contingent features underlying these agreements had been triggered on March 31, 2009, after off-setting asset positions under master netting arrangements we would have been required to post an additional $197 million of collateral to our counterparties; this amount includes those contracts which qualify for scope exceptions, which are excluded from the derivative details in the above footnote. We also have non-derivative contracts with credit related contingent features which could also require additional collateral if our debt were to fall below investment grade.

     The following table shows the Company’s changes in common stock equity and changes in equity of noncontrolling interests for the three months ended March 31, 2009 and 2008 (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. In August 2008, the United States Court of Appeals for the Federal Circuit issued decisions in three damages actions brought by other nuclear utilities that could result in a decrease in the amount of our recoverable damages; however, additional appeals in those actions are possible and APS continues to monitor the status of those actions. The trial in the APS matter began on January 28, 2009. Testimony and evidence have been presented by both sides. The trial court has set a post-trial briefing schedule and is expected to hear closing arguments in the early summer of 2009.

     APS currently estimates it will incur $132 million (in 2009 dollars) over the current life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2009, APS had a regulatory liability of $25 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

     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. In addition, on March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including APS, failed to properly file rate information at the FERC in connection with sales to California from 2000 to March 2002 under market-based rates. Since 2004, the Ninth Circuit and the FERC have issued various decisions and orders involving the aforementioned issues, including decisions related to: entities subject to FERC jurisdiction and, therefore, potentially owing refunds; applicable refund methodologies; the temporal scope and types of transactions that are properly subject to the refund orders; and the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings. A settlement, resolving APS’ issues with certain California parties for the current refund period, was approved by the FERC in an order issued on June 30, 2008. The resolution of the claims related to the parties involved in this settlement had no material adverse impact on our financial position, results of operations or cash flows. We currently believe the refund claims at the FERC related to the parties not involved in this settlement will have no material adverse impact on our financial position, results of operations or cash flows.

     On July 25, 2001, 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 was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were filed. Although the

FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

     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 are 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, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.

     Salt River Project previously notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserted that certain of these failures to bill APS for such losses and charges may have extended back to 1996 and, as a result, claimed that APS owed it approximately $29 million, which APS disputed.  The parties entered into a settlement agreement on April 9, 2009, resolving these matters. The resolution had no material adverse impact on our financial position, results of operations or cash flows.

     On April 16, 2009, the landlord for our corporate headquarters building announced that it is seeking relief under Chapter 11 of the United States Bankruptcy Code. We currently have several assets on our books related to our landlord, including an asset related to rent payments for the building of approximately $63 million. We are monitoring this matter and, while there can be no assurances as to the ultimate outcome of the matter due to the complexity of the bankruptcy proceedings, we currently do not expect that it will have a material adverse effect on our financial position, results of operations, or cash flows.

     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 financial position, results of operations or cash flows.

     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 $118 million, subject to an annual limit of $18 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 $103 million, with an annual payment limitation of approximately $15 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 approximately $21 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, 2009 and 2008 (dollars in thousands):

     We have issued parental guarantees and obtained letters of credit and surety bonds on behalf of some of our subsidiaries.

     Our parental guarantees for APS relate to commodity energy products. As required by Arizona law, Pinnacle West has also obtained a $10 million bond on behalf of APS in connection with the interim base rate surcharge approved by the ACC in December 2008. In addition, Pinnacle West has obtained approximately $8 million of surety bonds related to APS operations, of which approximately $7 million relates to self-insured workers’ compensation. Our credit support instruments enable APSES to offer energy-related products and services. 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 our subsidiaries. At March 31, 2009 we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover from our subsidiaries amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2009 are as follows (dollars in millions):

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2009, 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 $70 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. 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, 2009 and 2008:

     For the three months ended March 31, 2009 and 2008 the weighted average common shares outstanding were the same for both basic and diluted shares. Options to purchase 625,524 shares of common stock for the three months ended March 31, 2009, and 703,875 shares for the three months ended March 31, 2008 were outstanding but were excluded from the computation of diluted earnings per share because the impact of including those options would be antidilutive.

     SunCor (real estate segment) – In 2009 and 2008, SunCor sold or expects to sell properties that are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. Assets held for sale relate to properties in the amount of $32 million at March 31, 2009. These properties were classified as home inventory at December 31, 2008. In addition, see Note 21 – Real Estate Impairment Charge.

     APSES (other) – Includes activities related to discontinued commodity-related energy services in 2008, and the associated revenues and costs that were reclassified to discontinued operations in 2008.

     The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2009 and 2008 (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 securities and domestic 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, we have recorded the offsetting amount of gains or losses on investment securities in other regulatory liabilities or assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at March 31, 2009 and December 31, 2008 (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, 2009 is as follows (dollars in millions):

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted for our non-financial assets on January 1, 2009. This guidance was adopted for our financial assets on January 1, 2008.

     See Note 10 for a discussion of SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment to SFAS No. 133,” which we adopted January 1, 2009.

     We adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” on January 1, 2009. This guidance provides accounting and reporting

standards for noncontrolling interests in a consolidated subsidiary and clarifies that noncontrolling interests should be reported as equity on the consolidated financial statements. As a result of adopting this guidance, we have disclosed on the face of our financial statements the portion of equity and net income attributable to the noncontrolling interests in consolidated subsidiaries. Additionally, we reclassified $47 million of noncontrolling interests from Other Deferred Credits to Equity on the December 31, 2008 balance sheet. Prior year’s net income attributable to noncontrolling interests was not material to our income statement and was not reclassified. The adoption of this guidance modified our financial statements presentation, but did not have an impact on our financial statement results.

     In December 2008, the FASB issued FASB Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This guidance requires enhanced employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The guidance is effective for us on December 31, 2009. We do not expect it to have a material impact on our financial statements.

     In April 2009, the FASB issued various Staff Positions relating to fair value measurements and impairments. This guidance includes: FASB Staff Position No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”; FASB Staff Position Nos. FAS  115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”; and FASB Staff Position Nos. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” These Staff Positions were effective for us on April 1, 2009. We do not expect them to have a material impact on our financial statements.

     Effective January 1, 2009, we adopted FASB Staff Position No. EITF 03-6-1 (FSP EITF 03-6-1), “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” FSP EITF 03-6-1 requires companies to treat unvested share-based payment awards that have nonforfeitable rights to dividends or dividend equivalents as participating securities when computing earnings per share, pursuant to the two-class method described in SFAS No. 128, “Earnings Per Share.” Our awards do not have nonforfeitable rights to dividends or dividend equivalents and therefore the adoption of this FSP did not have any impact on our financial statements.

     SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and requires companies to disclose the fair value of certain assets and liabilities according to a fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

     Level 1 — Quoted prices in active markets for identical assets or liabilities.

     Level 2 — Quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable.

     Level 3 — Model-derived valuations with unobservable inputs that are supported by little or no market activity.

     As required by SFAS No. 157, assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. We maximize the use of observable inputs and minimize the use of unobservable inputs. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.

     We apply recurring fair value measurements to derivative instruments, nuclear decommissioning trusts, and certain cash equivalents. We may be required to record other assets at fair value on a nonrecurring basis. These nonrecurring fair value measurements typically involve write-downs of individual assets due to impairment.

     In February 2008, the FASB issued FASB Staff Position No. FAS 157-2 (FSP 157-2), “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities by one year. In accordance with FSP 157-2, we delayed the adoption of SFAS No. 157 for our nonfinancial assets and liabilities, except those items recognized or disclosed at fair value on a recurring basis, until January 1, 2009. We adopted SFAS No. 157 for our nonfinancial assets and liabilities on January 1, 2009, and it did not have a material impact on our financial statements.

     Some of our derivative instrument transactions are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near term portion and unobservable valuations for the long-term portions of the transaction. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long term nature of our energy transactions, and is not reflective of material inactive markets.

     The following table presents the fair value at March 31, 2009 of our assets and liabilities that are measured at fair value on a recurring basis for Pinnacle West Consolidated and APS (dollars in millions):