Pinnacle West Capital - 10-Q quarterly report FY

 

     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

Large accelerated filer þ       Accelerated filer o      Non-accelerated filer o

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o      Accelerated filer o      Non-accelerated filer þ

     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.

GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – Administrative Law Judge

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

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

Base Fuel Rate – the portion of APS’ retail base rates attributable to fuel and purchased power costs

Cholla – Cholla Power Plant

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

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

FIP – Federal Implementation Plan

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

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

2005 Deferrals – PSA deferrals related to 2005 replacement power costs associated with unplanned Palo Verde outages

2006 Deferrals – PSA deferrals related to 2006 replacement power costs associated with unplanned outages or reduced power operations at Palo Verde

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

West Phoenix – West Phoenix Power Plant

(unaudited)

(dollars and shares in thousands, except per share amounts)

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

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

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

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

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

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

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

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, APSES, SunCor, El Dorado, Pinnacle West Marketing & Trading and Pinnacle West Energy (dissolved as of August 31, 2006). 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.

     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 be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2006 Form 10-K. We have condensed certain prior year amounts on our condensed consolidated statements of cash flows to conform to current year presentations.

     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.

     SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60 million, of which $35 million was outstanding at September 30, 2007. The loan matures on April 19, 2009, and may be extended one year if certain conditions are met.

     In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of the proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.

     On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan matures on July 31, 2009, and may be extended annually up to two years.

     At September 30, 2007, APS had borrowings of $150 million under its revolving line of credit. Pinnacle West had borrowings of $105 million under its revolving line of credit. The amounts drawn under the Pinnacle West and APS lines of credit were used for general corporate purposes.

     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 September 30, 2007, APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4 billion, and total capitalization was approximately $6.3 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.5 billion, assuming APS’ total capitalization remains the same.

     SunCor has a $150 million loan facility secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The loan facility requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. As of September 30, 2007, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of these covenants was approximately $213 million.

     As a result of the restrictions in the preceding two paragraphs, as of September 30, 2007, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at September 30, 2007, our consolidated net assets were approximately $3.6 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements as of September 30, 2007 (dollars in millions):

     APS General Rate Case and Power Supply Adjustor

     Retail Rate Increase

     On June 19, 2007, the ACC rendered its decision in APS’ general retail rate case pursuant to which APS had requested a 20.4%, or $435 million, increase in its annual retail electricity revenues. APS’ request was designed to recover approximately $315 million in fuel-related expenses and approximately $120 million in non-fuel related expenses. The ACC order, which was formally issued on June 28, 2007, increased APS’ annual retail base revenues by approximately $322 million, effective July 1, 2007, which includes a fuel-related increase of approximately $315 million (excluding the PSA surcharge for 2005 Deferrals discussed below), or 15.1%, and non-fuel related increases of approximately $7 million. The interim PSA adjustor approved by the ACC on May 1, 2006, which was designed to recover a portion of APS’ fuel and purchased power costs deferred under the PSA, terminated effective with the rate increase, resulting in a net retail rate increase of approximately 6.8%. The base rate increase is premised 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 as of September 30, 2005; and a Base Fuel Rate of $0.0325 per kWh.

     PSA Modifications

     The ACC order modified the PSA in various respects, effective July 1, 2007. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case, provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. As modified by the ACC’s recent order, the PSA is subject to specified parameters and procedures, including the following:

     2008 PSA Year

     On September 28, 2007, APS submitted preliminary forecast calculations to the ACC for the Forward Component, Historical Component and Transition Component for the PSA Year beginning February 1, 2008. APS will update the calculations in a filing to the ACC prior to December 31, 2007. Based upon the preliminary calculations, the PSA rates would be limited to $0.004 per kWh for the 2008 PSA Year. Any uncollected deferrals during the 2008 PSA Year resulting from this limit will flow into the 2009 Historical Component at the end of 2008.

     PSA Deferrals Related to Palo Verde Outages

     APS recorded $45 million of 2005 Deferrals and $79 million of 2006 Deferrals. The ACC order (a) disallowed approximately $14 million, including accrued interest ($8 million after income taxes), of the 2005 Deferrals because the ACC found that the outage costs giving rise to those amounts resulted from APS’ imprudence and (b) approved APS’ recovery of the balance of the 2005 Deferrals (approximately $34 million, including accrued interest) through a temporary PSA surcharge over a twelve-month period effective July 1, 2007. In connection with the interim PSA adjustor approved on May 1, 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. Virtually all of the 2006 Deferrals were associated with a Unit 1 vibration issue. On October 4, 2007 the ACC staff filed a report with the ACC that concludes that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these costs were prudently incurred and that the 2006 Deferrals are, therefore, recoverable.

     PSA Balance

     The following table shows the changes in the deferred fuel and purchase power regulatory asset for the nine months ended September 30, 2007 and 2006 (dollars in millions):

     Other Matters

     The ACC order approved an environmental improvement surcharge (“EIS”) to recover capital costs incurred for environmental improvements made by APS in compliance with federal and state laws or regulatory requirements. The EIS will be set initially at $0.00016 per kWh, designed to produce approximately $4.5 million of cash per year until further order of the ACC.

     The ACC order requires APS and the ACC staff to work to prepare a “nuclear performance standard” that the ACC can consider in a separate proceeding. The parties are currently working together to develop the standard.

     The ACC Order also required APS to file a revised line extension schedule for ACC approval that would eliminate certain footage and equipment allowances for new or expanded electric service and remove any requirement for economic feasibility analyses used to determine whether or how much of an allowance should be granted. This would permit APS to collect, on a current basis, costs related to line extensions. Such pretax costs are currently estimated to be approximately $3,500-$5,000 per new meter set. These are average figures and the actual costs of a service extension will vary by customer class and the particulars of the extension.

     On October 24, 2007, APS filed a proposed amendment to its line extension schedule. On November 2, 2007, the ACC staff issued its recommended order, which accepts APS’ proposed amendment in all respects except for the accounting treatment for payments received for new or upgraded service. APS’ proposal would treat such payments as non-refundable other electric revenues, while the ACC Staff proposes these payments should be treated as contributions in aid of construction (“CIAC”). CIAC treatment would result in a positive cash flow that would offset capital expenditures, but without any revenue impact.

     APS proposed to “grandfather” applicants that have executed line extension agreements prior to the effective date of its amended line extension schedule. The impact of the amended line extension schedule on APS’ financial condition cannot be accurately predicted at this time and depends on the accounting treatment authorized for the proceeds, the extent of any “grandfathering” required by the ACC, and the level and mix of new APS customers. APS intends to file exceptions to the ACC staff’s recommended order by mid-November, and the final outcome of this matter is pending until further ACC action, which is expected to occur in late November.

     APS Financing Authorization

     On December 15, 2006, APS filed a financing application with the ACC requesting an increase in APS’ (a) current short-term debt authorization (7% of APS’ capitalization) to (i) 7% of APS’ capitalization plus (ii) $500 million in order to meet its growing cash requirements, including cash requirements for natural gas and power purchases and (b) current long-term debt authorization (approximately $3.2 billion) to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. On October 30, 2007, the ACC issued a financing order in which it approved APS’ requests, subject to specified parameters and procedures.

     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 APSES (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’ authority to make sales at market-based rates 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.

     On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on October 12, 2007.

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

     On July 10, 2007, APS submitted a revised Open Access Transmission Tariff (OATT) filing with the FERC to move from a fixed rate to a formula rate in order to more accurately reflect the costs that APS incurs in providing transmission and ancillary services. The requested formula rate would result in an estimated $37 million increase in annual transmission revenues, effective October 1, 2007. The proposed formula rate would be updated each year on June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 reports, and projected capital expenditures. Approximately $30 million of the requested increase represents charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”) and, as a result, would not affect APS’ earnings until such time as APS retail rates are adjusted to include these charges. As part of a retail rate case settlement order in 2005, the ACC approved the use of a mechanism by which changes in Retail Transmission Charges can be reflected in APS’ retail rates. APS is currently addressing the appropriate procedure to implement the retail transmission rate change.

     On September 21, 2007, the FERC issued an order on these proposed revisions to APS’ transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge procedures, with an initial settlement conference held on October 11, 2007. The proposed rates

become effective March 1, 2008, subject to refund based upon the outcome of the settlement procedures and a hearing, if necessary, that has been scheduled in abeyance to allow time for such settlement procedures.

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a nonqualified supplemental excess benefit retirement plan (“SEBRP”), 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.

     Pursuant to the ACC’s June 28, 2007 order in APS’ general rate case, APS was not allowed to recover the pension costs associated with the SEBRP through the ratemaking process. Therefore, amounts that were previously recorded as a regulatory asset, approximately $45 million ($27 million, net of income taxes), were charged to OCI at June 30, 2007 (see Notes 11 and S-2). This treatment is consistent with the accounting for this type of plan by our unregulated entities.

     The following table provides details of the plans’ benefit costs for the three and nine months ended September 30, 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):

     Our pension contribution of $52 million has been made for the year. The contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $18 million, of which

approximately $15 million was contributed through September 30, 2007. 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 and nine months ended September 30, 2007 and 2006 and at September 30, 2007 and December 31, 2006 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 our 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. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next 12 months, we expect 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 FIN 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 unrecognized tax benefits 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. APS’ share included in the total was approximately $7 million. Partial resolution of previously unrecognized tax benefits during the quarter ended September 30, 2007 resulted in a $10 million benefit.

     As of January 1, 2007, the tax year ended December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ended 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 September 30, 2007, APS would have been required to assume approximately $208 million of debt and pay the equity participants approximately $174 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 September 30, 2007, we hedged exposures to the price variability of the power and gas commodities for a maximum of 40 months. 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 and nine months ended September 30, 2007 and 2006 are comprised of the following (dollars in thousands):

     During the next twelve months ending September 30, 2008, we estimate that a net gain of $34 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, regulated electricity and marketing and trading.

     The following tables summarize our assets and liabilities from risk management and trading activities at September 30, 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 results of operations, 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 $58 million at September 30, 2007 and $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 $4 million at September 30, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Condensed Consolidated Balance Sheets. No collateral was provided to us by counterparties at September 30, 2007 and $54 million was provided to us 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. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on 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 for the three and nine months ended September 30, 2007 and 2006 are as follows (dollars in thousands):

     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 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 September 30, 2007, APS had a regulatory liability of approximately $8 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

     NRC Matters

     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. 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 (“Column 4”), which has resulted in an enhanced NRC inspection regimen. Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS management has been conducting site-wide assessments of equipment and operations. Preliminary work in support of the NRC’s enhanced inspection regimen took place throughout summer 2007. On June 21, 2007, the NRC issued an initial confirmatory action letter confirming APS’ commitments regarding specific actions APS will take to improve Palo Verde’s performance. From October 1, 2007, through November 2, 2007, a team of NRC inspectors performed on-site in-depth inspections of Palo Verde equipment and operations. APS expects to be informed of the NRC’s inspection findings in late December 2007 or January 2008. APS continues to cooperate fully with the NRC throughout this process. Following receipt of the inspection findings and APS’ revisions to improvement plans to address the inspection findings, the NRC will issue a revised confirmatory action letter in the first quarter of 2008.

     On November 9, 2006, APS notified the NRC that a senior reactor operator at Palo Verde had attempted to conceal a mistaken entry the operator had made in a Palo Verde operations verification log. The senior reactor operator resigned shortly thereafter. By letter dated July 12, 2007, the NRC notified APS that, based upon the results of its investigation of the matter, the NRC was considering an escalated enforcement action against Palo Verde due to the willfulness of the senior reactor operator’s actions. The NRC noted in its letter that the safety significance of the matter was very low. The NRC also offered to resolve the potential escalated enforcement action through the agency’s alternative dispute resolution program, which APS elected to do. As a result of the alternative dispute resolution proceeding between the NRC and APS, a settlement was reached under which APS agreed to take a number of corrective actions, including specified training for certain Palo Verde personnel and follow up reporting to the NRC. As a result of APS’ commitments, the NRC agreed not to pursue any further enforcement action in connection with this matter. The agreement between APS and the NRC became effective upon the NRC’s issuance of a confirmatory order, dated October 19, 2007, memorializing the agreement.

     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, or cash flows.

     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 December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari. This petition was denied on June 18, 2007. 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 Ninth Circuit has extended the stay until November 16, 2007. The outcome of the further proceedings cannot be predicted at this time.

     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. The Court stayed the date for petitions for rehearing of this opinion until November 16, 2007 to allow for any possible settlement negotiations. 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 sought appellate review to reallocate the cost responsibility associated with the changed contractual obligations in a way that would have increased APS’ annual capacity cost 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 was no basis for modifying the settlement rates during the remaining term of the settlement. By order of the D.C. Court of Appeals issued on October 10, 2007, this case was dismissed as a result of a motion for voluntary dismissal filed by the party that originally sought review in this case.

     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. 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 that may be required.

     Salt River Project has 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 asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million.  APS disputes that it is required to pay these amounts.  No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact 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 $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 $21.1 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 and nine months ended September 30, 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 APSES 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 our 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 September 30, 2007 are as follows (dollars in millions):

     At September 30, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in 2009. 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 September 30, 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 $83 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 September 30, 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 and nine months ended September 30, 2007 and 2006:

     Dilutive stock options and performance shares increased average common shares outstanding by approximately 505,000 shares and 482,000 shares for the three months ended September 30, 2007 and September 30, 2006, respectively, and by approximately 567,000 shares and 446,000 shares for the nine months ended September 30, 2007 and 2006, respectively.

     Options to purchase 610,250 shares of common stock for the three-month period and 115,200 shares for the nine-month period ended September 30, 2007 were outstanding but were excluded from the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were excluded from the computation of diluted earnings per share for that same reason were 447,650 shares for the three-month period ended September 30, 2006 and 732,534 shares for the nine-month period ended September 30, 2006.

     SunCor (real estate segment) – In 2006 and 2007, SunCor sold commercial properties that were required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. As a result of those sales, we recorded in 2007 a gain from discontinued operations of approximately $8 million ($13 million pretax). Assets held for sale at September 30, 2007 relate to commercial properties in the amount of $6 million. 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 and nine months ended September 30, 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 September 30, 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 September 30, 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 and preparing for the new disclosure requirements.

     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 FIN 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.

     In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1).  Under FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement.  This new guidance is effective for us on January 1, 2008, with early application permitted.  We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact on our results of operations or cash flows.

(unaudited)

(dollars in thousands)