Pinnacle West Capital - 10-Q quarterly report FY

 

(Mark One)

     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.

PINNACLE WEST CAPITAL CORPORATION              Yes þ       No o
ARIZONA PUBLIC SERVICE COMPANY                     Yes þ       No o

     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).

PINNACLE WEST CAPITAL CORPORATION               Yes o       No þ
ARIZONA PUBLIC SERVICE COMPANY                      Yes o       No þ

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

          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

APB – Accounting Principles Board

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

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

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

EITF – FASB’s Emerging Issues Task Force

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

EPA – United States Environmental Protection Agency

ERMC – Energy Risk Management Committee

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

FIP – Federal Implementation Plan

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

IRS – United States Internal Revenue Service

kWh – kilowatt-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

NPC – Nevada Power Company

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned 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

PRP – potentially responsible party

PSA – power supply adjustor

PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3

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, a 570-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles north of Las Vegas, Nevada

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

SunCor – SunCor Development Company, a subsidiary of the Company

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

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

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

2005 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2005

VIE – variable interest entity

(unaudited)

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

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)

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

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

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

     Our unaudited condensed consolidated financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. We suggest that these condensed consolidated financial statements and notes to condensed consolidated financial statements be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2005 Form 10-K.

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

     In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk. See “Equity Infusions” in Note 5 for more information.

     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).

     On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.

     On August 3, 2006, APS issued $400 million of debt as follows: $250 million of its 6.25% Notes due 2016 and $150 million of its 6.875% Notes due 2036. A portion of the proceeds will be used to pay at

maturity approximately $84 million of APS’ 6.75% Senior Notes due November 15, 2006, to fund its construction program and for other general corporate purposes. A portion of the proceeds may also be used to pay any liability determined to be payable as a result of the review by the Internal Revenue Service of a tax refund the Company received in 2002.

     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions) as of June 30, 2006:

     On January 31, 2006, APS filed with the ACC updated financial schedules, testimony and other data in the general rate case that APS originally filed on November 4, 2005. As requested by the ACC staff, the updated information uses the twelve months ended September 30, 2005 as the test period instead of the test year ended December 31, 2004 used in APS’ original filing. As a result of the updated filing, APS is requesting a 21.3%, or $453.9 million, increase in its annual retail electricity revenues effective no later than December 31, 2006. The original filing requested a 19.9%, or $409.1 million, retail rate increase.

     The updated requested rate increase is designed to recover the following (dollars in millions):

     The request is based on (a) a rate base of $4.4 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.031904 per kilowatt-hour based on estimated 2006

prices; and (c) a proposed capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity). The requested increase in annual retail electricity revenues from the original filing is based solely on increased fuel and purchased power costs, slightly offset by other items (see the above chart). If the ACC approves the requested base rate increase for fuel and purchased power costs (see clause (b) of this paragraph), subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates.

     The updated request does not include the PSA annual adjustor rate increase of approximately 5% that took effect February 1, 2006, the PSA surcharge increase of approximately 0.7% that took effect May 1, 2006, or APS’ pending application for a 1.9% PSA surcharge rate increase. See “Power Supply Adjustor” below. The interim rate increase described immediately below would, if it becomes permanent, accelerate the recovery of a portion of the fuel and purchased power component of the general rate case request.

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

As noted above, the interim PSA adjustor would, if it becomes permanent, accelerate the recovery of a portion of the fuel and purchased power component of APS’ general rate case and is not an additional increase.

     PSA Provisions

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

     2006 PSA Annual Adjustor The effective date of the PSA’s annual adjustor is February 1, 2006 and the adjustor rate was set at the maximum $0.004 per kilowatt-hour effective February 1, 2006.

The change in the adjustor rate represents a retail rate increase of approximately 5% designed to recover $110 million of deferred fuel and purchased power costs over the twelve-month period beginning February 1, 2006.

     Surcharge for Certain 2005 PSA Deferrals On April 12, 2006, the ACC approved APS’ request to recover $15 million of 2005 PSA deferrals over a twelve-month period beginning May 2, 2006, representing a temporary rate increase of approximately 0.7%. Approximately $45 million of 2005 PSA deferrals remain subject to a pending application (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below); the balance of the 2005 PSA deferrals is being recovered under the 2006 PSA annual adjustor described in the preceding paragraph.

     PSA Deferrals Related to Unplanned Palo Verde Outages On February 2, 2006, APS filed with the ACC an application to recover approximately $45 million over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages.

     As noted under “Interim Rate Increase” above, the ACC has directed the ACC staff to conduct a “prudence audit” on unplanned 2006 Palo Verde outage costs. PSA deferrals related to these 2006 outages are estimated to be about $70 million.

     Proposed Modifications to PSA (Requested In General Rate Case)

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

     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consist of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006 (see Note 17). Pinnacle West has made these equity infusions into APS.

     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.

     FERC Order

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

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

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

     The Pinnacle West Companies filed a rehearing request of the FERC Order on May 17, 2006 and requested a technical conference with the FERC staff to discuss the order. The rehearing request

is still pending. The FERC granted the request to hold a technical conference so that FERC staff and the Pinnacle West Companies may discuss how to implement the cost-based mitigation requirements of the FERC Order. The technical conference was held on July 10, 2006, and the Pinnacle West Companies submitted a supplemental compliance filing on July 31, 2006. Based upon an analysis of the FERC Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the FERC Order will have a material adverse effect on its financial position, results of operations or cash flows.

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

     The following table provides details of the plans’ benefit costs for the three and six months ended June 30, 2006 and 2005. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or capitalized as overhead construction (dollars in millions):

     The contribution to our pension plan in 2006 is estimated to be approximately $50 million, $29 million of which has been contributed through June 30, 2006. The contribution to our other postretirement benefit plan in 2006 is estimated to be approximately $29 million. APS’ share is approximately 97% of both plans.

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

     Financial data for the three and six months ended June 30, 2006 and 2005 and at June 30, 2006 and December 31, 2005 by business segment is provided as follows (dollars in millions):

     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and our subsidiaries.

     The 2002 Long-Term Incentive Plan (“2002 Plan”) allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. We have reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The terms of the options cannot be longer than 10 years and the options cannot be repriced.

     Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year period based upon Pinnacle West’s earnings per share growth rate during that three-year period compared to the earnings per share growth rate of all relevant companies in a specified utilities index. The number of shares of common stock a recipient is entitled to receive is determined by Pinnacle West’s relative percentile ranking during the three-year period.

     The 1994 Long-Term Incentive Plan (“1994 Plan”) includes outstanding options but no new options may be granted under the plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.

     In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25, “Accounting for Stock Issued to Employees.”

     Effective January 1, 2006, we prospectively adopted SFAS No. 123(R), “Share-Based Payment.” Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements.

     The compensation cost that has been charged against income for share-based compensation plans was $1.3 million and $4.1 million for the three and six months ended June 30, 2006, respectively compared to $1.6 million and $2.2 million for the three and six months ended June 30, 2005, respectively. The total income tax benefit recognized in the condensed consolidated income statement for share-based compensation arrangements was $0.5 million and $1.5 million for the three and six months ended June 30, 2006, respectively, compared to $0.6 million and $0.9 million for the three and six months ended June 30, 2005, respectively.

     The following table is a summary of option activity under our equity incentive plans as of June 30, 2006 and changes during the six months ending on that date:

     There were no options granted during the six months ended June 30, 2006 and 2005. The intrinsic value of options exercised during the three months ended June 30, 2006 and 2005 was $0.2 million and $0.6 million, respectively. The intrinsic value of options exercised during the six months ended June 30, 2006 and 2005 was $0.2 million and $1.1 million, respectively.

     The following table is a summary of the status of stock compensation awards, other than options, as of June 30, 2006 and changes during the six months ending on that date:

     As of June 30, 2006, there was $8.6 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plan. That cost is expected to be recognized over a weighted-average period of 1.8 years. No shares vested during the three months ended June 30, 2006 and 2005. The total fair value of shares vested during the six months ended June 30, 2006 and 2005 was $0.5 million and $2.9 million, respectively.

     Cash received from options exercised under our share-based payment arrangements was $0.9 million and $2.1 million for the three months ended June 30, 2006 and 2005, respectively. Cash received from options exercised under our share-based payment arrangements was $0.9 million and $6.1 million for the six months ended June 30, 2006 and 2005, respectively. The actual tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was immaterial for the three and six months ended June 30, 2006 and 2005.

     Pinnacle West has a current policy of issuing new shares to satisfy share requirements for stock compensation plans and does not expect to repurchase any shares during 2006.

     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 June 30, 2006, APS would have been required to assume approximately $228 million of debt and pay the equity participants approximately $182 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 well as interest rate risk associated with long-term debt. As of June 30, 2006, we hedged exposures to the price variability of the power and gas commodities for a maximum of 3.25 years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

     The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three and six months ended June 30, 2006 and 2005 are comprised of the following (dollars in thousands):

     During the next twelve months ending June 30, 2007, we estimate that a net gain of $47 million before income taxes will be reclassified from accumulated OCI 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, consistent with our business segments.

     The following table summarizes our assets and liabilities from risk management and trading activities at June 30, 2006 and December 31, 2005 (dollars in thousands):

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $13 million at June 30, 2006 and a liability of $123 million at December 31, 2005 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 $13 million at June 30, 2006 and $6 million at December 31, 2005, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $67 million at June 30, 2006 and $216 million at December 31, 2005, 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 (loss) for the three and six months ended June 30, 2006 and 2005 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 has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims.

     APS currently estimates it will incur $147 million (in 2005 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 June 30, 2006, APS had a regulatory asset of $2 million that represents amounts spent for on-site interim spent fuel storage net of amounts recovered in rates per the ACC rate order that was effective April 1, 2005.

     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 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. Petitions for rehearing on this order and due 90 days from the date of issuance. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.

     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On August 4, 2006, the State of California filed a motion to stay the issuance of the mandate (scheduled to be issued on August 7, 2006), until the end of the period for seeking rehearing in the California refund proceeding before the Ninth Circuit, discussed above. The outcome of the further proceedings cannot be predicted at this time.

     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to

the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or cash flows.

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

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

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

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

     Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on June 30, 2005, which proposed new rates, terms and conditions and services to become effective on January 1, 2006. These rates are subject to refund pending the outcome of a hearing. The cost impact of this rate case will not have a material adverse effect on APS’ financial position, results of operations, cash flows or liquidity.

     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, however, in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. APS believes Peabody's claims are without merit and intends to contest those claims. Because the litigation is in preliminary stages, however, APS cannot currently predict the outcome of this matter.

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

     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2004 and again in 2005, the current income tax liability was increased, with a corresponding decrease to plant-related deferred tax liability, to reflect the expected outcome of this audit. 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 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, cash flows or liquidity.

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $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 $17.8 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 six months ended June 30, 2006 and 2005 (dollars in thousands):

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of APS Energy Services. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by APS Energy Services would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of its subsidiary. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. At June 30, 2006, we had guarantees totaling $21 million and surety bonds totaling $24 million with a term of approximately one year for APS Energy Services.

     At June 30, 2006, Pinnacle West had approximately $4 million of letters of credit related to workers’ compensation expiring in 2007. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At June 30, 2006, 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 $93 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 June 30, 2006 APS had approximately $5 million of letters of credit related to counterparty collateral requirements

expiring in 2006. 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. 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 six months ended June 30, 2006 and 2005:

     Dilutive stock options and performance shares increased average common shares outstanding by approximately 419,000 shares and 107,000 shares for the three months ended June 30, 2006 and 2005, respectively, and by approximately 394,000 shares and 100,000 shares for the six months ended June 30, 2006 and 2005, respectively.

     Options to purchase 881,628 shares for the three-month period ended June 30, 2006 and 808,876 shares for the six-month period ended June 30, 2006 were outstanding but were not included in the computation of earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share for that same reason were 491,984 shares for the three-month period ended June 30, 2005 and 503,859 shares for the six-month period ended June 30, 2005.

     Silverhawk (marketing and trading segment) – In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on January 10, 2006. As a result of this sale, we recorded a loss from discontinued operations of approximately $56 million ($91 million pretax) in the second quarter of 2005. The marketing and trading segment discontinued operations amounts in the chart below also include the revenues and expenses related to the operations of Silverhawk.

     SunCor (real estate segment) – In 2005 and 2006, SunCor sold commercial 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.

     The following table provides revenue and income (loss) before income taxes and after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2006 and 2005 (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 debt 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, 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 June 30, 2006 and December 31, 2005 (dollars in millions):