FORM 10-Q
For the quarterly period ended September 30, 2004
OR
For the transition period from to
Commission file number 1-8962
PINNACLE WEST CAPITAL CORPORATION
Registrant’s telephone number, including area code: (602) 250-1000
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Number of shares of common stock, no par value,outstanding as of November 4, 2004: 91,572,219
Glossary
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PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements.
PINNACLE WEST CAPITAL CORPORATIONCONDENSED CONSOLIDATED STATEMENTS OF INCOME(unaudited)(in thousands, except per share amounts)
See Notes to Condensed Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATIONCONDENSED CONSOLIDATED BALANCE SHEETS(unaudited)(dollars in thousands)ASSETS
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PINNACLE WEST CAPITAL CORPORATIONCONDENSED CONSOLIDATED BALANCE SHEETS(unaudited)(dollars in thousands)LIABILITIES AND EQUITY
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PINNACLE WEST CAPITAL CORPORATIONCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(unaudited)(dollars in thousands)
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PINNACLE WEST CAPITAL CORPORATIONNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
1. The condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.
2. Our unaudited condensed consolidated financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature. We suggest that these condensed consolidated financial statements and notes to condensed consolidated financial statements be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2003 Form 10-K.
3. Weather conditions cause significant seasonal fluctuations in our revenues. In addition, trading and wholesale marketing activities can have significant impacts on our results for interim periods. For these reasons as well as others, results for interim periods do not necessarily represent results to be expected for the year.
4. Changes in Liquidity
On February 2, 2004, we used proceeds from the $165 million Floating Rate Notes issued on November 12, 2003 and short-term borrowings to pay down the maturing $215 million 4.5% Senior Notes due 2004.
On February 15, 2004, $125 million of APS’ 5.875% Notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of APS First Mortgage Bonds, 6.625% Series due 2004, were redeemed at maturity. APS used cash from operations and short-term debt to redeem the maturing debt.
On March 31, 2004, Navajo County, Arizona Pollution Control Corporation issued $166 million of variable interest rate pollution control bonds, 2004 Series A-E, due 2034 to refinance $166 million of outstanding pollution control bonds. The 2004 Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Navajo County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets.
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Also on March 31, 2004, Coconino County, Arizona Pollution Control Corporation issued $13 million of variable interest rate pollution control bonds, 2004 Series A, due 2034 to refinance $13 million of outstanding pollution control bonds. These bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Coconino County, Arizona Pollution Control Corporation. The 2004 Series A bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets.
In May 2004, APS renewed its $250 million revolving credit facility, while increasing its size to $325 million and extending its term to three years. The revolver provides liquidity support for APS’ $250 million commercial paper program, as well as an additional $75 million for other liquidity needs and miscellaneous letters of credit.
On June 29, 2004, APS issued $300 million of 5.80% senior unsecured notes due June 30, 2014. The proceeds from the sale of the notes will be used to redeem all or a portion of $100 million in aggregate principal amount of APS’ 6.25% Notes due January 15, 2005 and/or all or a portion of $300 million in aggregate principal amount of APS’ 7.625% Notes due August 1, 2005.
At September 30, 2004, APS had $566 million of pollution control bonds under which interest rates are reset on a daily, weekly or annual basis. The holders of $387 million of these bonds have the right to cause APS to purchase their bonds on the applicable reset date if the bonds are not remarketed. Of these bonds, $164 million of such bonds are classified as current maturities of long-term debt. The remaining $223 million of bonds are classified as long-term debt because APS has the intent and ability, as demonstrated by credit agreements in place that extend for more than one year, to refinance any bonds that APS is required to purchase.
In October 2004, we replaced two separate revolving credit facilities (with collective borrowing capacity of $275 million) with a $300 million revolving credit facility that terminates in October 2007. The revolver provides liquidity support for Pinnacle West’s $250 million commercial paper program, as well as up to $100 million of the facility that can be used for letters of credit.
The following is a list of principal payments due on our total long-term debt and capitalized lease requirements as of September 30, 2004:
In May 2004, SNWA paid Pinnacle West Energy approximately $91 million for a 25% interest in the 570 MW Silverhawk combined cycle plant.
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5. Regulatory Matters
Electric Industry Restructuring
State
APS General Rate Case; 2004 Settlement Agreement
On June 27, 2003, APS filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, intended to become effective July 1, 2004. In this rate case, APS updated its cost of service and rate design.
The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the Rules.
On August 18, 2004, a substantial majority of the parties to the rate case, including APS, the ACC staff, the Residential Utility Consumer Office, other customer groups, and merchant power plant intervenors entered into an agreement that proposes terms under which the rate case would be settled (the “2004 Settlement Agreement”). Key financial components of the 2004 Settlement Agreement, which is subject to ACC approval, are as follows:
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Major changes in revenue requirements under the 2004 Settlement Agreement are as follows (dollars in millions):
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Hearings on the 2004 Settlement Agreement are scheduled to begin on November 8, 2004.
ACC Financing Order
On May 12, 2003, APS issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to us to fund the repayment of a portion of the debt we incurred to finance the construction of the PWEC Dedicated Assets.
The ACC granted the Financing Order subject to various conditions. One of these conditions is that APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its common equity ratio below that threshold, unless otherwise waived by the ACC.
In addition, the Financing Order required the ACC staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003, APS submitted its report on these matters to the ACC staff. As part of the 2004 Settlement Agreement, this inquiry would be concluded with no further action by the ACC.
Retail Electric Competition Rules
The Rules approved by the ACC include the following major provisions:
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Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement.
On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affected the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of APS’ property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute. A request for the Arizona Supreme Court to review the Court of Appeals decision is still pending.
Track A Order
On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things:
On November 15, 2002, APS filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals.Arizona Public Service Company vs. Arizona Corporation Commission, CV 2002-0222 32. Arizona Public Service Company vs. Arizona Corporation Commission, 1CA CC 02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for resolving certain issues raised by APS in its appeals of the Track A
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Order. The major provisions of the principles include, among other things, the following:
On August 27, 2003, APS, Pinnacle West and Pinnacle West Energy filed a lawsuit asserting damage claims relating to the Track A Order. Arizona Public Service Company et al. v. The State of Arizona ex rel., Superior Court of the State of Arizona, County of Maricopa, No. CV2003-016372.
Upon the ACC’s issuance of a final, non-appealable order approving the 2004 Settlement Agreement, APS, Pinnacle West, and Pinnacle West Energy will dismiss the litigation described under this “Track A” heading.
Track B Order
On March 14, 2003, the ACC issued the Track B Order, which required APS to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003, APS was required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS’ total retail energy requirements.
APS issued requests for proposals in March 2003 and, by May 6, 2003, APS entered into contracts to meet all or a portion of its requirements for the years 2003 through 2006 as follows:
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Effective upon final ACC approval of the 2004 Settlement Agreement and the closing of the purchase of PPL Sundance, the Track B contracts with Pinnacle West Energy and PPL Energy Plus, LLC will be cancelled.
Provider of Last Resort Obligation
Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is, under the Rules, the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supplemental power in the wholesale spot market. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS’ current retail rates. There can be no assurance that APS would be able to fully recover the costs of this power. The proposed settlement of APS’ general rate case, discussed above, would, among other things, allow APS to recover purchased power costs.
1999 Settlement Agreement
The following are the major provisions of a settlement agreement entered into in 1999, as approved by the ACC:
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General
The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.
Request for Proposals and Asset Purchase Agreement
In early December 2003, APS issued a request for proposals (“RFP”) for long-term power supply resources. On June 1, 2004, APS and PPL Sundance, a wholly-owned subsidiary of PPL Corporation, entered into an asset purchase agreement by which APS agreed to purchase the 450 MW Sundance Generating Station. The Sundance Generating Station, which began commercial operation in July 2002, would provide peaking generation support for APS’ system and reduce APS’ growing needs for new generation resources.
The purchase price for the Sundance Generating Station is $189.5 million. Subject to the receipt of approvals from various regulatory agencies, including the ACC, the FERC, the Department of Justice and the Federal Trade Commission, the transaction is expected to close in the first quarter of 2005. Either party may terminate the agreement if ACC approval is not obtained by December 31, 2004 or the transaction does not close by March 31, 2005.
On June 1, 2004, APS and PPL Sundance filed a joint application with the ACC requesting approval of the transaction on or before December 31, 2004. APS also requested, among other things, that the Sundance Generating Station be included in APS’ rates in APS’ next rate case and that certain operating and capital costs be deferred until that time. APS is not requesting that the Sundance Generating Station be reflected in its current general rate case before the ACC. A hearing on the application was held in early October, and we expect a decision by the end of the year.
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APS does not expect to enter into any additional transactions as a result of the RFP.
Federal
In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.
On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule. On April 28, 2003, the FERC staff issued an additional white paper on the proposed Standard Market Design. The white paper discusses several policy changes to the proposed Standard Market Design, including a greater emphasis on flexibility for regional needs. We cannot currently predict what, if any, impact there may be to the Company if the FERC adopts the proposed rule or any modifications proposed in the comments.
The FERC has been in the process of auditing numerous utilities regarding compliance with its regulations. Such an audit of APS and its affiliates is currently in process. Certain instances of noncompliance with FERC regulations related to the administration of APS’ transmission tariff have been identified. APS is presently discussing these issues with the FERC staff and expects a public report to be issued later this year. APS currently expects, but cannot provide any assurance, that the resolution of these matters will not have a material adverse effect on its financial position, results of operations or liquidity.
6. Retirement Plans and Other Benefits
Pinnacle West sponsors a qualified defined benefit pension plan, a nonqualified supplemental excess benefit retirement plan, and other postretirement benefits for the employees of Pinnacle West and our subsidiaries.
On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug cost. The FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to address the accounting for the effects of the Act. During the third quarter of 2004, We retroactively adopted the provisions of FSP 106-2, resulting in the remeasurement of our postretirement benefit plans’ accumulated postretirement benefit obligation (APBO) as of December 31, 2003. The impact of the subsidy is a decrease in the accumulated projected benefit obligation of approximately $65 million and a decrease of approximately $11 million in the net periodic postretirement benefit cost for 2004. The annual after-tax reduction to expense is approximately $5 million,
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excluding amounts capitalized as construction overhead or billed to electric plant participants.
The following table provides details of the plans’ benefit costs for the three and nine months ended September 30, 2004 and 2003. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or amounts capitalized as overhead construction (dollars in millions):
Contributions
The Pension Stability Act was signed into law on April 10, 2004. Under this new legislation, our required pension contribution in 2004 is $35 million, which we contributed in the third quarter. We have contributed approximately $14 million to our other postretirement benefits plan in 2004 through September.
7. Business Segments
We have three principal business segments (determined by services and the regulatory environment):
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The amounts in our other segment include activities principally related to APS Energy Services’ non-commodity services and to the parent company. Financial data for our business segments follows (dollars in millions):
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8. Accounting Matters
See the following Notes for information about new accounting standards and other accounting matters:
9. Variable Interest Entities
In 2003, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities,” as it applies to special-purpose entities. FIN No. 46R requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities.
In 1986, APS entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs.
APS is exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2004, APS would have been required to assume approximately $250 million of debt and pay the equity participants approximately $195 million.
In the first quarter of 2004, we adopted FIN No. 46R for all other contractual arrangements. SunCor has certain land development arrangements that are
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required to be consolidated under FIN No. 46R. The assets and noncontrolling interests reflected in our Condensed Consolidated Balance Sheets related to these arrangements were approximately $17 million at September 30, 2004.
10. Derivative Instruments and Energy Trading Activities
We are exposed to the impact of market fluctuations in interest rates and in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge our exposure to changes in interest rates and to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of September 30, 2004 we hedge exposures to the price variability of these commodities for a maximum of eight 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.
Cash Flow Hedges
The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2004 and 2003 were comprised of the following (dollars in thousands):
During the twelve months ending September 30, 2005, we estimate that a net gain of $56 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect on earnings of market price changes for the related hedged transactions.
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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 September 30, 2004 and December 31, 2003 (dollars in thousands):
Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties
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was $2 million at September 30, 2004 and $1 million at December 31, 2003, and is included in investments and other assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $23 million at September 30, 2004 and $12 million at December 31, 2003, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.
Credit Risk
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represented approximately 30% of our $396 million of risk management and trading assets as of September 30, 2004. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
Fair Value Hedges
On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% senior note. The purpose of these hedges is to protect against significant fluctuations in the fair value of our debt. Our interest rate swaps are considered to be fully effective with any resulting gains or losses on the derivative offset by a similar loss or gain amount on the underlying fair value of debt. The fair value of the interest rate swaps was $1.4 million at September 30, 2004 and is included in other assets with the corresponding offset in long-term debt less current maturities on the Condensed Consolidated Balance Sheets.
11. Comprehensive Income
Components of comprehensive income for the three and nine months ended September 30, 2004 and 2003, are as follows (dollars in thousands):
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12. Commitments and Contingencies
Palo Verde Nuclear Generating Station
Spent Fuel and Waste Disposal
Nuclear power plant owners are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. Arizona Public Service Company v. United States of America, United States Court of Federal Claims, 03-2832C.
Based upon current estimates of the amount of spent fuel and the cost of storage, APS currently estimates it will incur $115 million over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of September 30, 2004, APS had spent $10 million and recorded a liability of $41
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million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. APS has recorded a corresponding regulatory asset of $51 million and is seeking recovery of these costs through future rates (see “APS General Rate Case; 2004 Settlement Agreement” in Note 5).
California Energy Market Issues and Refunds in the Pacific Northwest
In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. APS does not anticipate material changes in its exposure and still believes, subject to the finalization of the revised proxy prices, that it will be entitled to a net refund.
The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Court of Appeals (Ninth Circuit). Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.
On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.
PG&E filed for bankruptcy protection in 2001. In the fourth quarter of 2003, the CPUC and the Bankruptcy Court accepted PG&E’s plan of reorganization. The plan indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstanding, undisputed debts. PG&E emerged from bankruptcy protection on April 12, 2004 and settled all outstanding, undisputed debts with us.
California Energy Market Litigation On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. State of California v. British Columbia Power Exchange et al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale
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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. State of California ex rel. Bill Lockyer, Attorney General v. FERC, No. 02-73093. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The outcome of the further proceedings cannot be predicted at this time.
In addition, the State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II,Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including APS, attempting to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit.
APS was also named in a lawsuit regarding wholesale contracts in California, which, after moving to state court, has been removed to the federal court for a second time. James Millar, et al. v. Allegheny Energy Supply, et al., San Francisco Superior Court, Case No. 407867, U.S. District Court (Northern District) C-04-0519 SBA. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against APS and numerous other PX participants. Cal PX v. The State of California, Superior Court in and for the County of Sacramento, JCCP No. 4203. Various motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations or liquidity.
Natural Gas Supply
APS and Pinnacle West Energy purchase the majority of their natural gas requirements for their gas-fired plants under contracts with a number of natural gas suppliers. Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for transportation are subject to a rate moratorium through December 31, 2005.
On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement. In order for APS and Pinnacle West Energy to meet their natural gas supply and capacity requirements, we now expect that the combined increase in costs associated with the natural gas
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supply and the transportation capacity to result in an overall average increase of approximately $4 million per year in 2004 and 2005. APS and Pinnacle West Energy have sought appellate review of the FERC’s July 9 order and related issues on the grounds that the FERC decision to abrogate the full requirements contracts is arbitrary and capricious and is not supported by substantial evidence. Arizona Public Service Company and Pinnacle West Energy Corporation v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1209. This petition for review was consolidated with a petition filed by the ACC and other full requirements contract holders. Arizona Corporation Commission et al v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia Circuit, No. 03-1206. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements.
In addition, another party has also sought review of FERC’s July 9 order and is seeking to reallocate the costs associated with the changed contractual obligations in a way that would be less favorable to APS and Pinnacle West Energy than under FERC’s order. Should this party prevail on this point, APS and Pinnacle West Energy’s annual capacity cost could be increased by approximately $3 million per year, from September 2003 through December 2005, in addition to the $4 million discussed above.
Environmental Matters — Superfund
On September 3, 2003, the EPA advised APS and Pinnacle West that the EPA considers APS and Pinnacle West to be a “potentially responsible party” in the Motorola 52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this superfund site. Liability under Superfund is strict, joint and several. The Company and APS have agreed with the EPA to perform certain investigation activities of the APS facilities within OU3. Because the investigation has not yet been completed and the ultimate remediation requirements are not yet finalized, we cannot currently estimate the expenditures which may be required.
Asset Purchase Agreement
See “Request for Proposals and Asset Purchase Agreement” in Note 5 for a description of an asset purchase agreement between APS and PPL Sundance.
13. Nuclear Insurance
The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. The Price Anderson Act currently limits the combined public liability of nuclear reactor owners to $10.76 billion for claims that could arise from a single nuclear incident. The Palo Verde participants purchase the maximum available commercial insurance of $300 million. The balance of the $10.46 billion is provided by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for
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each nuclear incident is approximately $101 million, subject to an annual limit of $10 million per incident. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $9 million.
The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The estimated maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $16 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
14. Stock-Based Compensation
Pinnacle West offers stock-based compensation plans for officers and key employees of the Company and our subsidiaries. In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”
The following chart compares our net income, stock compensation expense and earnings per share for the three and nine months ended September 30, 2004 and 2003 to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through September 30, 2004 (dollars in thousands, except per share amounts):
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15. Other Income and Other Expense
The following table provides detail of other income and other expense for the three and nine months ended September 30, 2004 and 2003 (dollars in thousands):
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16. Guarantees
We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction program and long-term service agreement guarantees for new power plants. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products and enable El Dorado to support the activities of NAC. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s guarantees on behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at September 30, 2004 are as follows (dollars in millions):
At September 30, 2004, we had entered into approximately $39 million of letters of credit, which support various construction agreements. At September 30, 2004, the terms of these letters of credit expired in 2004 and 2005; however, during October 2004, the terms of these letters of credit were extended to 2005 and 2006. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required. Pinnacle West has approximately $3 million of letters of credit related to workers’ compensation expiring in 2004.
APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2004, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. See Note 4 for more information. In July 2004, $150 million of these letters of credit were renewed for a three-year term and expire in
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2007. The remainder expire in 2005. APS has also entered into approximately $102 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2005. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2005. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
We provide indemnifications relating to liabilities arising from or related to certain of our agreements. APS has provided indemnifications to the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnifications and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnifications is likely and therefore no related liability has been recorded.
17. Earnings Per Share
The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2004 and 2003:
The following table reconciles weighted-average common shares outstanding – basic to weighted-average common shares outstanding – diluted that are used in the earnings per share calculation in the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2004 and 2003 (in thousands):
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Options to purchase 985,469 shares for the three-month period ended September 30, 2004 and 1,088,378 shares for the nine-month period ended September 30, 2004 were outstanding but were not included in the computation of earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share for that same reason were 1,784,168 shares for the three-month period ended September 30, 2003 and 2,021,928 shares for the nine-month period ended September 30, 2003.
18. Discontinued Operations – SunCor and NAC
The following chart provides a summary of SunCor and NAC income from discontinued operations (after income taxes) for the three and nine months ended September 30, 2004 and the comparable prior periods (dollars in millions):
Real Estate Activities
The following table provides the revenue and income before taxes for properties owned by SunCor that were classified as discontinued operations for the three and nine months ended September 30, 2004 and the comparable prior periods (dollars in millions):
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NAC
In July 2004, we entered into an agreement to sell our investment in NAC Holding Inc. and NAC International Inc. (NAC). The transaction is expected to close later this year and result in an after-tax gain of up to approximately $6 million, which will be classified as discontinued operations. Due to the pending sale of NAC, all revenues and expenses for NAC have been reclassified to discontinued operations for the three months and nine months ended September 30, 2004 and 2003 on our Condensed Consolidated Statements of Income.
The following table provides the revenue and income before taxes for El Dorado’s investment in NAC that was classified as discontinued operations for the three and nine months ended September 30, 2004 and the comparable prior periods (dollars in millions):
Due to the pending sale of NAC, all amounts related to assets and liabilities of discontinued operations have been reclassified to assets and liabilities held for sale on the Condensed Consolidated Balance Sheets.
19. Sale of Phoenix Suns Partnership Interest
In June 2004, the Phoenix Suns Limited Partnership, in which El Dorado held a limited partnership interest, sold the partnership’s assets to a new investor group. The transaction resulted in a gain for El Dorado of approximately $35 million pretax ($21 million after income taxes), which is reflected in other income on the Condensed Consolidated Statements of Income. Additionally, $23 million in cash was received in July 2004 and $12 million will be received in 2007.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Introduction
We suggest this section be read along with the 2003 Form 10-K. Throughout this Item, we refer to specific “Notes” in the Notes to Condensed Consolidated Financial Statements in this report. These Notes add further details to the discussion. Operating statistics for the three and nine months ended September 30, 2004 and 2003 are available on our website (www.pinnaclewest.com).
Overview
We own all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States. APS’ marketing and trading division also sells, in the wholesale market, Pinnacle West Energy’s generation output that is not needed for APS’ Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with APS’ costs of serving retail customer energy requirements. APS has historically accounted for a substantial part of our revenues and earnings. Growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.
Pinnacle West Energy is our unregulated generation subsidiary. We formed Pinnacle West Energy in 1999 as a result of the ACC’s requirement that APS transfer all of its competitive assets and services to an affiliate or to a third party by the end of 2002. We planned to transfer APS’ generation assets to Pinnacle West Energy. Additionally, Pinnacle West Energy constructed several power plants to meet growing energy needs (1790 MW in Arizona and 570 MW in Nevada). In September 2002, the ACC issued the Track A Order, which prohibited APS from transferring its generation assets to Pinnacle West Energy. As a result of the Track A Order, we are seeking to transfer the plants built by Pinnacle West Energy in Arizona to APS to unite the Arizona generation under one common owner, as originally intended. The 2004 Settlement Agreement would provide for that transfer.
SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow, particularly during the years 2003 through 2005 due to accelerated asset sales activity. Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial, industrial and institutional retail customers in the western United States.
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We believe APS’ general rate case, including the proposed settlement, pending before the ACC is the key issue affecting our outlook. See Note 5 in Item 1 for a detailed discussion of this rate case and proposed settlement. Other factors affecting our past and future financial results include the June 2004 sale of El Dorado’s limited partnership interest in the Phoenix Suns; customer growth; purchased power and fuel costs; operations and maintenance expenses, including those relating to plant outages; weather variations; depreciation and amortization expenses, which are affected by net additions to existing utility plant and other property and changes in regulatory asset amortization; and the expected performance of our subsidiaries, SunCor and El Dorado.
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
The following table summarizes net income (loss) by segment for the three and nine months ended September 30, 2004 and the comparable prior-year periods (dollars in millions):
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Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. Our real estate segment gross margin refers to real estate revenues less real estate operations costs of SunCor. In addition, we have reclassified certain prior period amounts to conform to our current period presentation.
In accordance with the 1999 Settlement Agreement, we completed amortizing substantially all of our regulatory assets related to the 1999 Settlement Agreement as of June 30, 2004.
Our consolidated net income for the three months ended September 30, 2004 was $105 million compared with $110 million for the prior-year period. The $5 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:
Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):
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The increase in net costs (primarily interest expense, depreciation and operations and maintenance expense, net of gross margin contributions) related to new power plants placed in service in mid-2003 and mid-2004 by Pinnacle West Energy totaled approximately $6 million after income taxes in the three months ended September 30, 2004, compared with the prior-year period.
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Regulated Electricity Segment Revenues
Regulated electricity segment revenues were $3 million higher for the three months ended September 30, 2004 compared with the prior-year period, primarily as a result of:
Marketing and Trading Segment Revenues
Marketing and trading segment revenues were $46 million higher for the three months ended September 30, 2004 compared with the prior-year period, primarily as a result of:
Other Revenues
Other revenues were $7 million higher for the three months ended September 30, 2004 compared with the prior year period primarily due to higher non-commodity revenues at APS Energy Services.
Our consolidated net income for the nine months ended September 30, 2004 was $209 million compared with $191 million for the prior-year period. The $18 million increase in the period-to-period comparison reflects the following changes in earnings by segment:
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Additional details on the major factors that increased (decreased) income from continuing operations and net income are contained in the following table (dollars in millions).
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The increase in net costs (primarily interest expense, depreciation and operations and maintenance expense, net of gross margin contributions) related to new power plants placed in service in mid-2003 and mid-2004 by Pinnacle West Energy totaled approximately $21 million after income taxes in the nine months ended September 30, 2004, compared with the prior-year period.
Regulated electricity segment revenues were $60 million higher for the nine months ended September 30, 2004 compared with the prior-year period, primarily as a result of:
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Marketing and trading segment revenues were $31 million higher for the nine months ended September 30, 2004 compared with the prior-year period, primarily as a result of:
Real Estate Segment Revenues
Real estate segment revenues were $21 million higher for the nine months ended September 30, 2004 compared with the prior year period primarily as a result of increased home and commercial property sales partially offset by decreased land sales.
Other revenues were $16 million higher for the nine months ended September 30, 2004 compared with the prior year period primarily due to higher non-commodity revenues at APS Energy Services.
Liquidity and Capital Resources
Capital Expenditure Requirements
The following table summarizes the actual capital expenditures for the nine months ended September 30, 2004 and estimated capital expenditures for the next three years (dollars in millions):
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Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility cost. Examples of the types of projects included in the forecast include T&D lines and substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth. APS will begin major projects each year for the next several years, and expects to spend about $200 million on major transmission projects during the 2004 to 2006 time frame. These amounts are included in “APS-Delivery” in the table above. Completion of these projects will stretch from 2005 through at least 2008.
Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants and the replacement of Palo Verde steam generators. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $30 million annually for 2004 to 2006.
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Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall outage of 2003 at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. These generators will be installed in Unit 1 (scheduled completion in 2005) and Unit 3 (scheduled completion in 2007). Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million, which will be spent through 2008. In 2004 through 2006, approximately $90 million of the Unit 1 and Unit 3 costs are included in the generation capital expenditures table above and will be funded with internally-generated cash or external financings.
Contractual Obligations
Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2003 Form 10-K with the following exceptions that occurred in the nine months ended September 30, 2004:
Off-Balance Sheet Arrangements
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
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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, 2004, APS would have been required to assume approximately $250 million of debt and pay the equity participants approximately $195 million.
In the first quarter of 2004, we adopted FIN No. 46R for all other contractual arrangements. SunCor has certain land development arrangements that are required to be consolidated under FIN No. 46R. The assets and noncontrolling interests reflected in our Condensed Consolidated Balance Sheets related to these arrangements were approximately $17 million at September 30, 2004.
Guarantees and Letters of Credit
We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We generally provide indemnifications relating to liabilities arising from or related to certain of our agreements, except with limited exceptions depending on the particular agreement. We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to these obligations. See Note 16 for additional information regarding guarantees and letters of credit.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of November 5, 2004 are shown below and are considered to be “investment-grade” ratings. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).
APS no longer has any senior secured debt. See “APS” below for a discussion of the termination of APS’ mortgage and deed of trust.
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Debt Provisions
Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. The ratio of debt to total capitalization cannot exceed 65% for the Company and for APS. At September 30, 2004, the ratio was approximately 53% for Pinnacle West. At September 30, 2004, the ratio was approximately 53% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. The coverages were approximately 4 times for the Company and 4 times for APS at September 30, 2004. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants.
Neither Pinnacle West’s nor APS’ financing agreements contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under other agreements. Pinnacle West’s and APS’ credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in financial condition or financial prospects, except Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings equal to outstanding commercial paper amounts.
See Note 4 for further discussions.
Capital Needs and Resources by Company
Pinnacle West (Parent Company)
Our primary cash needs are for dividends to our shareholders; interest payments and optional and mandatory repayments of principal on our long-term debt. The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2004 and 2005 due to anticipated accelerated asset sales activity. As discussed in Note 5 under “ACC
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Financing Order,” APS must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce its common equity below that threshold. As defined in the Financing Order, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At September 30, 2004, APS’ common equity ratio was approximately 46%.
On February 2, 2004, we used proceeds from the $165 million Floating Rate Notes issued on November 12, 2003 and short term borrowings to pay down the maturing $215 million 4.5% Senior Notes due 2004.
Pinnacle West sponsors a pension plan that covers employees of Pinnacle West and our subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. APS and other subsidiaries fund their share of the pension contribution, of which APS represents approximately 89% of the total funding amounts described above. The assets in the plan are comprised of common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. The United States Pension Stability Act was signed into law on April 10, 2004. Under this new legislation, our required pension contribution in 2004 is $35 million, which we contributed in the third quarter. We have contributed approximately $14 million to our other postretirement benefits plan in 2004 through September.
APS
APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See Note 5 for a discussion of the $500 million financing arrangement between APS and Pinnacle West Energy approved by the ACC in 2003.
APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid for its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
On February 15, 2004, $125 million of APS’ 5.875% Notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of APS’ First Mortgage Bonds, 6.625% Series due 2004 were redeemed at maturity. APS used cash from operations and short-term debt to redeem the maturing debt.
On March 31, 2004, Navajo County, Arizona Pollution Control Corporation issued $166 million of variable interest rate pollution control bonds, 2004 Series A-E, due 2034. The bonds were issued to refinance $166 million of outstanding pollution control bonds.
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The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Navajo County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets.
Also on March 31, 2004, Coconino County, Arizona Pollution Control Corporation issued $13 million of variable interest rate pollution control bonds, 2004 Series A, due 2034. The bonds were issued to refinance $13 million of outstanding pollution control bonds. The Series A bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Coconino County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets.
On June 29, 2004 APS issued $300 million of 5.80% senior unsecured notes due June 30, 2014. The proceeds from the sale of the notes will be used to redeem all or a portion of $100 million in aggregate principal amount of APS’ 6.25% Notes due January 15, 2005 and/or all or a portion of $300 million in aggregate principal amount of APS’ 7.625% Notes due August 1, 2005.
APS has retired all first mortgage bonds issued by APS under its 1946 mortgage and deed of trust, including the first mortgage bonds securing APS senior notes. On April 30, 2004, APS terminated its mortgage and deed of trust and, as a result, is not able to issue any additional first mortgage bonds under that mortgage.
Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.
Pinnacle West Energy
Pinnacle West Energy’s capital requirements consist primarily of capital expenditures. In May 2004, SNWA paid Pinnacle West Energy approximately $91 million for a 25% interest in the 570 MW Silverhawk combined cycle plant. Pinnacle West Energy’s capital requirements are funded through capital infusions from Pinnacle West, which finances those infusions through debt and equity financings and internally-generated cash. See the capital expenditures table above for actual capital expenditures in the nine months ended September 30, 2004 and projected capital expenditures for the next three years.
See Note 5 for a discussion of the $500 million financing arrangement between APS and Pinnacle West Energy authorized by the ACC pursuant to the Financing Order.
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Other Subsidiaries
During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures in the nine months ended September 30, 2004 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings.
We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2004 and 2005 due to anticipated accelerated asset sales activity.
El Dorado funded its cash requirements during the past three years, primarily for NAC in 2002, with cash infused by the parent company and with cash from operations. El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments. For information on the pending sale of NAC, see Note 18.
APS Energy Services’ cash requirements during the past three years were funded with cash infusions from the parent company and with cash from operations.
Critical Accounting Policies
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting and the determination of the appropriate accounting for our pension and other postretirement benefits, derivatives and mark-to-market accounting. There have been no changes to our critical accounting policies since our 2003 Form 10-K except for the impact of recent accounting pronouncements as discussed in Note 8. See “Critical Accounting Policies” in Item 7 of the 2003 Form 10-K for further details about our critical accounting policies.
Business Outlook
2004 Earnings Outlook
We confirm our previous guidance that we expect our 2004 earnings will be approximately $2.50 per share, after taxes on a fully-diluted basis. This estimate assumes no contribution from a general rate case decision (see Note 5) and excludes the gain on El Dorado’s sale of its limited partnership interest in the Phoenix Suns (see Note 19). This earnings guidance, which supersedes all previous 2004 earnings guidance provided by the Company, is forward-looking information, and actual results may differ materially from our expectations. See “Forward-Looking Statements” below.
A number of factors affecting our business outlook are discussed below.
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APS General Rate Case
We believe APS’ general rate case, including the proposed settlement, pending before the ACC is the key issue affecting our outlook. See Note 5 for a detailed discussion of this rate case and proposed settlement.
Wholesale Power Market Conditions
The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with its costs of serving retail customer demand. We moved this division to APS in early 2003 for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting APS’ transfer of generating assets to Pinnacle West Energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities.
Factors Affecting Operating Revenues
General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity prices and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in western states that have opened to competitive supply.
Customer Growth Customer growth in APS’ service territory averaged about 3.4% a year for the three years 2001 through 2003; we currently expect customer growth to average about 3.8% per year from 2004 to 2006. We currently estimate that total retail electricity sales in kilowatt-hours will grow 4.6% on average, from 2004 through 2006, before the retail effects of weather variations. The customer and sales growth referred to in this paragraph applies to Native Load customers. Customer growth for the nine-month period ended September 30, 2004 compared with the prior year period was 3.7%.
Retail Rate Changes As part of the 1999 Settlement Agreement, APS agreed to a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. The final price reduction was implemented July 1, 2003. See “1999 Settlement Agreement” in Note 5 for further information. In addition, the Company has requested a 9.8% retail rate increase to be effective July 1, 2004. See “APS General Rate Case; 2004 Settlement Agreement” in Note 5 for further information.
Other Factors Affecting Future Financial Results
Purchased Power and Fuel Costs Purchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel,
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our power plant performance, prevailing market prices, new generating plants being placed in service and our hedging program for managing such costs. See “Natural Gas Supply” in Note 12 for more information on fuel costs.
Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.
Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to existing utility plant and other property, changes in regulatory asset amortization and our generation construction program. West Phoenix Unit 4 was placed in service in June 2001. Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in July 2002. West Phoenix Unit 5 was placed in service in July 2003 and Silverhawk was placed in service in May 2004. The regulatory assets to be recovered through June 30, 2004 under the 1999 Settlement Agreement were amortized as follows (dollars in millions):
Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.3% of assessed value for 2003 and 9.7% for 2002. We expect property taxes to increase primarily due to our generation construction program, as the plants phase-in to the property tax base over a five-year period, and our additions to existing facilities.
Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation. As noted above, we placed new power plants in commercial operation in 2001, 2002, 2003 and 2004. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs.
Retail Competition The regulatory developments and legal challenges to the Rules discussed in Note 5 have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
Subsidiaries In the case of SunCor, efforts to accelerate asset sales activities in 2003 were successful. A portion of these sales have been, and additional amounts may be required to be, reported as discontinued operations on our Condensed Consolidated Statements of Income. See Note 18 for further discussion. The annual earnings
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contribution from SunCor was $56 million after tax in 2003. We anticipate SunCor’s annual earnings contributions will average $30-$40 million over the years 2004 and 2005.
The annual earnings contribution from APS Energy Services is expected to be positive over the next several years due primarily to a number of retail electricity contracts in California. APS Energy Services had after tax earnings of $16 million in 2003.
We expect SunCor and APS Energy Services to have combined earnings of approximately $10 million per year after tax beyond 2005.
El Dorado’s historical results are not necessarily indicative of future performance. In June 2004, the Phoenix Suns Limited Partnership, in which El Dorado holds limited partnership interests, sold the partnership’s assets to a new investor group. The transaction resulted in a gain for El Dorado of approximately $21 million after income taxes (see Note 19 for further information). See Note 18 for information regarding El Dorado’s pending sale of NAC.
General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” below for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.
Risk Factors
Exhibit 99.1, which is hereby incorporated by reference, contains a discussion of risk factors affecting the Company.
Forward-Looking Statements
This document contains forward-looking statements based on current expectations, and we assume no obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “predict”, “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. In addition to the Risk Factors noted above (see Exhibit 99.1), these factors include, but are not limited to:
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Item 3. Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.
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Interest Rate and Equity Risk
Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt.
On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% senior note. These transactions qualify as fair value hedges under SFAS No. 133. See Note 10.
Commodity Price Risk
We are exposed to the impact of market fluctuations in interest rates and in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge our exposure to changes in interest rates and to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
The mark-to-market values of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:
The following tables show the pretax changes in mark-to-market of our regulated electricity and marketing and trading derivative positions for the nine months ended September 30, 2004 and 2003 (dollars in millions):
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The tables below show the fair value of maturities of our regulated electricity and trading derivative contracts (dollars in millions) at September 30, 2004 by maturities and by the type of valuation that is performed to calculate the fair values. See “Critical Accounting Policies — Mark-to-Market Accounting,” in Item 7 of our 2003 Form 10-K for more discussion on our valuation methods.
Regulated Electricity
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Marketing and Trading
The table below shows the impact that hypothetical price movements of 10% would have had on the market value of our risk management and trading assets and liabilities included on the Condensed Consolidated Balance Sheets at September 30, 2004 (dollars in millions).
We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represented approximately 30% of our $396 million of risk management and trading assets as of September 30, 2004. See “Critical Accounting Policies - Mark-to-Market Accounting,” in Item 7 of our 2003 Form
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10-K for more discussion on our valuation methods. See Note 10 for further discussion of credit risk.
Item 4. Controls and Procedures
(a) Evaluation of Disclosure Controls and Procedures
The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
(b) Change in Internal Control over Financial Reporting
No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II – OTHER INFORMATION
Item 1. Legal Proceedings
See Note 12 of Notes to Condensed Consolidated Financial Statements in regard to pending or threatened litigation or other disputes.
Item 5. Other Information
Construction and Financing Programs
See “Liquidity and Capital Resources” in Part I, Item 2 of this report for a discussion of construction and financing programs of the Company and its subsidiaries.
Regulatory Matters
See Note 5 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of regulatory developments.
Environmental Matters
ADEQ issued a Notice of Violation to APS in January 2004 alleging that, among other things, the discharge limit for lead was exceeded at the Saguaro Power Plant. See “Environmental Matters – Arizona Department of Environmental Quality” in Part I, Item 1 of the 2003 10-K. In August 2004, ADEQ closed the Notice of Violation without issuing any penalty.
See “Environmental Matters — Superfund” in Note 12 of Notes to Condensed Consolidated Financial Statements for a discussion of a superfund site.
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Item 6. Exhibits
(a) Exhibits
In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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