-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, OR72ytMn/ZFwSn1RExJV3uup9gqRz9wiC/Hco3CZFwuM3ZYVDJqYYjnDs65D16AQ c/kxxGkYLnYphxxR2OWiUw== 0000950147-03-000434.txt : 20030331 0000950147-03-000434.hdr.sgml : 20030331 20030331150600 ACCESSION NUMBER: 0000950147-03-000434 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARIZONA PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000007286 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 860011170 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-04473 FILM NUMBER: 03629766 BUSINESS ADDRESS: STREET 1: 400 N FIFTH ST STREET 2: P O BOX 53999 CITY: PHOENIX STATE: AZ ZIP: 85004 BUSINESS PHONE: 6022501000 10-K 1 e-9778.txt ANNUAL REPORT FOR THE FISCAL YR ENDED 12/31/2002 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______ TO ______ COMMISSION FILE NUMBER 1-4473 ARIZONA PUBLIC SERVICE COMPANY (Exact name of registrant as specified in its charter) ARIZONA (State or other jurisdiction 86-0011170 of incorporation or organization) (I.R.S. Employer Identification No.) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (Address of principal executive (602) 250-1000 offices, (Registrant's telephone number, including zip code) including area code) ================================================================================ SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OR 12(g) OF THE ACT: None. ================================================================================ 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in any amendment to this Form 10-K. [X] Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [ ] No [X] As of March 31, 2003, there were issued and outstanding 71,264,947 shares of the registrant's common stock, $2.50 par value, all of which were held beneficially and of record by Pinnacle West Capital Corporation. ================================================================================ THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I1(a) AND (b) AND IS THEREFORE FILING THIS DOCUMENT WITH THE REDUCED DISCLOSURE FORMAT. ================================================================================ TABLE OF CONTENTS PAGE ---- GLOSSARY..................................................................... 1 PART I Item 1. Business.......................................................... 3 Item 2. Properties........................................................ 18 Item 3. Legal Proceedings................................................. 23 Item 4. Submission of Matters to a Vote of Security Holders............... 23 PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters............................................. 24 Item 6. Selected Financial Data........................................... 25 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................................... 26 Item 7A. Quantitative and Qualitative Disclosures about Market Risk........ 54 Item 8. Financial Statements and Supplementary Data....................... 55 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..........................................111 PART III Item 10. Directors and Executive Officers of the Registrant................111 Item 11. Executive Compensation............................................111 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.................................111 Item 13. Certain Relationships and Related Transactions....................111 Item 14. Controls and Procedures...........................................112 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..113 SIGNATURES...................................................................141 i GLOSSARY ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission ADEQ - Arizona Department of Environmental Quality AISA - Arizona Independent Scheduling Administrator ALJ - Administrative Law Judge ANPP - Arizona Nuclear Power Project, also known as Palo Verde APS - Arizona Public Service Company, the Company APS Energy Services - APS Energy Services Company, Inc., a subsidiary of Pinnacle West CC&N - Certificate of Convenience and Necessity Cholla - Cholla Power Plant Citizens - Citizens Communications Company Clean Air Act - the Clean Air Act, as amended Company - Arizona Public Service Company CPUC - California Public Utility Commission DOE - United States Department of Energy EITF - the FASB's Emerging Issues Task Force EPA - United States Environmental Protection Agency ERMC -Energy Risk Management Committee FASB - Financial Accounting Standards Board FERC - United States Federal Energy Regulatory Commission FIN - FASB Interpretation Financing Application - our application filed with the ACC on September 16, 2002 FIP - Federal Implementation Plan Fitch - Fitch, Inc. Four Corners - Four Corners Power Plant GAAP - accounting principles generally accepted in the United States of America Interim Financing Application - our application filed with the ACC on November 8, 2002 IRS - United States Internal Revenue Service ISO - California Independent System Operator kW - kilowatt, one thousand watts kWh - kilowatt - hour, one thousand watts per hour Moody's - Moody's Investors Service MW - megawatt, one million watts MWh - megawatt-hours, one million watts per hour Native Load - retail and wholesale sales supplied under traditional cost-based rate regulation 1999 Settlement Agreement - comprehensive settlement agreement related to the implementation of retail electric competition NOV - Notice of Violation NRC - United States Nuclear Regulatory Commission Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended OCI - other comprehensive income Palo Verde - Palo Verde Nuclear Generating Station PG&E - PG&E Corp. Pinnacle West - Pinnacle West Capital Corporation, parent company of the Company Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of Pinnacle West PRP - potentially responsible parties under Superfund PX - California Power Exchange RTO - regional transmission organization Rules - ACC retail electric competition rules Salt River Project - Salt River Project Agricultural Improvement and Power District SCE - Southern California Edison Company SEC - United States Securities and Exchange Commission SFAS - Statement of Financial Accounting Standards SMD - standard market design SPE - special-purpose entity Standard & Poor's - Standard & Poor's Corporation SunCor - SunCor Development Company, a subsidiary of Pinnacle West Superfund - Comprehensive Environmental Response, Compensation and Liability Act System - non-trading energy related activities T&D - transmission and distribution Track A Order - ACC order dated September 10, 2002 regarding generation asset transfers and related issues Track B Order -ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizona's investor-owned electric utilities Trading - energy-related activities entered into with the objective of generating profits on changes in market prices VIE - variable interest entity WestConnect - WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission lines in the southwestern United States 2 PART I ITEM 1. BUSINESS CURRENT STATUS GENERAL We were incorporated in 1920 under the laws of Arizona and currently have more than 902,000 customers. Pinnacle West owns all of our outstanding common stock. We provide either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about half of the Phoenix metropolitan area. Electricity is delivered through a distribution system that we own. We also generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading division, as discussed below, sells, in the wholesale market, our and Pinnacle West Energy's generation output that is not needed for our Native Load, which includes loads for retail customers and cost-of-service wholesale customers. We do not distribute any products. During 2002, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 1% of total electric revenues. At December 31, 2002, we employed approximately 5,100 people, which includes employees assigned to joint-owned generating facilities for which we serve as the generating facility manager. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). MARKETING AND TRADING In early 2003, the marketing and trading division was moved from Pinnacle West to us for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" below). The marketing and trading division sells, in the wholesale market, our and Pinnacle West Energy generation output that is not needed for our Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. The division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Financial Outlook" in Item 7 for a discussion of our implementation of an ACC-mandated process by which we must competitively procure energy. Additionally, the marketing and trading division, subject to specific parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 for information about the historical and prospective contribution of the marketing and trading activities to our financial results. BUSINESS SEGMENTS We have two principal business segments (determined by services and the regulatory environment): 3 * our regulated electricity segment (98% of operating revenues in 2002), which consists of regulated traditional retail and wholesale electricity businesses and related activities, and includes electricity transmission, distribution and generation; and * our marketing and trading segment (2% of operating revenues in 2002), which consists of our competitive energy business activities, including wholesale marketing and trading. See Note 15 of Notes to Financial Statements in Item 8 for financial information about our business segments. OVERVIEW OF ARIZONA REGULATORY DEVELOPMENTS As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Financial Outlook" in Item 7, we believe pending Arizona regulatory matters are among the key factors affecting our financial outlook. GENERAL On September 21, 1999, the ACC approved Rules that provided a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among us and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, we were required to transfer all of our competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, we had been addressing the legal and regulatory requirements necessary to complete the transfer of our generation assets to Pinnacle West Energy on or before that date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed us not to transfer our generation assets to Pinnacle West Energy. See Note 3 of Notes to Financial Statements in Item 8 for additional information about the 1999 Settlement Agreement, the Rules (including legal challenges to the Rules), and the Track A Order. FINANCING APPLICATION On September 16, 2002, we filed an application with the ACC requesting the ACC to allow us to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to Pinnacle West; to guarantee up to $500 million of Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to exceed $500 million in the aggregate. In our application, we stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between us and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing that Pinnace West provided to fund the construction of Pinnacle West Energy generation assets or from effectively competing in wholesale markets. On March 27, 2003, the ACC authorized us to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt or a combination of both, not to exceed $500 million in the aggregate. See "ACC Applications" in Note 3 of Notes to Financial Statements in Item 8 for additional information. 4 COMPETITIVE PROCUREMENT PROCESS On September 10, 2002, the ACC issued an order that, among other things, established a requirement that we competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order, which documented the decision made by the ACC at its open meeting on February 27, 2003, addressing this requirement. Under the order, we will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, we will be required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in our retail load and retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets." The order recognizes our right to reject any bids that are unreasonable, uneconomical or unreliable. We expect to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply our electricity requirements. See "Track B Order" in Note 3 of Notes to Financial Statements in Item 8 for additional information. GENERAL RATE CASE As required by the 1999 Settlement Agreement, on or before June 30, 2003, we will file a general rate case with the ACC. In this rate case, we will update our cost of service and rate design. In addition, we expect to seek: * rate base treatment of certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3); * recovery of the $234 million pretax asset write-off recorded by us as a result of the 1999 Settlement Agreement; and * recovery of costs incurred by us in preparation for the previously required transfer of generation assets to Pinnacle West Energy. We assume that the ACC will make a decision in this general rate case by the end of 2004. 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. 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. These factors include the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition; the outcome of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including price caps and other market constraints imposed by the FERC; 5 regional economic and market conditions, including the California energy situation and completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital and access to capital markets; weather variations affecting local and regional customer energy usage; the effect of conservation programs on energy usage; power plant performance; our ability to compete successfully outside traditional regulated markets (including the wholesale market); our ability to manage our marketing and trading activities and the use of derivative contracts in our business; technological developments in the electric industry; the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommissioning trust funds; and other uncertainties, all of which are difficult to predict and many of which are beyond our control. REGULATION AND COMPETITION RETAIL The ACC regulates our retail electric rates and our issuance of securities. The ACC must also approve any transfer of our utility property and certain transactions between us and affiliated parties. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Financial Outlook" in Item 7 and Note 3 of Notes to Financial Statements in Item 8 for a discussion of the status of electric industry restructuring in Arizona. We are subject to varying degrees of competition from other utilities in Arizona (such as Tucson Electric Power Company, Southwest Gas Corporation and Citizens Communications Company) as well as cooperatives, municipalities, electrical districts and similar types of governmental organizations (principally Salt River Project). We also face competition from low-cost hydroelectric power and parties that have access to low-priced preferential federal power and other subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate facilities to generate their own electric energy requirements. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our 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 effectively in a restructured industry. WHOLESALE GENERAL The FERC regulates rates for wholesale power sales and transmission services. During 2002, approximately 11% of our electric operating revenues resulted from such sales and services. In early 2003, the marketing and trading division was moved from Pinnacle West to us for all future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" above). The marketing and trading division sells, in the wholesale market, our and Pinnacle West Energy's generation output that is not needed for our Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. The division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer energy requirements. See "Track B Order" in Note 3 of 6 Notes to Financial Statements in Item 8 for information regarding an ACC-mandated process by which we must competitively procure energy. REGIONAL TRANSMISSION ORGANIZATIONS On December 20, 1999, the FERC issued its Order No. 2000 regarding regional transmission organizations. In its order, the FERC set minimum characteristics and functions that must be met by utilities that participate in RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and nondiscriminatory markets and exclusive authority to maintain short-term reliability. As stated in Order No. 2000, the FERC believes that a number of benefits will result from the formation of RTOs throughout the country, and it has moved aggressively to ensure that all public utilities participate in an RTO or demonstrate why such participation is not feasible. According to the FERC, the benefits it expects to result from RTO formation include: (1) improvements in transmission system operations with resulting enhancements to inter-regional trade, congestion management, reliability and coordination; and (2) improved performance of energy markets, including greater incentives for efficient generator performance and enhanced potential for demand response. On October 16, 2001, we and other owners of electric transmission lines in the Southwest filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC's requirements for the formation of an RTO. We and the other filing parties have agreed to fund the start-up of WestConnect's operations, which are subject to FERC approval. WestConnect has been structured as a for-profit RTO and evolved from DesertSTAR, a not-for-profit corporation in which we participated, which was originally designed to serve as an RTO for the southwestern United States. The success of WestConnect will be largely dependent on participation by all major transmission owners in the Southwest. The success is also dependent on support from the affected state regulatory commissions. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC's RTO requirements and provide the basic framework for a standard market design for the Southwest. In its order, the FERC also stated that its approval of various WestConnect provisions addressed in the order would not be overturned or affected by the final rule the FERC intends to ultimately adopt in response to its July 31, 2002 Notice of Proposed Rulemaking regarding a standard market design for the electric utility industry (see "Federal" in Note 3 of Notes to Financial Statements in Item 8 for additional information regarding the Notice of Proposed Rulemaking). On November 12, 2002, we and other owners filed a request for rehearing and clarification on portions of the October 10, 2002 order. On December 23, 2002, the FERC issued its order on rehearing. In it, the FERC clarified the RTO elements that it had approved. In its order, the FERC stated that it envisions the Seams Steering Group - Western Interconnection (SSG-WI) as the entity that will facilitate a common market design for the West. The SSG-WI consists of western transmission owners, including members of WestConnect. The FERC also noted that its prior WestConnect order did not address other elements of market design that are currently being considered in the pending SMD proposal and/or through the SSG-WI process. The FERC clarified 7 that there are only three areas that would be subject to the final SMD rule: (1) transmission credits; (2) resource adequacy; and (3) market monitoring. The order also stated that FERC's approval of the for-profit structure will not predetermine its decision in the final SMD rule regarding whether a for-profit independent transmission company should be permitted to perform all the functions of an independent transmission provider. To the extent that the FERC has not addressed aspects of WestConnect's for-profit proposal or WestConnect's proposed particular functions, such elements will be subject to review for consistency with Order No. 2000 and other related decisions regarding functions that may be performed by an independent transmission company. The WestConnect applicants sought further clarification of that aspect of the rehearing order. The FERC has indicated that it will issue an order on the WestConnect applicants' motion for clarification before April 14, 2003. The ACC Rules also required the formation and implementation of an Arizona Independent Scheduling Administrator. The purpose of the AISA is to oversee the application of operating protocols to ensure statewide consistency for transmission access. The AISA is anticipated to be a temporary organization until the implementation of an independent system operator or RTO. APS participated in the creation of the AISA, a not-for-profit entity, and the filing at the FERC for approval of its operating protocols. The operating protocols were partially rejected and the remainder are currently under review. On February 8, 2002, the ACC's Chief ALJ issued a procedural order which consolidated the ACC docket relating to the AISA with several other pending ACC dockets. In its Track B Order, the ACC directed that a hearing be held on whether or not we should be required to continue funding the AISA. PURCHASED POWER AND GENERATING FUEL See "Properties - Net Accredited Capacity" in Item 2 for information about our power plants by fuel types. 2002 ENERGY MIX Our sources of energy during 2002 were: purchased power - 30.4% (approximately 60% of which was for wholesale power operations); coal - 37.2%; nuclear -27.7%; gas - 4.6%; and other (includes oil, hydro and solar) - 0.1%. COAL SUPPLY CHOLLA Cholla is a coal-fired power plant located in northeastern Arizona. It is a jointly-owned facility operated by us. We purchase most of Cholla's coal requirements from a coal supplier that mines all of the coal under a long-term lease of coal reserves owned by the Navajo Nation, the federal government and private landholders. Cholla has sufficient coal, including low sulfur coal, under current contracts to ensure a reliable fuel supply through 2007. We purchase a portion of Cholla's coal requirements on the spot market to take advantage of competitive pricing options. Following expiration of current contracts, we believe that numerous competitive fuel supply options will exist to ensure the continued operation of Cholla for its useful life. FOUR CORNERS Four Corners is a coal-fired power plant located in the northwest corner of New Mexico. It is a jointly-owned facility operated by us. We purchase all of Four Corners' coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. Four Corners is 8 under contract for coal through 2004, with options to extend the contract through the plant site lease expiration in 2017. NAVAJO GENERATING STATION The Navajo Generating Station is a coal-fired power plant located in northern Arizona. It is a jointly-owned facility operated by Salt River Project. The Navajo Generating Station's coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through the plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. The lease provides for the potential to renegotiate the coal royalty in 2007 and 2017, which may impact the fuel price. See "Properties - Net Accredited Capacity" in Item 2 for information about our ownership interest in Cholla, Four Corners and the Navajo Generating Station. See Note 10 of Notes to Financial Statements in Item 8 for information regarding our coal mine reclamation obligations. NATURAL GAS SUPPLY We purchase the majority of our natural gas requirements for our gas-fired plants under contracts with a number of natural gas suppliers. Our natural gas supply is transported pursuant to a firm, full requirements transportation service agreement with El Paso Natural Gas Company. The transportation agreement features a 10-year rate moratorium established in a comprehensive rate case settlement entered into in 1996. In a pending FERC proceeding, El Paso Natural Gas Company has proposed allocating its gas pipeline capacity in such a way that our (and other companies with the same contract type) gas transportation rights could be significantly impacted. Various parties, including Pinnacle West Energy and us, have challenged this allocation as being inconsistent with El Paso Natural Gas Company's existing contractual obligations and a 1996 settlement. On May 31, 2002 the FERC issued an order requiring the conversion of all firm, full requirements contracts to contract demand contracts by November 1, 2002. In addition, the FERC order set forth procedures to encourage parties to resolve the details of such conversions through a settlement process. We and other full requirements contract holders sought rehearing of the FERC order and requested a stay of the November 1, 2002 implementation date. On September 20, 2002, the FERC issued another order clarifying the capacity allocation methodology, extending the conversion implementation date from November 1, 2002 to May 1, 2003 and approving the reallocation of costs for the transportation service. We and other full requirements contract holders have sought rehearings of this FERC order. The FERC has indicated that it intends to issue an order on the merits in this proceeding by April 14, 2003. Although we cannot predict the outcome of this matter, we currently do not expect this matter to have a material adverse impact on our financial position, results of operations or liquidity. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements. NUCLEAR FUEL SUPPLY PALO VERDE FUEL CYCLE Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. It is a jointly-owned facility operated by us. The fuel cycle for Palo Verde is comprised of the following stages: 9 * mining and milling of uranium ore to produce uranium concentrates; * conversion of uranium concentrates to uranium hexafluoride; * enrichment of uranium hexafluoride; * fabrication of fuel assemblies; * utilization of fuel assemblies in reactors; and * storage and disposal of spent nuclear fuel. The Palo Verde participants have contracted for all of Palo Verde's requirements for uranium concentrates and conversion services through 2008, except for a small percentage of 2003 uranium concentrates and 2004 conversion requirements that will be obtained under contracts currently being finalized. The Palo Verde participants have also contracted for all of Palo Verde's enrichment services through 2010 and fuel assembly fabrication services until at least 2015. SPENT NUCLEAR FUEL AND WASTE DISPOSAL Nuclear power plant operators are required to enter into spent nuclear 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 that 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 filed damages lawsuits against the DOE in the Court of Federal Claims. In February 2002, the U.S. Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the President's recommendation. In July 2002, Congress approved the development of the Yucca Mountain, Nevada site, overriding the Nevada veto. It is now expected that the DOE will submit a license application to the NRC late in 2004. The State of Nevada has filed several lawsuits relating to the Yucca Mountain site. We cannot currently predict what further steps will be taken in this area. Facility funding is a further complication. While all nuclear utilities pay an amount calculated on the basis of the output of their respective plants into a so-called nuclear waste fund the annual Congressional appropriations for the permanent repository have been for amounts less than the amounts paid into the waste fund (the balance of which is being used for other purposes). We have existing fuel storage pools at Palo Verde and have completed a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, we believe that spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit. See "Palo Verde Nuclear Generating Station" in Note 10 of Notes to Financial Statements in Item 8 for a discussion of interim spent nuclear fuel storage costs. Although some low-level waste has been stored on-site in a low-level waste facility, we are currently shipping low-level waste to off-site facilities. We currently believe that interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available. 10 We believe that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, we acknowledge that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which we are less able to predict. We expect to vigorously protect and pursue our rights related to this matter. PURCHASED POWER AGREEMENTS In addition to that available from our own generating capacity (see "Properties" in Item 2), we purchase electricity under various arrangements. One of the most important of these is a long-term contract with Salt River Project. The amount of electricity available to us is based in large part on customer demand within certain areas now served by us pursuant to a related territorial agreement. The generating capacity available to us pursuant to the contract was 336 MW from January through May 2002, and starting in June 2002, it changed to 343 MW. In 2002, we received approximately 1,104,973 MWh of energy under the contract and paid about $46.2 million for capacity availability and energy received. This contract may be canceled by Salt River Project on three years' notice, given no earlier than December 31, 2003. We may also cancel the contract on five years' notice, given no earlier than December 31, 2006. In September 1990, we entered into a thirty-year seasonal capacity exchange agreement with PacifiCorp. Under this agreement, we receive electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and we return electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, we and PacifiCorp each has 480 MW of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2002, we received approximately 571,392 MWh of energy under the capacity exchange. We must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2002, PacifiCorp received offers of 1,129,600 MWh and purchased about 115,750 MWh. CONSTRUCTION PROGRAM During the years 2000 through 2002, we incurred approximately $1.4 billion in capital expenditures. Our capital expenditures for the years 2003 through 2005 are expected to be primarily for expanding transmission and distribution capabilities to meet growing customer needs, for upgrading existing utility property and for environmental purposes. Our capital expenditures were approximately $501 million in 2002. Our capital expenditures, including expenditures for environmental control facilities, for the years 2003 through 2005 have been estimated as follows: (dollars in millions) BY YEAR BY MAJOR FACILITIES ---------------------------- ---------------------------- 2003 $ 401 Production $ 386 2004 379 T&D 877 2005 498 Other 15 ------- ------- Total $ 1,278 Total $ 1,278 ======= ======= 11 The above amounts exclude capitalized interest costs and include capitalized property taxes and approximately $30 million per year for nuclear fuel. These amounts include only our generation (production) assets. We conduct a continuing review of our construction program. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Needs and Resources" in Item 7 for additional information about our construction program. MORTGAGE REPLACEMENT FUND REQUIREMENTS So long as any of our first mortgage bonds are outstanding, we are required for each calendar year to deposit with the trustee under our mortgage cash in a formularized amount related to net additions to our mortgaged utility plant. We may satisfy all or any part of this "replacement fund" requirement by using redeemed or retired bonds, net property additions or property retirements. For 2002, the replacement fund requirement amounted to approximately $161 million. Certain of the bonds we have issued under the mortgage that are callable prior to maturity are redeemable at their par value plus accrued interest with cash we deposit in the replacement fund. These call provisions are subject in many cases to a period of time after the original issuance of the bonds during which they may not be redeemed in this manner. See Note 6 of Notes to Financial Statements in Item 8 for information regarding our first mortgage bonds. ENVIRONMENTAL MATTERS EPA ENVIRONMENTAL REGULATION CLEAN AIR ACT We are subject to a number of requirements under the Clean Air Act. The Clean Air Act addresses, among other things: * "acid rain"; * visibility in certain specified areas; * hazardous air pollutants; and * areas that have not attained national ambient air quality standards. With respect to "acid rain," the Clean Air Act established a system of sulfur dioxide emissions "allowances" to offset each ton of sulfur dioxide emitted by affected power plants. Based on EPA allowance allocations, we will have sufficient allowances to permit continued operation of our plants at current levels without installing additional equipment. The Clean Air Act also requires the EPA to set nitrogen oxides emissions limitations for certain coal-fired units. The EPA rule allows emissions from all units in a plant to be averaged to demonstrate compliance with the emission limitation. Currently, nitrogen oxides emissions from all of our units are within the limitations specified under the EPA's rules. We do not currently expect this rule to have a material impact on our financial position, results of operations or liquidity. The Clean Air Act required the EPA to establish a Grand Canyon Visibility Transport Commission to complete a study on visibility impairment in sixteen "Class I Areas" (large national parks and wilderness areas) on the Colorado Plateau. The Navajo Generating Station, Cholla and Four Corners are located near several Class I Areas on the Colorado Plateau. The Visibility Commission 12 completed its study and on June 10, 1996 submitted its final recommendations to the EPA. On April 22, 1999, the EPA announced final regional haze rules. These new regulations require states to submit, by 2008, implementation plans to eliminate all man-made emissions causing visibility impairment in certain specified areas, including Class I Areas in the Colorado Plateau. The 2008 implementation plans must also include consideration and potential application of best available retrofit technology for major stationary sources which came into operation between August 1962 and August 1977, such as the Navajo Generating Station, Cholla and Four Corners. The rules allow the nine western states and tribes that participated in the Visibility Commission process to follow an alternate implementation plan and schedule for the Class I Areas considered by the Visibility Commission. Under this option, those states and tribes would submit implementation plans by 2003, which would incorporate certain regional sulfur dioxide emissions milestones for the years 2003, 2008, 2013 and 2018 (which include the application of best available retrofit technology). If the regional emissions in those years were within those milestones, there would be no further emission reduction requirements, and if they were exceeded, then an emission trading program would be implemented to maintain the emissions within those milestones. The EPA reviewed an "Annex" to the Visibility Commission recommendations that specify the regional sulfur dioxide emission milestones. On April 26, 2002, the EPA proposed to accept the Visibility Commission's Annex, which had been submitted by the Western Regional Air Partnership (successor to Visibility Commission) in September 2000. The Annex specifies regional sulfur dioxide emission reduction milestones. The EPA's final approval of the Annex would allow the states and tribes to pursue the alternate implementation of the regional haze rules through 2018. Any states and tribes that implement this option would have to submit state implementation plans by 2003 to address visibility in areas identified in the process, and revised implementation plans in 2008 to address Class I Areas which were not included in the process. The State of Arizona is in the process of developing a State Implementation Plan to implement the provisions of the Annex. Because Four Corners is located on the Navajo Reservation and is currently regulated by EPA Region IX, the provisions of the Annex currently could become applicable to Four Corners only through a Federal Implementation Plan promulgated by EPA Region IX. At this time, it is uncertain how the State of Arizona and/or EPA Region IX will proceed to implement the Annex, so the actual impact on us cannot yet be determined. In July 1997, the EPA promulgated final National Ambient Air Quality Standards for ozone and particulate matter. Pursuant to these rules, the ozone standard is more stringent and a new ambient standard for very fine particles has been established. Congress has enacted legislation that could delay the implementation of regional haze requirements and the particulate matter ambient standard; however, the legislation does not preclude the Visibility Commission states and tribes from implementing the alternate regional haze rules discussed above. Because the actual level of emissions controls, if any, for any unit cannot be determined at this time, we currently cannot estimate the capital expenditures, if any, which would result from the final rules. However, we do not currently expect these rules to have a material adverse effect on our financial position, results of operations or liquidity. With respect to hazardous air pollutants emitted by electric utility steam generating units, the EPA has determined that mercury emissions and other hazardous air pollutants from coal and oil-fired power plants will be regulated. We expect that the EPA will propose specific rules for this purpose in 2003 and 13 finalize them by 2004, with compliance required by 2008. Because the ultimate requirements that the EPA may impose are not yet known, we cannot currently estimate the capital expenditures, if any, which may be required. Certain aspects of the Clean Air Act may require us to make related expenditures, such as permit fees. We do not expect any of these expenditures to have a material impact on our financial position, results of operations or liquidity. FEDERAL IMPLEMENTATION PLAN In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and Four Corners. The comment period on this proposal ended in November 1999. The FIP is similar to current Arizona regulation of the Navajo Generating Station and New Mexico regulation of Four Corners, with minor modifications. We do not currently expect the FIP to have a material impact on our financial position, results of operations or liquidity. SUPERFUND The Comprehensive Environmental Response, Compensation, and Liability Act (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 potentially responsible parties. PRPs may be strictly, and often jointly and severally, liable for clean-up. The EPA had previously advised us that the EPA considers us to be a PRP in the Indian Bend Wash Superfund Site, South Area. Our Ocotillo Power Plant is located in this area. Based on the information to date, including available insurance coverage and an EPA estimate of cleanup costs, we do not expect this matter to have a material impact on our financial position, results of operations or liquidity. MANUFACTURED GAS PLANT SITES We are currently investigating properties which we now own or which were previously owned by us or our corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. The purpose of this investigation is to determine if: * waste materials are present; * such materials constitute an environmental or health risk; and * we have any responsibility for remedial action. Where appropriate, we have begun clean-up of certain of these sites. We do not expect these matters to have a material adverse effect on our financial position, results of operations or liquidity. ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY ADEQ issued to us NOVs, dated September 25, 2001 and October 15, 2001 alleging, among other things, the burning of unauthorized materials and storage of hazardous waste without a permit at the Cholla Power Plant. Each NOV requires us to achieve and document compliance with specific environmental requirements. We have submitted responses to the NOVs as well as additional information requested by the agency. By letter dated February 28, 2003, the Arizona Attorney General notified us that the ADEQ expects to take enforcement action against us regarding the violations included in the NOVs, as well as related violations. We do not expect these matters to have a material adverse effect on our financial position, results of operations or liquidity. 14 NAVAJO NATION ENVIRONMENTAL ISSUES Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. We are the Four Corners operating agent. We own a 100% interest in Four Corners Units 1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. We own a 14% interest in Navajo Generating Station Units 1, 2 and 3. In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those that occur at Four Corners and the Navajo Generating Station. The Four Corners and Navajo Generating Station participants dispute that purported authority, and by separate letters dated October 12 and October 13, 1995, the Four Corners participants and the Navajo Generating Station participants requested the United States Secretary of the Interior to resolve their dispute with the Navajo Nation regarding whether or not the Navajo Acts apply to operations of Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, seeking, among other things, a declaratory judgment that: * their respective leases and federal easements preclude the application of the Navajo Acts to the operations of Four Corners and the Navajo Generating Station; and * the Navajo Nation and its agencies and courts lack adjudicatory jurisdiction to determine the enforceability of the Navajo Acts as applied to Four Corners and the Navajo Generating Station. On October 18, 1995, the Navajo Nation and the Four Corners and Navajo Generating Station participants agreed to indefinitely stay these proceedings so that the parties may attempt to resolve the dispute without litigation. The Secretary and the Court have stayed these proceedings pursuant to a request by the parties. We cannot currently predict the outcome of this matter. In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Indian tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants and the Navajo Generating Station participants that could limit the Navajo Nation's environmental regulatory authority over the Navajo Generating Station and Four Corners. We believe that the Clean Air Act does not supersede these pre-existing agreements. We cannot currently predict the outcome of this matter. In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. We believe that the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo Generating Station participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. We cannot currently predict the outcome of this matter. 15 WATER SUPPLY Assured supplies of water are important for our generating plants. At the present time, we have adequate water to meet our needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions. Both groundwater and surface water in areas important to our operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. We are one of a number of parties in a proceeding before a state court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. (STATE OF NEW MEXICO, IN THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY OF FARMINGTON, UTAH INTERNATIONAL, INC., ET AL., SAN JUAN COUNTY, NEW MEXICO, District Court No. 75-184). An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for a then-agreed upon cost, sufficient water from our allocation to offset the loss. A summons served on us in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. (IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA RIVER SYSTEM AND SOURCE, Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the geographic area subject to the summons. Our rights and the rights of the Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As project manager of Palo Verde, we filed claims that dispute the court's jurisdiction over the Palo Verde participants' groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, we seek confirmation of such rights. Three of our other power plants and two of Pinnacle West Energy's power plants are also located within the geographic area subject to the summons. Our claims dispute the court's jurisdiction over our groundwater rights with respect to these plants. Alternatively, we seek confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court's criteria for resolving groundwater claims. Litigation on both of these issues will continue in the trial court. No trial date concerning our water rights claims has been set in this matter. We have also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court. (IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE LITTLE COLORADO RIVER SYSTEM AND SOURCE, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417). Our groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. Our claims dispute the court's jurisdiction over our groundwater rights. Alternatively, we seek confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning our water rights claims has been set in this matter. 16 Although the foregoing matters remain subject to further evaluation, we expect that the described litigation will not have a material adverse impact on our financial position, results of operations or liquidity. The Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants in 2003, as well as later years if adequate moisture is not received in the watershed that supplies the area. Various stakeholders in the San Juan Basin, including the New Mexico State Engineer, are evaluating how water rights might be affected by the drought conditions, including water rights pursuant to the New Mexico state permit that provide approximately 30,000 acre feet of water to Four Corners. We are assessing alternatives for temporary supplies of water and are working with area stakeholders to minimize the effect, if any, on operations of the plant. The effect of the drought cannot be fully assessed at this time, and we cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners. 17 ITEM 2. PROPERTIES NET ACCREDITED CAPACITY Our present generating facilities have net accredited capacities as follows: Capacity(kW) ------------ Coal: Units 1, 2 and 3 at Four Corners.............................. 560,000 15% owned Units 4 and 5 at Four Corners....................... 222,000 Units 1, 2 and 3 at Cholla Plant.............................. 615,000 14% owned Units 1, 2 and 3 at the Navajo Plant................ 315,000 --------- Subtotal 1,712,000 --------- Gas or Oil: Two steam units at Ocotillo and two steam units at Saguaro.... 430,000(a) Eleven combustion turbine units............................... 493,000 Three combined cycle units.................................... 255,000 --------- Subtotal 1,178,000 --------- Nuclear: 29.1% owned or leased Units 1, 2, and 3 at Palo Verde......... 1,086,300 --------- Hydro and Solar................................................. 7,600 --------- Total........................................................... 3,983,900 ========= - ---------- (a) Does not include West Phoenix steam units (108,300 kW), which were retired in December 2002. 18 RESERVE MARGIN Our 2002 peak one-hour demand on our electric system was recorded on July 9, 2002 at 5,802,900 kW, compared to the 2001 peak of 5,687,200 kW recorded on July 2, 2001. Taking into account additional capacity then available to us under long-term purchase power contracts as well as our and Pinnacle West Energy's generating capacity, our capability of meeting system demand on July 9, 2002, amounted to 6,046,600 kW, for an installed reserve margin of 6.5%. The power actually available to us from our resources fluctuates from time to time due in part to planned outages and technical problems. The available capacity from sources actually operable at the time of the 2002 peak amounted to 3,877,600 kW, for a margin of negative 38.1%. Firm purchases totaling 2,612,000 kW, including short-term seasonal purchases and unit contingent purchases were in place at the time of the peak ensuring the ability to meet the load requirement, with an actual reserve margin of 7.1%. See "Purchased Power Agreements" in Item 1 for information about certain of our long-term power agreements. PLANT SITES LEASED FROM NAVAJO NATION The Navajo Generating Station and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. These are long-term agreements with options to extend, and we do not believe that the risk with respect to enforcement of these easements and leases is material. The majority of coal contracted for use in these plants and certain associated transmission lines are also located on Indian reservations. See "Purchased Power and Generating Fuel - Coal Supply" in Item 1. PALO VERDE NUCLEAR GENERATING STATION PALO VERDE LEASES See Note 8 of Notes to Financial Statements in Item 8 for a discussion of three sale-leaseback transactions related to Palo Verde Unit 2. REGULATORY Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize us, as operating agent for Palo Verde, to operate the three Palo Verde units at full power. NUCLEAR DECOMMISSIONING COSTS The NRC rules on financial assurance requirements for the decommissioning of nuclear power plants provide that a licensee may use a trust as the exclusive financial assurance mechanism if the licensee recovers estimated total decommissioning costs through cost of service rates or through a "non-bypassable charge." The "non-bypassable systems benefits" charge is the charge that the ACC has approved to recover certain types of ACC-approved costs, including costs for low income programs, demand side management, consumer education, environmental, renewables, etc. "Non-bypassable" means that if a customer chooses to take 19 energy from an "energy service provider" other than us, the customer will still have to pay this charge to us as part of the customer's electric bill. Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on the external sinking fund mechanism are not met. We currently rely on the external sinking fund mechanism to meet the NRC financial assurance requirements for our interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in our ACC jurisdictional rates. ACC retail electric competition Rules provide that decommissioning costs would be recovered through a non-bypassable "system benefits" charge, which would allow us to maintain our external sinking fund mechanism. See Note 11 of Notes to Financial Statements in Item 8 for additional information about our nuclear decommissioning costs. PALO VERDE LIABILITY AND INSURANCE MATTERS See "Palo Verde Nuclear Generating Station" in Note 10 of Notes to Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including us, for Palo Verde. PROPERTY NOT HELD IN FEE OR SUBJECT TO ENCUMBRANCES JOINTLY-OWNED FACILITIES We share ownership of some of our generating and transmission facilities with other companies. The following table shows our interest in those jointly-owned facilities recorded on the Balance Sheets at December 31, 2002: PERCENT OWNED BY US ----------- Generating facilities: Palo Verde Nuclear Generating Station Units 1 and 3 29.1% Palo Verde Nuclear Generating Station Unit 2 (see "Palo Verde Leases" below) 17.0% Four Corners Steam Generating Station Units 4 and 5 15.0% Navajo Steam Generating Station Units 1, 2, and 3 14.0% Cholla Steam Generating Station Common Facilities (a) 62.8%(b) Transmission facilities: ANPP 500KV System 35.8%(b) Navajo Southern System 31.4%(b) Palo Verde-Yuma 500KV System 23.9%(b) Four Corners Switchyards 27.5%(b) Phoenix-Mead System 17.1%(b) Palo Verde - Estrella 500KV System 50.0%(b) (a) PacifiCorp owns Cholla Unit 4 and we operate the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned. 20 (b) Weighted average of interests. PALO VERDE LEASES In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. We account for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. See Notes 8 and 18 of Notes to Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale-leaseback transactions. FIRST MORTGAGE LIEN Our first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). See Note 6 of Notes to Financial Statements in Item 8 for information regarding our outstanding first mortgage bonds. OTHER INFORMATION REGARDING OUR PROPERTIES See "Environmental Matters" and "Water Supply" in Item 1 with respect to matters having possible impact on the operation of certain of our power plants. See "Construction Program" in Item 1 and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" in Item 7 for a discussion of our construction plans. 21 [MAP PAGE} In accordance with Item 304 of Regulation S-T of the Securities Exchange Act of 1934, APS' Service Territory map contained in this Form 10-K is a map of the State of Arizona showing APS' service area, the location of its major power plants and principal transmission lines, the location of Pinnacle West Energy's power plants and the location of transmission lines operated by APS for others. APS' major power plants shown on such map are the Navajo Generating Station located in Coconino County, Arizona; the Four Corners Power Plant located near Farmington, New Mexico; the Cholla Power Plant, located in Navajo County, Arizona; the Yucca Power Plant, located near Yuma, Arizona; the Palo Verde Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona; the West Phoenix Power Plant, located near Phoenix, Arizona; and the Saguaro Power Plant, located near Tucson, Arizona (each of which plants is reflected on such map as being jointly owned with other utilities), as well as the Ocotillo Power Plant located near Phoenix, Arizona. Pinnacle West Energy's power plants shown on such map are the West Phoenix Power Plant located near Phoenix, Arizona, and the Saguaro Power Plant, located near Tucson, Arizona (both of which plants are reflected on such map as being jointly owned with APS), as well as the Redhawk Power Plant, located near Phoenix, Arizona. APS' major transmission lines shown on such map are reflected as running between the power plants named above and certain major cities in the State of Arizona. The transmission lines operated for others shown on such map are reflected as running from the Four Corners Plant through a portion of northern Arizona to the California border and from the Phoenix area. 22 ITEM 3. LEGAL PROCEEDINGS See "Environmental Matters" and "Water Supply" in Item 1 in regard to pending or threatened litigation and other disputes. See Note 3 of Notes to Financial Statements in Item 8 for a discussion of the ACC retail electric competition Rules, the Track A Order and related litigation. See Note 10 of Notes to Financial Statements in Item 8 for information relating to the FERC proceedings on California energy market issues and a claim by Citizens that we overcharged Citizens under a power service agreement. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 23 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS Our common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for our common stock. The chart below sets forth the dividends declared on the Company's common stock for each of the four quarters for 2002 and 2001. COMMON STOCK DIVIDENDS (DOLLARS IN THOUSANDS) QUARTER 2002 2001 ----------- ------- ------- 1st Quarter $42,500 $42,500 2nd Quarter 42,500 42,500 3rd Quarter 42,500 42,500 4th Quarter 42,500 42,500 After payment or setting aside for payment of cumulative dividends and mandatory sinking fund requirements, where applicable, on all outstanding issues of preferred stock, the holders of common stock are entitled to dividends when and as declared out of funds legally available therefor. See Note 6 of Notes to Financial Statements in Item 8 for restrictions on retained earnings available for the payment of common stock dividends. As of December 31, 2002, we did not have any outstanding preferred stock. 24 ITEM 6. SELECTED FINANCIAL DATA
2002 2001 2000 1999 1998 ------------ ------------ ------------ ------------ ------------ (DOLLARS IN THOUSANDS) Electric operating revenues: Regulated electricity segment $ 2,059,339 $ 2,562,088 $ 2,538,750 $ 1,914,722 $ 1,741,148 Marketing and trading segment 34,054 549,240 395,392 154,126 180,145 Purchased power and fuel costs: Regulated electricity segment 595,368 1,227,188 1,065,596 432,844 306,884 Marketing and trading segment 32,662 313,991 267,032 136,522 151,164 Operating expenses 1,136,363 1,171,171 1,155,278 1,115,664 1,097,471 ------------ ------------ ------------ ------------ ------------ Operating income 329,000 398,978 446,236 383,818 365,774 Other income/(deductions) (8,041) (79) (6,545) 20,857 20,315 Interest deductions - net 121,616 118,211 133,097 136,353 130,842 ------------ ------------ ------------ ------------ ------------ Income before extraordinary charge and cumulative effect adjustment 199,343 280,688 306,594 268,322 255,247 Extraordinary charge - net of tax (a) -- -- -- (139,885) -- Cumulative effect of change in accounting - net of tax (b) -- (15,201) -- -- -- ------------ ------------ ------------ ------------ ------------ Net income 199,343 265,487 306,594 128,437 255,247 Preferred dividends -- -- -- 1,016 9,703 ------------ ------------ ------------ ------------ ------------ Earnings for common stock $ 199,343 $ 265,487 $ 306,594 $ 127,421 $ 245,544 ============ ============ ============ ============ ============ Total Assets $ 6,521,807 $ 6,225,733 $ 6,349,609 $ 6,079,307 $ 6,356,534 ============ ============ ============ ============ ============ Capital Structure: Common stock equity $ 2,159,312 $ 2,150,690 $ 2,119,768 $ 1,983,174 $ 1,975,755 Non-redeemable preferred stock -- -- -- -- 85,840 Redeemable preferred stock -- -- -- -- 9,401 Long-term debt less current maturities 2,217,340 1,949,074 1,806,908 1,997,400 1,876,540 ------------ ------------ ------------ ------------ ------------ Total capitalization 4,376,652 4,099,764 3,926,676 3,980,574 3,947,536 Commercial paper -- 171,162 82,100 38,300 178,830 Current maturities of long-term debt 3,503 125,451 250,266 114,711 164,378 ------------ ------------ ------------ ------------ ------------ Total $ 4,380,155 $ 4,396,377 $ 4,259,042 $ 4,133,585 $ 4,290,744 ============ ============ ============ ============ ============
- ---------- (a) Changes associated with a regulatory disallowance. See "Regulatory Accounting" in Note 1. (b) Change in accounting standards related to derivatives in 2001. See Note 16 See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 for a discussion of certain information in the table above. 25 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION In this Item, we explain our results of operations, general financial condition, and outlook including: * the changes in our earnings from 2001 to 2002 and from 2000 to 2001; * our capital needs, liquidity and capital resources; * our critical accounting policies; * our business outlook and major factors that affect our financial outlook; and * our management of market risks. Throughout this Item, we refer to specific "Notes" in the Notes to Financial Statements in Item 8 of this report. These Notes add further details to the discussion. BUSINESS OVERVIEW We are an electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about half of the Phoenix metropolitan area. Electricity is delivered through a distribution system that we own. We also generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading division sells, in the wholesale market, our and Pinnacle West Energy's generation output that is not needed for our Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. We do not distribute any products. Pinnacle West owns all of our outstanding common stock. SUMMARY OF KEY FACTORS AFFECTING OUR FINANCIAL OUTLOOK We believe the following are among the key factors affecting our financial outlook: * The following ACC regulatory matters: * Our $500 million financing application, which the ACC approved on March 27, 2003; * The implementation of the ACC-mandated process by which we must competitively procure energy; and * Our general rate case to be filed in 2003. * Wholesale power market conditions in the western United States. We discuss each of these, and other, factors in detail below in the section entitled "Factors Affecting Our Financial Outlook." 26 BUSINESS SEGMENTS We have two principal business segments (determined by services and the regulatory environment): * our regulated electricity segment, which consists of regulated traditional retail and wholesale electricity businesses and related activities, and includes electricity transmission, distribution and generation; and * our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading. The following is a summary of earnings by business segment for the years ended December 31, 2002, 2001, and 2000 (dollars in millions): 2002 2001 2000 ------ ------ ------ Regulated electricity $ 198 $ 138 $ 228 Marketing and trading 1 142 79 Income before accounting change 199 280 307 Cumulative effect of change in accounting - net of income taxes (a) -- (15) -- Net income $ 199 $ 265 $ 307 (a) We recorded a $15 million after-tax charge in 2001 for the cumulative effect of a change in accounting for derivatives related to the adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." See Note 16. See Note 15 for additional financial information regarding our business segments. 27 RESULTS OF OPERATIONS GENERAL Throughout the following explanations of our results of operations, we refer to "gross margin." With respect to our regulated electricity segment and marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. 2002 COMPARED WITH 2001 Our net income for the year ended December 31, 2002 was $199 million compared with $265 million for the prior year. In 2001, we recognized a $15 million after-tax charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133 (see Note 16). Our income before accounting change for the year ended December 31, 2002 was $199 million compared with $281 million for the prior year. The period-to-period comparison was lower due to reduced marketing and trading segment gross margin due to our transfer of the marketing and trading activities to Pinnacle West in 2001 and severance costs of $34 million in the second half of 2002 relating to voluntary workforce reductions. These decreases were partially offset by increased earnings contributions from our regulated electricity activities, reflecting lower replacement power costs for power plant outages, retail customer growth and higher average usage per customer, and lower purchased power costs related to 2001 generation reliability program (the addition of generating capability to enhance reliability for the summer of 2001). These increases were partially offset by the effects of milder weather, retail electricity price decreases and higher costs for purchased power and gas due to higher hedged gas and power prices. For additional details, see the following discussion. 28 The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
Increase (Decrease) ---------- Regulated electricity segment gross margin: Lower replacement power costs for plant outages due to lower market prices and fewer unplanned outages $ 127 Increased purchased power and fuel costs due to higher hedged gas and power prices, partially offset by improved hedge management, net of mark-to-market reversals (24) Lower purchased power and fuel costs related to the 2001 generation reliability program 30 Higher retail sales volumes due to customer growth and higher average usage, excluding weather effects 38 2001 charges related to purchased power contracts with Enron and its affiliates 13 Retail price reductions effective July 1, 2001 and July 1, 2002 (28) Effects of milder weather on retail sales (27) ---------- Net increase in regulated electricity segment gross margin 129 ---------- Marketing and trading segment gross margin: Decrease in generation sales other than Native Load due to lower market prices partially offset by higher sales volumes (78) Decrease in marketing and trading segment margin resulting from our transfer of marketing and trading activities to Pinnacle West in 2001 (156) ---------- Net decrease in marketing and trading segment gross margin (234) ---------- Net decrease in regulated electricity and marketing and trading segments' gross margins (105) Higher operations and maintenance expense related to 2002 severance costs of approximately $34 million, partially offset by lower generation reliability costs (30) Lower depreciation and amortization expense primarily related to lower regulatory asset amortization 21 Higher taxes other than income taxes (7) Lower other income primarily due to a 2001 insurance recovery of environmental remediation costs (15) Higher net interest expense primarily due to higher debt balances and lower capitalized interest (3) Miscellaneous factors, net 2 ---------- Net decrease in income before income taxes (137) Lower income taxes primarily due to lower income 56 ---------- Net decrease in income before accounting change $ (81) ==========
REGULATED ELECTRICITY SEGMENT GROSS MARGIN Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $503 million lower in the year ended December 31, 2002, compared with the prior year as a result of: 29 * decreased revenues related to traditional wholesale sales as a result of lower sales volumes and lower prices ($64 million); * decreased revenues related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes ($421 million); * decreased retail revenues related to milder weather ($60 million); * increased retail revenues related to customer growth and higher average usage, excluding weather effects ($69 million); * decreased retail revenues related to reductions in retail electricity prices ($28 million); and * other miscellaneous factors ($1 million net increase). Regulated electricity segment purchased power and fuel costs were $632 million lower in the year ended December 31, 2002, compared with the prior year as a result of: * decreased costs related to traditional wholesale sales as a result of lower sales volumes and lower prices ($64 million); * decreased costs related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes ($426 million); * increased costs related to higher prices for hedged natural gas and purchased power, net of mark-to-market reversals ($29 million); * lower purchased power costs related to the 2001 generation reliability program ($30 million); * decreased costs related to the effects of milder weather on retail sales ($33 million); * increased costs related to retail sales growth, excluding weather effects ($31 million); * charges in 2001 related to purchased power contracts with Enron and its affiliates ($13 million net decrease); * decreased replacement power costs for power plant outages due to lower market prices and fewer unplanned outages ($127 million); and * other miscellaneous factors ($1 million net increase). MARKETING AND TRADING SEGMENT GROSS MARGIN Marketing and trading segment revenues were $515 million lower in the year ended December 31, 2002, compared with the prior year as a result of: * decreased revenues from generation sales other than Native Load primarily due to lower market prices partially offset by higher sales volumes ($128 million); and * lower marketing and trading revenues as a result of our transfer of marketing and trading activities to Pinnacle West in 2001 ($387 million). Marketing and trading segment purchased power and fuel costs were $281 million lower in the year ended December 31, 2002, compared with the prior year as a result of: * decreased fuel costs related to generation sales other than Native Load primarily because of lower natural gas prices partially offset by higher sales volumes ($50 million); and 30 * lower marketing and trading purchased power and fuel costs as a result of our transfer of marketing and trading activities to Pinnacle West in 2001 ($231 million). OTHER INCOME STATEMENT ITEMS The increase in operations and maintenance expense of $30 million was primarily due to severance costs of $34 million related to a 2002 voluntary workforce reduction, partially offset by lower costs related to generation reliability, plant outages and maintenance costs. The increase in taxes other than income taxes of $7 million is primarily due to increased property taxes on higher property balances. Other income decreased $15 million primarily due to an insurance recovery recorded in 2001 related to environmental remediation costs and other costs (see Note 17). The decrease in depreciation and amortization expense of $21 million primarily related to lower regulatory asset amortization, in accordance with the 1999 Settlement Agreement, partially offset by increased depreciation and amortization on higher property, plant and equipment balances. 2001 COMPARED WITH 2000 Our net income for the year ended December 31, 2001 was $265 million compared with $307 million for the year ended December 31, 2000. In 2001, we recognized a $15 million after-tax charge in net income as a cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133 (see Note 16). Income before accounting change for the year ended December 31, 2001 was $281 million compared with $307 million for the year ended December 31, 2000. The year-to-year comparison benefited from strong marketing and trading results and retail customer growth. These factors were partially offset by higher purchased power and fuel costs, due in part to increased power plant maintenance; generation reliability measures; continuing retail electricity price decreases; and a charge related to Enron and its affiliates. For additional details, see the following discussion. The major factors that increased (decreased) income before accounting change were as follows (dollars in millions): 31
Increase (Decrease) ---------- Regulated electricity segment gross margin: Higher replacement power costs for plant outages related to higher market prices $ (70) Retail price reductions effective July 1, 2001 and July 1, 2000 (27) Charges related to purchased power contracts with Enron and its affiliates (a) (13)(a) Higher purchased power costs related to the 2001 generation reliability program (30) Miscellaneous revenues 1 ---------- Net decrease in regulated electricity segment gross margin (139) ---------- Marketing and trading segment gross margin: Increase from generation sales other than Native Load due to higher market prices 25 Higher realized wholesale margin net of related mark-to-market reversals 11 Increase in mark-to-market value related to future periods 71 ---------- Net increase in marketing and trading segment gross margin 107 ---------- Net increase in regulated electricity and marketing and trading segments' gross margins (32) Higher operations and maintenance expense related to the 2001 generation reliability program (12) Higher operations and maintenance expense related primarily to employee benefits, plant outage and maintenance and other costs (23) Lower net interest expense primarily due to higher capitalized interest 15 Higher other income primarily due to a 2001 insurance recovery of environmental remediation costs 11 Miscellaneous factors, net 2 ---------- Net decrease in income before income taxes (39) Lower income taxes primarily due to lower income 13 ---------- Net decrease in income before accounting change $ (26) ==========
(a) We recorded charges totaling $13 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. REGULATED ELECTRICITY SEGMENT GROSS MARGIN Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $23 million higher in the year ended December 31, 2001 compared with the prior year as a result of: * decreased revenues related to other wholesale sales and miscellaneous revenues as a result of lower sales volumes ($28 million); * increased retail revenues primarily related to higher sales volumes primarily due to customer growth ($78 million); and 32 * decreased retail revenues related to reductions in retail electricity prices ($27 million). Regulated electricity segment purchased power and fuel costs were $162 million higher in the year ended December 31, 2001 compared with the prior year as a result of: * decreased costs related to other wholesale sales as a result of lower volumes ($29 million); * higher replacement power costs primarily due to higher market prices and increased plant outages ($70 million), including costs of $12 million related to a Palo Verde outage extension to replace fuel control element assemblies; * higher purchase power costs related to the 2001 generation reliability program ($30 million); * higher costs related to retail sales volumes due to customer growth ($78 million); and * charges related to purchased power contracts with Enron and its affiliates ($13 million). MARKETING AND TRADING SEGMENT GROSS MARGIN Marketing and trading segment revenues were $154 million higher in the year ended December 31, 2001 compared with the prior year as a result of: * increased revenues related to generation sales other than Native Load as a result of higher average market prices ($32 million); * increased realized wholesale revenues net of related mark-to-market reversals primarily due to more transactions ($40 million); * increased prior period mark-to-market value for losses transferred to realized margin in current period ($11 million); and * increased mark-to-market value for future periods primarily as a result of more forward sales volumes ($71 million). Marketing and trading segment purchased power and fuel costs were $47 million higher in the year ended December 31, 2001 compared with the prior year as a result of: * increased fuel costs related to generation sales other than Native Load as a result of higher fuel prices ($7 million); and * increased purchased power and fuel costs net of related mark-to-market reversals primarily due to more transactions ($40 million). OTHER INCOME STATEMENT ITEMS The increase in operations and maintenance expenses of $35 million primarily related to the 2001 generation reliability program (the addition of generating capability to enhance reliability for the summer of 2001) ($12 million) and increased employee benefit costs, plant outage and maintenance and other costs ($23 million). 33 Interest expense decreased by $15 million primarily because of lower interest rates and increased capitalized interest resulting from higher construction project balances. Net other income increased $11 million primarily because of insurance recovery of environmental remediation costs (see Note 17). See "Regulatory Matters - 1999 Settlement Agreement" in Note 3 for a discussion of the 1999 Settlement Agreement under which, among other things, we agreed to five annual retail electricity price reductions of 1.5%, with the last decrease to take effect July 1, 2003. LIQUIDITY AND CAPITAL RESOURCES CAPITAL NEEDS AND RESOURCES CAPITAL EXPENDITURE REQUIREMENTS The following table summarizes the actual capital expenditures for the year ended December 31, 2002 and estimated capital expenditures for the next three years. CAPITAL EXPENDITURES (dollars in millions) (Actual) (Estimated) -------- ---------------------------- 2002 2003 2004 2005 ------ ------ ------ ------ Delivery $ 369 $ 273 $ 275 $ 329 Generation (a) 132 123 99 164 Other (b) -- 5 5 5 ------ ------ ------ ------ Total $ 501 $ 401 $ 379 $ 498 ====== ====== ====== ====== (a) As discussed below under "Factors Affecting Our Financial Outlook," as part of our 2003 general rate case, we intend to seek rate base treatment of certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3). (b) The other amounts relate to capital expenditures for our marketing and trading segment. These costs were in the parent company for 2002. Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. 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. In addition, we began several major transmission projects in 2001. These projects are periodic in nature and are driven by strong regional customer growth. We expect to spend about $105 million on major transmission projects during the 2003 to 2005 time frame, and these amounts are included in "Delivery" in the table above. 34 Generation capital expenditures are comprised of various improvements for our 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 contains nuclear fuel expenditures of approximately $30 million annually for 2003 to 2005. Replacement of the steam generators in Palo Verde Unit 2 is presently scheduled for completion during the fall outage of 2003. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. We expect that these generators will be installed in Units 1 and 3 in the 2005 to 2008 time frame. Our portion of steam generator expenditures for Units 1, 2 and 3 is approximately $145 million, which will be spent from 2003 through 2008. In 2003 through 2005, $94 million of the costs are included in the generation capital expenditures table above and would be funded with internally-generated cash or external financings. CONTRACTUAL OBLIGATIONS Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See "Factors Affecting Our Financial Outlook - Regulatory Matters" below and Note 3 for discussion of the $500 million financing arrangement between us and Pinnacle West Energy recently approved by the ACC. On November 22, 2002 the ACC approved our request (Interim Financing Application), to permit us to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West's short-term debt, subject to certain conditions. As of December 31, 2002, there were no borrowings outstanding under the inter-affiliate financing arrangement. See the table below for our contractual requirements, including our debt repayment obligations. The table does not take into account any funds that we intend to lend to Pinnacle West Energy or Pinnacle West consistent with the foregoing financing arrangements. We pay for our capital requirements with cash from operations and, to the extent necessary, external financings. We have historically paid for our dividends to Pinnacle West with cash from operations. In 2002, we issued $375 million in long-term debt, refinanced $90 million in long-term debt and redeemed approximately $247 million in long-term debt (see Note 6). On April 7, 2003, we will redeem $33 million of our first mortgage bonds. Our outstanding debt was approximately $2.2 billion at December 31, 2002. At December 31, 2002, we had credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2002, we had no outstanding commercial paper or bank borrowings. Although provisions in our first mortgage bond indenture, articles of incorporation and ACC financing orders establish maximum amounts of additional first mortgage bonds, debt and preferred stock that we may issue, we do not 35 expect any of these provisions to limit our ability to meet our capital requirements. We are part of a multi-employer pension plan sponsored by Pinnacle West. Pinnacle West contributes 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 the pension obligation. Pinnacle West elected to contribute cash to the pension plan in each of the last five years; the minimum required contributions during each of those years was zero. Specifically, Pinnacle West contributed $27 million for 2002, $24 million for 2001, $44 million for 2000, $25 million for 1999 and $14 million for 1998. We fund our share of the pension contribution. We represent approximately 90% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. Pinnacle West currently forecasts a pension contribution in 2003 of approximately $50 million, all or part of which may be required. If the fund performance continues to decline as a result of a continued decline in equity markets, larger contributions may be required in future years. As a result of a change in IRS guidance, we claimed a tax deduction related to a tax accounting method change on the 2001 Pinnacle West federal consolidated income tax return. The accelerated deduction has resulted in a $200 million reduction in the current income tax liability. In 2002, we received an income tax refund of approximately $115 million related to the 2001 Pinnacle West federal consolidated income tax return. The following table summarizes actual contractual requirements for the year ended December 31, 2002 and estimated contractual commitments for the next five years and thereafter (dollars in millions):
Actual Estimated ------ --------------------------------------------------- There- 2002 2003 2004 2005 2006 2007 after ------ ------ ------ ------ ------ ------ ------ Long-term debt payments $ 337 $ -- $ 205 $ 400 $ 84 $ -- $1,518 Capital lease payments -- 4 3 3 3 2 5 Operating lease payments 60 59 59 59 59 59 456 Fuel and purchase power commitments 307 135 82 28 31 17 162 ------ ------ ------ ------ ------ ------ ------ Total contractual commitments $ 704 $ 198 $ 349 $ 490 $ 177 $ 78 $2,141 ====== ====== ====== ====== ====== ====== ======
OFF-BALANCE SHEET ARRANGEMENTS In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities." FIN No. 46 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. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003. 36 In 1986, we 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. See Note 8 for further information about the sale-leaseback transactions. Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to consolidate the Palo Verde SPEs. However, we continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements. We are exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that we do 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), we 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 December 31, 2002, we would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million. CREDIT RATINGS The ratings of our securities as of March 28, 2003 are shown below and are considered "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 our securities and serve to increase our cost of and access to capital. Moody's Standard & Poor's Fitch ------- ----------------- ----- Senior secured A3 A- A- Senior unsecured Baa1 BBB BBB+ Secured lease obligation bonds Baa2 BBB BBB Commercial paper P-2 A-2 F-2 On November 4, 2002 Standard & Poor's affirmed our debt ratings in the above chart. On that same date, Standard & Poor's lowered our corporate credit rating from BBB+ to BBB. Standard & Poor's assigned a stable outlook to the ratings. All of our credit ratings remain investment grade. In December 2002, Fitch placed certain of our debt on Ratings Watch Negative. The ratings watch affects all of our debt ratings with the exception of our commercial paper rating. On December 31, 2002, Moody's affirmed the ratings set forth above. DEBT PROVISIONS Our significant debt covenants include a debt-to-total-capitalization ratio and an interest coverage test. We are in compliance with such covenants and anticipate that we will continue to meet all the significant covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65%. 37 At December 31, 2002, our ratio is approximately 48%. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements. The coverage is approximately 5 times for our bank agreements and 15 times for our mortgage indenture. 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. Our financing agreements do not 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, we may be subject to increased interest costs under certain financing agreements. All of our bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these bank agreements if we were to default under other agreements. Our credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects. 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. We consider the following accounting policies to be our most critical because of uncertainties, judgments and complexities of the underlying accounting standards and operations involved. * Regulatory Accounting - Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. * Pensions and Other Postretirement Benefit Accounting - Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term. * Derivative Accounting - Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in other comprehensive income. 38 * Mark-to-Market Accounting - The market value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. See the discussion below for further details on our critical accounting policies. REGULATORY ACCOUNTING For our regulated operations, we prepare our financial statements in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections of costs not likely to be incurred. We are required to discontinue applying SFAS No. 71 when deregulatory legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated. In 1999, we discontinued the application of SFAS No. 71 for our generation operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a discussion of the 1999 Settlement Agreement. In 2002, the ACC directed us not to transfer our generation assets, as previously required by the 1999 Settlement Agreement (see "Track A Order" in Note 3). Accordingly, we now consider our generation to be cost-based, rate-regulated and subject to the requirements of SFAS No. 71. The impact of this change was immaterial to our financial statements. Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings. We had $241 million of regulatory assets included on the Balance Sheets at December 31, 2002. See Notes 1 and 3 for more information. PENSIONS AND OTHER POSTRETIREMENT BENEFIT ACCOUNTING Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for employees of Pinnacle West and its subsidiaries. In 2002, we represented 87% of the total costs of this plan. Our reported costs of providing defined pension and other postretirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension and other postretirement benefit costs, for example, are impacted by actual employee demographics (including age, compensation levels and employment periods), the level of contributions we make to the plans and earnings on plan assets. Changes made to the provisions of the plans may also impact current and future pension 39 and other postretirement benefit costs. Pension and other postretirement benefit costs may also be significantly affected by changes in key actuarial assumptions, including the expected long-term rate of return on plan assets and the discount rates used in determining the projected benefit obligation and pension and other postretirement benefit costs. Pinnacle West's pension and other postretirement plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension and other postretirement benefit costs in future periods. Likewise, changes in assumptions regarding current discount rates and the expected long-term rate of return on plan assets could also increase or decrease recorded pension and other postretirement benefit costs. We account for our defined benefit pension plans in accordance with SFAS No. 87, "Employers' Accounting for Pensions," which requires amounts recognized in our financial statements to be determined on an actuarial basis. Changes in pension obligations associated with these factors may not be immediately recognized as pension costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. The following chart reflects the sensitivities associated with a one percent increase or decrease in certain actuarial assumptions related to our defined benefit pension plans. Each sensitivity below reflects the impact of changing only that assumption. The chart shows the increase (decrease) each change in assumption would have on the 2002 Pinnacle West projected benefit obligation, the 2002 reported pension liability on the Pinnacle West Consolidated Balance Sheets and the 2002 reported annual pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Pinnacle West Consolidated Statements of Income (dollars in millions). In 2002, we represented 87% of the total cost of the plans. Increase/(Decrease) - -------------------------------------------------------------------------------- Impact on Impact on Impact on Projected Benefit Pension Pension Actuarial Assumption Obligation Liability Expense - -------------------------------------------------------------------------------- Discount rate: Increase 1% $(143) $(107) $ (4) Decrease 1% 177 130 9 Expected long-term rate of return on plan assets: Increase 1% -- -- (4) Decrease 1% -- -- 4 At the end of each year, we determine the discount rate to be used to calculate the present value of plan liabilities. The discount rate is an estimate of the current interest rate at which the pension liabilities could be effectively settled at the end of the year. The discount rate is selected by comparison to current yields on high-quality, long-term bonds. We changed our discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31, 2002. 40 In 2002, we assumed that the expected long-term rate of return on plan assets would be 10%. However, the plan assets have earned a rate of return substantially less than 10% in the last three years due to sharp declines in the equity markets. For 2003, we decreased our expected long-term rate of return on plan assets to 9%, as a result of continued declines in general equity and bond market returns. The following chart reflects the sensitivities associated with a one percent increase or decrease in certain actuarial assumptions related to our other postretirement benefit plans. Each sensitivity below reflects the impact of changing only that assumption. The chart shows the increase (decrease) each change in assumption would have on the 2002 Pinnacle West accumulated other postretirement benefit obligation and the 2002 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on the Pinnacle West Consolidated Statements of Income (dollars in millions). In 2002, we represented 87% of the total cost of this plan. Increase/(Decrease) - -------------------------------------------------------------------------------- Impact on Accumulated Impact on Other Postretirement Benefit Postretirement Actuarial Assumption Obligation Benefit Expense - -------------------------------------------------------------------------------- Discount rate: Increase 1% $ (38) $ (2) Decrease 1% 43 2 Health care cost trend rate (a): Increase 1% 54 5 Decrease 1% (43) (4) Expected long-term rate of return on plan assets - pretax: Increase 1% -- (1) Decrease 1% -- 1 (a) This assumes a 1% change in the initial and ultimate health care cost trend rate. The discount rate is selected by comparison to current yields on high-quality, long-term bonds. We changed our discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31, 2002. In selecting our health care cost trend rate, we consider past performance and forecasts of health care costs. In 2002, we increased our initial health care cost trend rate to 8% from 7% based on an analysis of our actual plan experience. We also assume an ultimate health care cost trend rate of 5% is reached in 2007. In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. The market value of the plan assets has been affected by sharp declines in the equity markets. For 2003, we decreased our expected long-term rate of return on plan assets from 10% to 9%, as a result of continued declines in general equity and bond market returns. 41 Pension and other postretirement benefit costs and cash funding requirements may increase in future years without a substantial recovery in the equity markets. Due to the actual investment performance of the pension and other postretirement benefit funds and the changes in the actuarial assumptions discussed above, we expect an increase of approximately $29 million before income taxes in 2003 expense over 2002. See Note 7 for further details about our pension and other postretirement benefit plans. DERIVATIVE ACCOUNTING We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we enter into derivative transactions 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 commodities. 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. We examine contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133 scope exception, we account for the contract on an accrual basis with associated revenues and costs recorded at the time the contracted commodities are delivered or received. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. For contracts that qualify as a derivative and do not meet a SFAS No. 133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. Changes in the fair value of the effective portion of derivative instruments that qualify for cash flow hedge accounting treatment are recognized as either an asset or liability and in common stock equity (as a component of accumulated other comprehensive income (loss)). Gains and losses related to derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If a contract does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period through mark-to-market accounting. On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the accounting definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See "Other Accounting Matters - Accounting for Derivative and Trading Activities" below for 42 details on the change in accounting for energy trading contracts. See Note 16 for further discussion on derivative accounting. MARK-TO-MARKET ACCOUNTING Under mark-to-market accounting, the purchase or sale of energy commodities is reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as assets and liabilities from risk management and trading activities in the Balance Sheets. We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted. When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers. We shape quarterly and calendar year quotes into monthly prices based on historical relationships. For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model. For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged. A credit valuation adjustment is also recorded to represent estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements; expected default experience for the credit rating of the counterparties; and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. See "Factors Affecting Our Financial Outlook - Market Risks - Commodity Price Risk" below and Note 16 for further discussion on credit risk. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our practice is to hedge within timeframes established by the ERMC. 43 OTHER ACCOUNTING MATTERS ACCOUNTING FOR DERIVATIVE AND TRADING ACTIVITIES During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts, and on January 1, 2003 for existing contracts, with early adoption permitted. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. The impact of the guidance was immaterial to our financial statements. EITF 02-3 requires derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Previous guidance under EITF 98-10 permitted physically settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the Statements of Income and restated prior year amounts for all periods presented. Reclassification of such trading activity to a net basis of reporting resulted in reductions in both revenues and purchased power and fuel costs, but did not have any impact on our financial condition, results of operations or cash flows. In 2001, we adopted SFAS No. 133 and recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income), both as a cumulative effect of a change in accounting for derivatives. See Notes 1 and 16 for further information on accounting for derivatives under SFAS No. 133. ASSET RETIREMENT OBLIGATIONS On January 1, 2003 we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires the fair value of asset retirement obligations to be recorded as a liability, along with an offsetting plant asset, when the obligation is incurred. Accretion of the liability due to the passage of time will be an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. (See Note 1 for more information regarding our previous accounting for removal costs.) We determined that we have asset retirement obligations for our nuclear facilities (nuclear decommissioning) and certain other generation, transmission and distribution assets. On January 1, 2003 we recorded a liability of $219 million for our asset retirement obligations including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a regulatory 44 liability of $40 million for our asset retirement obligations related to our regulated utility. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. STOCK-BASED COMPENSATION 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." We recorded approximately $333,000 in stock option expense before income taxes in our Statements of Income for 2002. See Notes 1 and 14 for further information on the impacts of adopting the fair value method provided in SFAS No. 123. VARIABLE INTEREST ENTITIES See "Liquidity and Capital Resources - Off-Balance Sheet Arrangements" and Note 18 for discussion of VIEs. OTHER See Note 2 for discussion of other new accounting standards that are not expected to have a material impact on the Company. FACTORS AFFECTING OUR FINANCIAL OUTLOOK REGULATORY MATTERS GENERAL On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among us and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, we were required to transfer all of our competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, we had been addressing the legal and regulatory requirements necessary to complete the transfer of our generation assets to Pinnacle West Energy on or before that date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed us not to transfer our generation assets to Pinnacle West Energy. 1999 SETTLEMENT AGREEMENT The 1999 Settlement Agreement has affected, and will affect, our results of operations. As part of the 1999 Settlement Agreement, we agreed to reduce retail electricity prices for standard-offer, full-service customers with loads less than three megawatts in a series of annual decreases of 1.5% on July 1, 1999 through July 1, 2003, for a total of 7.5%. For customers with loads three 45 megawatts or greater, standard-offer rates were reduced in annual increments totaling 5% in the years 1999 through 2002. The 1999 Settlement Agreement also removed, as a regulatory disallowance, $234 million before income taxes ($183 million net present value) from ongoing regulatory cash flows. We recorded this regulatory disallowance as a net reduction of regulatory assets and reported it as a $140 million after-tax extraordinary charge on the 1999 Statement of Income. As discussed under "General Rate Case" below, we intend to seek recovery of this $234 million write-off in our next general rate case. Prior to the 1999 Settlement Agreement, the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions): 1999 2000 2001 2002 2003 2004 Total ----- ----- ----- ----- ----- ----- ----- $ 164 $ 158 $ 145 $ 115 $ 86 $ 18 $ 686 See Note 3 for additional information regarding the 1999 Settlement Agreement. FINANCING APPLICATION On September 16, 2002, we filed an application with the ACC requesting the ACC to allow us to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to Pinnacle West; to guarantee up to $500 million of Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to exceed $500 million in the aggregate. In our application, we stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between us and Pinnacle West Energy under different regulatory regimes results in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing that Pinnacle West provided to fund the construction of Pinnacle West Energy generation assets or from effectively competing in the wholesale markets. On March 27, 2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. See "ACC Applications" in Note 3 for further discussion of the approval and related conditions. TRACK A ORDER On September 10, 2002, the ACC issued the Track A Order. See "Track A Order" in Note 3. COMPETITIVE PROCUREMENT PROCESS On September 10, 2002, the ACC issued an order that, among other things, established a requirement that we competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order, which documented the decision made by the ACC at its open meeting on February 27, 2003 addressing this requirement. Under the ACC's Track B Order, we will be required to solicit 46 bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, we will be required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in our retail load and our retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets." The order recognizes our right to reject any bids that are unreasonable, uneconomical or unreliable. We expect to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply our electricity requirements. See "Track B Order" in Note 3 for additional information. GENERAL RATE CASE As required by the 1999 Settlement Agreement, on or before June 30, 2003, we will file a general rate case with the ACC. In this rate case, we will update our cost of service and rate design. In addition, we expect to seek: * rate base treatment of certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3); * recovery of the $234 million pretax asset write-off recorded by us as part of the 1999 Settlement Agreement ($140 million extraordinary charge recorded on the 1999 Statement of Income); and * recovery of costs incurred by us in preparation for the previously required transfer of generation assets to Pinnacle West Energy. We assume that the ACC will make a decision in this general rate case by the end of 2004. WHOLESALE POWER MARKET CONDITIONS The marketing and trading division, which was moved to us in early 2003 for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting our transfer of generating assets to Pinnacle West Energy, focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer demand. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. Earnings contributions from Pinnacle West's marketing and trading division were lower in 2002 compared to 2001 due to weak wholesale power market conditions in the western United States, which included a lack of market liquidity, fewer creditworthy counterparties, lower wholesale market prices and resulting decreases in sales volumes. Our 2003 earnings will be affected by the strength (or weakness) of the wholesale power market. 47 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 bulk 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. CUSTOMER GROWTH Customer growth in our service territory averaged about 3.6% a year for the three years 2000 through 2002; we currently expect customer growth to average about 3.5 % per year from 2003 to 2005. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in 2003 through 2005, before the retail effects of weather variations. The customer growth and sales growth referred to in this paragraph applies to energy delivery customers. As previously noted, under the 1999 Settlement Agreement, we agreed to retail electricity price reductions of 1.5% annually through July 1, 2003 (see Note 3). 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, our power plant performance, prevailing market prices and our hedging program for managing such costs. OPERATIONS AND MAINTENANCE EXPENSES Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors. In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $34 million before taxes in voluntary severance costs in the second half of 2002. In addition, we are expecting to produce annual operating expense savings of approximately $30 million beginning in 2003 as a result of this workforce reduction. DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property and changes in regulatory asset amortization. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions): 1999 2000 2001 2002 2003 2004 Total ----- ----- ----- ----- ----- ----- ----- $ 164 $ 158 $ 145 $ 115 $ 86 $ 18 $ 686 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 was 9.7% of assessed value for 2002 and 9.3% for 2001. We expect property taxes to increase primarily due to 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 recording capitalized interest on a project when it is placed in commercial operation. Interest expense is affected by interest rates on variable-rate debt. We are continuing to evaluate our construction program. 48 RETAIL COMPETITION The regulatory developments and legal challenges to the Rules discussed in Note 3 have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory. 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. MARKET RISKS Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by the nuclear decommissioning trust fund and the pension plans. INTEREST RATE AND EQUITY RISK Our major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our pension plan (see Note 7) and nuclear decommissioning trust fund (see Note 11). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan and nuclear decommissioning fund also have risks associated with changing market values of equity investments. Pension and nuclear decommissioning costs are recovered in regulated electricity prices. See "Critical Accounting Policies - Pension and Other Postretirement Benefit Accounting" for a sensitivity analysis on the long-term rate of return on plan assets. The tables below present contractual balances of our long-term debt and commercial paper at the expected maturity dates as well as the fair value of those instruments on December 31, 2002 and 2001. The interest rates presented in the tables below represent the weighted average interest rates for the years ended December 31, 2002 and 2001. 49 Expected Maturity/Principal Repayment December 31, 2002 (dollars in thousands)
Variable-Rate Fixed-Rate Short-Term Debt Long-Term Debt Long-Term Debt ----------------------- ----------------------- ----------------------- Interest Interest Interest Rates Amount Rates Amount Rates Amount ---------- ---------- ---------- ---------- ---------- ---------- 2003 $ -- $ -- 5.86% $ 3,503 2004 -- -- 6.16% 208,300 2005 -- -- 7.27% 403,300 2006 -- -- 6.72% 86,517 2007 -- -- 5.78% 2,227 Years thereafter -- 3.17% 386,860 6.08% 1,136,473 ---------- ---------- ---------- Total $ -- $ 386,860 $1,840,320 ========== ========== ========== Fair Value $ -- $ 386,860 $1,937,244 ========== ========== ==========
Expected Maturity/Principal Repayment December 31, 2001 (dollars in thousands)
Variable-Rate Fixed-Rate Short-Term Debt Long-Term Debt Long-Term Debt ----------------------- ----------------------- ----------------------- Interest Interest Interest Rates Amount Rates Amount Rates Amount ---------- ---------- ---------- ---------- ---------- ---------- 2002 4.72% $ 171,162 $ -- 8.10% $ 125,451 2003 -- -- -- 6.18% 337 2004 -- -- -- 6.08% 205,185 2005 -- -- -- 7.59% 400,185 2006 -- -- -- 6.77% 83,880 Years thereafter -- -- 2.60% 476,860 6.73% 787,894 ---------- ---------- ---------- Total $ 171,162 $ 476,860 $1,602,932 ========== ========== ========== Fair Value $ 171,162 $ 476,860 $1,621,937 ========== ========== ==========
COMMODITY PRICE RISK We are exposed to the impact of market fluctuations 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 commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. The ERMC, consisting of senior officers, 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 enter into derivative transactions to 50 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 commodities. 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. Prior to October 1, 2002, we accounted for our energy trading contracts at fair value in accordance with EITF 98-10. On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See Note 16 for details on the change in accounting for energy trading contracts and further discussion regarding derivative accounting. Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Balance Sheets. For non-trading derivative instruments that qualify for hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of accumulated other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings. Derivatives associated with trading activities are adjusted to fair value through income. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. Our assets and liabilities from risk management and trading activities are presented in two categories consistent with our business segments: * System - our regulated electricity business segment, which consists of non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements; and * Marketing and Trading - our non-regulated, competitive business segment, which includes both non-trading and trading derivative instruments. The following tables show the changes in mark-to-market of our system and marketing and trading derivative positions in 2002 and 2001 (dollars in millions): 51 Marketing and System Trading ---------- ---------- Mark-to-market of net positions at December 31, 2001 $ (107) $ -- Change in mark-to-market losses for future period deliveries (22) -- Changes in cash flow hedges recorded in OCI 64 -- Ineffective portion of changes in fair value recorded in earnings 8 -- Mark-to-market losses realized during the year 7 -- ---------- ---------- Mark-to-market of net positions at December 31, 2002 $ (50) $ -- ========== ========== Marketing and System Trading ---------- ---------- Mark-to-market of net positions at December 31, 2000 $ -- $ 12 Cumulative effect adjustment due to adoption of SFAS No. 133 95 -- Change in mark-to-market (losses)/gains for future period deliveries (12) 85 Changes in cash flow hedges recorded in OCI (166) -- Ineffective portion of changes in fair value recorded in earnings (6) -- Mark-to-market (gains)/losses realized during the year (18) 7 Transfer of marketing and trading balance to Pinnacle West marketing and trading -- (104) ---------- ---------- Mark-to-market of net positions at December 31, 2001 $ (107) $ -- ========== ========== As of December 31, 2002, a hypothetical adverse price movement of 10% in the market price of our risk management and trading assets and liabilities would have decreased the fair market value of these contracts by approximately $16 million, compared to a $23 million decrease that would have been realized as of December 31, 2001. A hypothetical favorable price movement of 10% would have increased the fair market value of these contracts by approximately $18 million, compared to a $23 million increase that would have been realized as of December 31, 2001. These contracts are hedges of our forecasted purchases of natural gas. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. 52 CREDIT RISK We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure related to our counterparties. Despite the fact that the great majority of trading counterparties 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 earnings for a given period. Counterparties in the portfolio consist principally of 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. 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. See "Critical Accounting Policies - Mark-to-Market Accounting" above for a discussion of our credit valuation adjustment policy. RISK FACTORS Exhibit 99.3, which is hereby incorporated by reference, contains a discussion of risk factors affecting the Company. FORWARD-LOOKING STATEMENTS The above discussion 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 laws. 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. These factors include the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition; the outcome of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including price caps and other market constraints imposed by the FERC; regional economic and market conditions, including the California energy situation and completion of generation construction in the region, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital and access to capital markets; weather variations affecting local and regional customer energy usage; the effect of conservation programs on energy usage; power plant performance; our ability to compete successfully outside traditional regulated markets (including the wholesale market); our ability to manage our marketing and trading activities and the use of derivative contracts in our business; technological developments in the electric industry; the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommissioning trust funds; and other uncertainties, all of which are difficult to predict and many of which are beyond our control. 53 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See "Factors Affecting Our Financial Outlook - Market Risks" in Item 7 for a discussion of quantitative and qualitative disclosures about market risk. 54 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS Independent Auditors' Report................................................. 56 Statements of Income for 2002, 2001 and 2000................................. 57 Balance Sheets as of December 31, 2002 and 2001.............................. 58 Statements of Cash Flows for 2002, 2001 and 2000............................. 60 Statements of Changes in Common Stock Equity for 2002, 2001 and 2000......... 61 Notes to Financial Statements................................................ 62 Financial Statement Schedule for 2002, 2001 and 2000 Schedule II - Reserve for 2002, 2001 and 2000....................................................110 See Note 12 for the selected quarterly financial data required to be presented in this Item. 55 INDEPENDENT AUDITORS' REPORT To the Board of Directors and the Stockholder of Arizona Public Service Company Phoenix, Arizona We have audited the accompanying balance sheets of Arizona Public Service Company (the "Company") as of December 31, 2002 and 2001 and the related statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedule listed in the Index. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Arizona Public Service Company at December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 16 to the financial statements, in 2001 Arizona Public Service Company changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." DELOITTE & TOUCHE LLP Phoenix, Arizona February 3, 2003 (March 14, 26 and 27, 2003 as to Note 20) 56 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, -------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ Electric Operating Revenues: Regulated electricity segment $ 2,059,339 $ 2,562,088 $ 2,538,750 Marketing and trading segment 34,054 549,240 395,392 ------------ ------------ ------------ Total 2,093,393 3,111,328 2,934,142 ------------ ------------ ------------ Purchased Power and Fuel Costs: Regulated electricity segment 595,368 1,227,188 1,065,596 Marketing and trading segment 32,662 313,991 267,032 ------------ ------------ ------------ Total 628,030 1,541,179 1,332,628 ------------ ------------ ------------ Operating Revenues less Purchased Power and Fuel Costs 1,465,363 1,570,149 1,601,514 ------------ ------------ ------------ Other Operating Expenses: Operations and maintenance 495,845 465,561 430,092 Depreciation and amortization 399,640 420,893 425,479 Income taxes (Note 4) 132,953 183,640 199,977 Other taxes 107,925 101,077 99,730 ------------ ------------ ------------ Total 1,136,363 1,171,171 1,155,278 ------------ ------------ ------------ Operating Income 329,000 398,978 446,236 ------------ ------------ ------------ Other Income (Deductions): Other income (Note 17) 5,149 20,207 9,690 Other expense (Note 17) (19,338) (20,790) (20,547) Income taxes (Note 4) 6,148 504 4,312 ------------ ------------ ------------ Total (8,041) (79) (6,545) ------------ ------------ ------------ Income Before Interest Deduction 320,959 398,899 439,691 ------------ ------------ ------------ Interest Deductions: Interest on long-term debt 128,462 126,118 134,431 Interest on short-term borrowings 5,416 4,407 7,455 Debt discount, premium and expense 2,888 2,650 2,105 Capitalized interest (15,150) (14,964) (10,894) ------------ ------------ ------------ Total 121,616 118,211 133,097 ------------ ------------ ------------ Income Before Accounting Change 199,343 280,688 306,594 Cumulative Effect of Change in Accounting for Derivatives - net of income taxes of $9,892 -- (15,201) -- ------------ ------------ ------------ Net Income $ 199,343 $ 265,487 $ 306,594 ============ ============ ============
See Notes to Financial Statements. 57 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS ASSETS
DECEMBER 31, ---------------------------- 2002 2001 ------------ ------------ (DOLLARS IN THOUSANDS) Utility Plant (Notes 1, 8 and 9) Electric plant in service and held for future use $ 8,299,131 $ 7,935,206 Less accumulated depreciation and amortization 3,442,571 3,287,333 ------------ ------------ Total 4,856,560 4,647,873 Construction work in progress 329,089 321,305 Intangible assets, net of accumulated amortization (Note 19) 93,259 83,135 Nuclear fuel, net of accumulated amortization of $102,821 and $99,185 7,466 6,933 ------------ ------------ Utility Plant - net 5,286,374 5,059,246 ------------ ------------ Investments and Other Assets Decommissioning trust accounts (Note 11) 194,440 202,036 Assets from risk management and trading activities - long-term 31,622 2,082 Other assets 19,964 76,322 ------------ ------------ Total Investments and Other Assets 246,026 280,440 ------------ ------------ Current Assets: Cash and cash equivalents 42,549 16,821 Accounts receivable: Service customers 136,945 182,749 Other (Note 1) 202,597 55,016 Allowance for doubtful accounts (1,341) (3,349) Accrued utility revenues 72,915 76,131 Materials and supplies (at average cost) 79,985 81,215 Fossil fuel (at average cost) 28,185 27,023 Deferred income taxes (Note 4) 4,094 -- Assets from risk management and trading activities 39,616 10,097 Other 45,361 42,009 ------------ ------------ Total Current Assets 650,906 487,712 ------------ ------------ Deferred Debits: Regulatory assets (Notes 1 and 3) 241,045 342,383 Unamortized debt issue costs 16,696 13,163 Other 80,760 42,789 ------------ ------------ Total Deferred Debits 338,501 398,335 ------------ ------------ Total Assets $ 6,521,807 $ 6,225,733 ============ ============
See Notes to Financial Statements. 58 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS LIABILITIES AND EQUITY
DECEMBER 31, ---------------------------- 2002 2001 ------------ ------------ (DOLLARS IN THOUSANDS) Capitalization: Common stock $ 178,162 $ 178,162 Additional paid-in capital 1,246,804 1,246,804 Retained earnings 819,632 790,289 Accumulated other comprehensive loss: Minimum pension liability adjustment (61,487) (966) Derivative instruments (23,799) (63,599) ------------ ------------ Common stock equity 2,159,312 2,150,690 Long-term debt less current maturities (Note 6) 2,217,340 1,949,074 ------------ ------------ Total Capitalization 4,376,652 4,099,764 ------------ ------------ Current Liabilities: Commercial paper (Note 5) -- 171,162 Current maturities of long-term debt (Note 6) 3,503 125,451 Accounts payable 118,133 98,959 Accrued taxes 82,557 107,595 Accrued interest 42,608 41,043 Customer deposits 39,865 28,664 Deferred income taxes (Note 4) -- 3,244 Liabilities from risk management and trading activities 59,773 21,840 Other 51,820 18,798 ------------ ------------ Total Current Liabilities 398,259 616,756 ------------ ------------ Deferred Credits and Other: Deferred income taxes (Note 4) 1,225,552 1,023,079 Liabilities from risk management and trading activities 36,678 95,159 Unamortized gain - sale of utility plant (Note 8) 59,484 64,060 Customer advances for construction 45,513 69,293 Pension liability (Note 7) 156,442 30,247 Other 223,227 227,375 ------------ ------------ Total Deferred Credits and Other 1,746,896 1,509,213 ------------ ------------ Commitments and Contingencies (Notes 3, 10 and 11) Total Liabilities and Equity $ 6,521,807 $ 6,225,733 ============ ============
See Notes to Financial Statements. 59 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, -------------------------------------------- 2002 2001 2000 ------------ ------------ ------------ (DOLLARS IN THOUSANDS) Cash Flows from Operating Activities: Net income $ 199,343 $ 265,487 $ 306,594 Items not requiring cash: Depreciation and amortization 399,640 420,893 425,479 Nuclear fuel amortization 31,185 28,362 30,083 Deferred income taxes 206,767 (26,516) (65,726) Change in mark-to-market 2,957 (100,030) (11,752) Cumulative effect of change in accounting - net of income taxes -- 15,201 -- Changes in certain current assets and liabilities: Accounts receivable (102,450) 302,283 (209,705) Materials, supplies and fossil fuel 68 (16,867) 475 Other current assets (136) (5,160) (26,682) Accounts payable 15,372 (190,141) 101,558 Accrued taxes (25,038) 1,080 43,657 Accrued interest 1,565 1,555 7,189 Other current liabilities 44,224 (58,361) 101,685 Increase in regulatory assets (11,029) (17,516) (14,138) Change in risk management trading - assets (22,570) 10,730 13,181 Change in customer advances (23,780) 28,599 2,544 Change in pension liability 5,415 (30,346) (18,373) Change in other net long-term assets (18,923) (14,192) 64,998 Change in other net long-term liabilities 1,902 (9,986) (27,396) ------------ ------------ ------------ Net cash provided by operating activities 704,512 605,075 723,671 ------------ ------------ ------------ Cash Flows from Investing Activities: Capital expenditures (490,156) (465,360) (464,368) Capitalized interest (15,150) (14,964) (10,894) Other 44,918 (41,926) (72,189) ------------ ------------ ------------ Net cash used for investing activities (460,388) (522,250) (547,451) ------------ ------------ ------------ Cash Flows from Financing Activities: Issuance of long-term debt 459,926 396,072 300,000 Short-term borrowings (171,162) 89,062 43,800 Dividends paid on common stock (170,000) (170,000) (170,000) Repayment and reacquisition of long-term debt (337,160) (383,747) (354,888) ------------ ------------ ------------ Net cash used for financing activities (218,396) (68,613) (181,088) ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents 25,728 14,212 (4,868) Cash and cash equivalents at beginning of year 16,821 2,609 7,477 ------------ ------------ ------------ Cash and cash equivalents at end of year $ 42,549 $ 16,821 $ 2,609 ============ ============ ============ Supplemental disclosure of cash flow information: Cash paid during the year for: Interest (excluding capitalized interest) $ 117,081 $ 114,094 $ 123,895 Income taxes paid/(refunded) (Note 4) $ (54,283) $ 212,989 $ 222,866
See Notes to Financial Statements. 60 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CHANGES IN COMMON STOCK EQUITY For the Years Ended December 31, 2002, 2001 and 2000 (dollars in thousands)
2002 2001 2000 ------------ ------------ ------------ COMMON STOCK $ 178,162 $ 178,162 $ 178,162 ------------ ------------ ------------ ADDITIONAL PAID-IN CAPITAL 1,246,804 1,246,804 1,246,804 ------------ ------------ ------------ RETAINED EARNINGS Balance at beginning of year 790,289 694,802 558,208 Net income 199,343 265,487 306,594 Common stock dividends (170,000) (170,000) (170,000) ------------ ------------ ------------ Balance at end of year 819,632 790,289 694,802 ------------ ------------ ------------ ACCUMULATED OTHER COMPREHENSIVE LOSS Balance at beginning of year (64,565) -- -- Minimum pension liability adjustment, net of tax of $39,696 and $634 (60,521) (966) -- Cumulative effect of a change in accounting for derivatives, net of tax of $47,404 in 2001 -- 72,274 -- Unrealized gain/(loss) on derivative instruments, net of tax of $25,426 and $71,720 38,764 (109,346) -- Reclassification of realized (gain)/loss to income, net of tax of $679 and $17,399 1,036 (26,527) -- ------------ ------------ ------------ Balance at end of year (85,286) (64,565) -- ------------ ------------ ------------ TOTAL COMMON STOCK EQUITY $ 2,159,312 $ 2,150,690 $ 2,119,768 ============ ============ ============ COMPREHENSIVE INCOME Net income $ 199,343 $ 265,487 $ 306,594 Other comprehensive loss (20,721) (64,565) -- ------------ ------------ ------------ Comprehensive income $ 178,622 $ 200,922 $ 306,594 ============ ============ ============
See Notes to Financial Statements. 61 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS We are an electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about half of the Phoenix metropolitan area. Electricity is delivered through a distribution system owned by us. We also generate, sell and deliver electricity to wholesale customers in the western United States. In early 2003, the marketing and trading division was moved from Pinnacle West to us for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy (see Note 3 for a discussion of the Track A Order). Our marketing and trading division sells, in the wholesale market, our and Pinnacle West Energy's generation output that is not needed for our Native Load, which includes loads for retail customers and cost-of-service wholesale customers. We do not distribute any products. Pinnacle West owns all of our outstanding stock. During 2001, we transferred most of our marketing and trading activities to Pinnacle West, which approximated $219 million in assets and $149 million in liabilities. From time to time, we enter into transactions with Pinnacle West or Pinnacle West's subsidiaries. The following table summarizes the amounts included in the Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions): For the year ended December 31, ---------------------------- 2002 2001 2000 ------ ------ ------ Electric operating revenues: Pinnacle West - marketing and trading $ 85 $ 50 $ -- APS Energy Services -- 15 26 ------ ------ ------ Total $ 85 $ 65 $ 26 ====== ====== ====== Purchased power and fuel costs: Pinnacle West - marketing and trading $ 135 $ 50 $ -- Pinnacle West Energy -- 14 -- ------ ------ ------ Total $ 135 $ 64 $ -- ====== ====== ====== As of December 31, ------------------ 2002 2001 ------ ------ Net intercompany receivables/(payables): Pinnacle West - marketing and trading $ 135 $ 13 Pinnacle West (1) (11) Pinnacle West Energy (1) 1 APS Energy Services -- 13 ------ ------ Total $ 133 $ 16 ====== ====== 62 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. Intercompany receivables primarily include the amounts related to the transfer of marketing and trading activities discussed above and intercompany sales of electricity. Intercompany payables primarily include amounts related to the purchase of electricity. Intercompany receivables and payables are generally settled on a current basis in cash. ACCOUNTING RECORDS AND USE OF ESTIMATES Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (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. DERIVATIVE ACCOUNTING We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we enter into derivative transactions 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 commodities. 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. We examine contracts at inception to determine the appropriate accounting treatment. If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," scope exception, we account for the contract on an accrual basis with associated revenues and costs recorded at the time the contracted commodities are delivered or received. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. For contracts that qualify as a derivative and do not meet a SFAS No. 133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. Changes in the fair value of the effective portion of derivative instruments that qualify for cash flow hedge accounting treatment are recognized as either an asset or liability and in common stock equity (as a component of accumulated other comprehensive income (loss)). Gains and losses related to derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction 63 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS impacts earnings. If a contract does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period through mark-to-market accounting. On October 1, 2002, we adopted EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," which rescinded EITF 98-10. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. See Note 16 for more details on the change in accounting for energy trading contracts and for further discussion on derivative accounting. MARK-TO-MARKET ACCOUNTING Under mark-to-market accounting, the purchase or sale of energy commodities is reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as assets and liabilities from risk management and trading activities in the Balance Sheets. We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted. When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers. We convert quarterly and calendar year quotes into monthly prices based on historical relationships. For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model. For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged. 64 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS A credit valuation adjustment is also recorded to represent estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. See Note 16 for further discussion on credit risk. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our practice is to hedge within timeframes established by the ERMC. REGULATORY ACCOUNTING We are regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections of costs not likely to be incurred. We are required to discontinue applying SFAS No. 71 when deregulatory legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated. In 1999, we discontinued the application of SFAS No. 71 for our generation operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a discussion of the 1999 Settlement Agreement. As a result, we tested the generation assets for impairment and determined the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, a regulatory disallowance removed $234 million pretax ($183 million net present value) from ongoing regulatory cash flows and was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extraordinary charge on the 1999 Statements of Income. In 2002, the ACC directed us not to transfer our generation assets, as previously required by the 1999 Settlement Agreement (see "Track A Order" in Note 3). Accordingly, we now consider our generation to be cost-based, rate-regulated and subject to the requirements of SFAS No. 71. The impact of this change was immaterial to our financial statements. 65 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Prior to the 1999 Settlement Agreement, the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions): 1999 2000 2001 2002 2003 2004 Total ----- ----- ----- ----- ----- ----- ----- $ 164 $ 158 $ 145 $ 115 $ 86 $ 18 $ 686 Regulatory assets are reported as deferred debits on the Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the following (dollars in millions): December 31, ----------------- 2002 2001 ------ ------ Remaining balance recoverable under the 1999 Settlement Agreement (a) $ 104 $ 219 Spent nuclear fuel storage (Note 10) 46 43 Electric industry restructuring transition costs (Note 3) 40 34 Other 51 46 ------ ------ Total regulatory assets $ 241 $ 342 ====== ====== (a) The majority of our unamortized regulatory assets above relates to deferred income taxes (see Note 4) and rate synchronization cost deferrals (see "Rate Synchronization Cost Deferrals" below). Regulatory liabilities are included in deferred credits and other on the Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the following (dollars in millions): December 31, ----------------- 2002 2001 ------ ------ Deferred gains on utility property $ 20 $ 20 Other 6 7 ------ ------ Total regulatory liabilities $ 26 $ 27 ====== ====== 66 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS RATE SYNCHRONIZATION COST DEFERRALS As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense in the Statements of Income. UTILITY PLANT AND DEPRECIATION Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes: * material and labor; * contractor costs; * construction overhead costs (where applicable); and * capitalized interest or an allowance for funds used during construction. We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant, plus removal costs less salvage realized, to accumulated depreciation. See Note 2 for information on a new accounting standard that impacts accounting for removal costs. We record depreciation on utility property on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2002 were as follows: * Fossil plant - 20 years; * Nuclear plant - 22 years * Transmission - 34 years * Distribution - 28 years; and * Other utility property - 9 years For the years 2000 through 2002 the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 20%. The weighted-average rate was 3.35% for 2002, 3.40% for 2001 and 2000. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years. CAPITALIZED INTEREST Capitalized interest represents the cost of debt funds used to finance construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. Capitalized interest does not represent current cash 67 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS earnings. The rate used to calculate capitalized interest was a composite rate of 5.28% for 2002, 6.26% for 2001 and 6.62% for 2000. ELECTRIC REVENUES Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Other than revenues and purchased power costs related to energy trading activities, revenues are reported on a gross basis in our Statements of Income. All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Statements of Income on a net basis. CASH AND CASH EQUIVALENTS For purposes of the Statements of Cash Flows, we consider all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents. NUCLEAR FUEL We charge nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method based on actual physical usage. We divide the cost of the fuel by the estimated number of thermal units we expect to produce with that fuel. We then multiply that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense. We also charge nuclear fuel expense for the permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel, and it charges us $0.001 per kWh of nuclear generation. See Note 10 for information about spent nuclear fuel disposal and Note 11 for information on nuclear decommissioning costs. INCOME TAXES Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, "Accounting for Income Taxes." Pinnacle West files the federal income tax return on a consolidated basis and files the state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to us as though we filed a separate income tax return. Any difference between the aforementioned allocations and the consolidated (and unitary) income tax liability is attributed to Pinnacle West. 68 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS REACQUIRED DEBT COSTS For debt related to the regulated portion of our business, we amortize those gains and losses incurred upon early retirement over the original remaining life of the debt. In accordance with the 1999 Settlement Agreement, we are continuing to accelerate reacquired debt costs over an eight-year period that will end June 30, 2004. All regulatory asset amortization is included in depreciation and amortization expense in the Statements of Income. STOCK-BASED COMPENSATION Pinnacle West offers stock-based compensation plans for officers and key employees of our company. 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." The fair value method of accounting is the preferred method. 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 Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees." The following chart compares our net income and stock compensation expense 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 2002 (dollars in thousands): 2002 2001 2000 -------- -------- -------- Net income: As reported $199,343 $265,487 $306,594 Pro forma (fair value method) 198,381 263,905 305,745 Stock compensation expense (net of tax): As reported 200 -- -- Pro forma (fair value method) 962 1,582 849 In order to calculate the fair value of the 2002 stock option grants and the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options: 2002 2001 2000 -------- -------- -------- Risk-free interest rate 4.17% 4.08% 5.81% Dividend yield 4.17% 3.70% 3.48% Volatility 22.59% 27.66% 32.00% Expected life (months) 60 60 60 See Note 14 for further discussion about our stock compensation plans. 69 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 2. ACCOUNTING MATTERS On January 1, 2003 we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires the fair value of asset retirement obligations to be recorded as a liability, along with an offsetting plant asset, when the obligation is incurred. Accretion of the liability due to the passage of time will be an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. (See Note 1 for more information regarding our previous accounting for removal costs.) We determined that we have asset retirement obligations for our nuclear facilities (nuclear decommissioning) and certain other fossil generation, transmission and distribution assets. On January 1, 2003 we recorded a liability of $219 million for our asset retirement obligations including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a net regulatory liability of $40 million for our asset retirement obligations related to our regulated utility. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. In November 2002, the EITF reached a consensus on EITF 00-21, "Revenue Arrangements with Multiple Deliverables." EITF 00-21 addresses certain aspects of the accounting by a vendor for arrangements under which it will perform multiple revenue-generating activities. EITF 00-21 specifically addresses how to determine whether an arrangement has identifiable, separable revenue-generating activities. EITF 00-21 does not address when the criteria for revenue recognition are met or provide guidance on the appropriate revenue recognition convention. EITF 00-21 is effective for revenue arrangements entered into after July 1, 2003. We are currently evaluating the impacts of this new guidance, but we do not believe it will have a material impact on our financial statements. On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and the accounting and reporting provisions for the disposal of a segment of a business. This standard did not impact our financial statements at adoption. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements Nos. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" which, among other things, supersedes previous guidance for reporting gains and losses from extinguishment of debt. This standard did not impact our financial statements at adoption. In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. 70 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS The guidance will be applied to exit or disposal activities initiated after December 31, 2002. This standard did not impact our financial statements at adoption. In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), "Accounting for Certain Costs Related to Property, Plant, and Equipment." This proposed SOP would create a project timeline framework for capitalizing costs related to property, plant and equipment construction. It would require that property, plant and equipment assets be accounted for at the component level and require administrative and general costs incurred in support of capital projects to be expensed in the current period. In November 2002, the AICPA announced they would no longer issue general purpose SOPs. The work they have performed on the proposed SOP will be transitioned to the FASB staff. In February 2003, the FASB determined that the AICPA should continue their deliberations on certain aspects of the proposed SOP. We are waiting for further guidance from the FASB staff and the AICPA on the timing of the final guidance. See the following Notes for other new accounting standards: * Notes 1 and 14 for a new accounting standard (SFAS No. 148) related to stock-based compensation; * Note 16 for a new EITF issue (EITF 02-3) related to accounting for energy trading contracts; * Note 18 for a new interpretation (FIN No. 46) related to VIEs; and * Note 19 for a new standard (SFAS No. 142) related to goodwill and intangible assets. 3. REGULATORY MATTERS ELECTRIC INDUSTRY RESTRUCTURING STATE OVERVIEW On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among us and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, we were required to transfer all of our competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Consistent with that requirement, we had been addressing the legal and regulatory requirements necessary to complete the transfer of our generation assets to Pinnacle West Energy on or before that date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed us not to transfer our generation assets to Pinnacle West Energy. See "Track A Order" below. On September 16, 2002, we filed an application with the ACC requesting the ACC to allow us to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to Pinnacle West; to guarantee up to $500 million of Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to exceed $500 million in the aggregate. In our application, we stated that the 71 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between us and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing provided by Pinnacle West to fund the construction of Pinnacle West Energy generation assets or from effectively competing in the wholesale markets. On March 27, 2003, the ACC authorized us to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. See "ACC Applications" below. COMPETITIVE PROCUREMENT PROCESS On September 10, 2002, the ACC issued an order that, among other things, established a requirement that we competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order which documented the decision made by the ACC at its open meeting on February 27, 2003, addressing this requirement. Under the order, we will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, we will be required to solicit competitive bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in our retail load and retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets." The order recognizes our right to reject any bids that are unreasonable, uneconomical or unreliable. We expect to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply our electricity requirements. See "Track B Order" below. These regulatory developments and legal challenges to the Rules have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. These matters are discussed in more detail below. 1999 SETTLEMENT AGREEMENT The following are the major provisions of the 1999 Settlement Agreement, as approved by the ACC: * We have reduced, and will reduce, rates for standard-offer service for customers with loads less than three MW in 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%. Based on the price reductions authorized in the 1999 Settlement Agreement, there were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; and approximately $28 million ($17 million after taxes), effective July 1, 2002. The final price reduction is to be implemented July 1, 2003. For customers having 72 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002. * Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004. * There will be a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor we will be prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms; material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. * We will be permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the "provider of last resort" and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. * Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see "Retail Electric Competition Rules" below), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this note have raised considerable uncertainty about the status and pace of electric competition in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory. * Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we had demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). We will not be allowed to recover $183 million net present value (in 1999 dollars) of the above amounts. The 1999 Settlement Agreement provides that we will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition 73 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery due to sales volume variances. * We will form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) our competitive electric assets and services at book value as of the date of transfer, and will complete the transfers no later than December 31, 2002. We will be allowed to defer and later collect, beginning July 1, 2004, 67% percent of our costs to accomplish the required transfer of generation assets to an affiliate. However, as noted above and discussed in greater detail below, in 2002, the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing an order preventing us from transferring our generation assets. RETAIL ELECTRIC COMPETITION RULES The Rules approved by the ACC included the following major provisions: * They apply to virtually all Arizona electric utilities regulated by the ACC, including us. * Effective January 1, 2001, retail access became available to all of our retail electricity customers. * Electric service providers that get CC&N's from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution. * Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services. * The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs. * Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our competitive electric assets and services to affiliates no later than December 31, 2002. However, as noted above and discussed in greater detail below, in 2002, the ACC reversed its decision, as reflected in the Rules, to require us to transfer our generation assets. 74 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 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, we 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 affects 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 our property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have appealed the ruling to the Arizona Court of Appeals, as a result of which the Superior Court's ruling is automatically stayed pending further judicial review. That appeal is still pending. In a similar appeal concerning the issuance of competitive telecommunications CC&N's, the Arizona Court of Appeals invalidated rates for competitive carriers due to the ACC's failure to establish a fair value rate base for such carriers. That decision was upheld by the Arizona Supreme Court. PROVIDER OF LAST RESORT OBLIGATION Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are the "provider of last resort" for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. Unless we are able to obtain an adjustment of our rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that we would be able to fully recover the costs of this power. GENERIC DOCKET In January 2002, the ACC opened a "generic" docket to "determine if changed circumstances require the [ACC] to take another look at electric restructuring in Arizona." In February 2002, the ACC docket relating to our October 2001 filing was consolidated with several other pending ACC dockets, including the generic docket. On May 2, 2002, the ACC issued a procedural order stating that 75 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS hearings would begin on June 17, 2002 on various issues, including our planned divestiture of generation assets to Pinnacle West Energy and associated market and affiliate issues. The procedural order also stated that consideration of the competitive bidding process required by the Rules would proceed concurrently with the Track A issues. TRACK A ORDER On September 10, 2002, the ACC issued the Track A Order, which documents decisions made by the ACC at an open meeting on August 27, 2002. The major provisions of the Track A Order include, among other things: Provisions related to the reversal of the generation asset transfer requirement: * The ACC reversed its decision, as reflected in the Rules, to require us to transfer our generation assets either to an unrelated third party or to a separate corporate affiliate; and * the ACC unilaterally modified the 1999 Settlement Agreement, which authorized the transfer of our generating assets, and directed us to cancel our activities to transfer our generation assets to Pinnacle West Energy. Provisions related to the wholesale competitive energy procurement process (Track B issues): * The ACC stayed indefinitely the requirement of the Rules that we acquire 100% of our energy needs for our standard offer customers from the competitive market, with at least 50% obtained through a competitive bid process; * the ACC established a requirement that we competitively procure, at a minimum, any required power that we cannot produce from our existing assets in accordance with the ultimate outcome of the Track B proceedings; * the ACC directed the parties to develop a competitive procurement ("bidding") process that can begin by March 1, 2003; and * the ACC stated that "the [Pinnacle West Energy] generating assets that APS may acquire from [Pinnacle West Energy] shall not be counted as APS assets in determining the amount, timing and manner of the competitive solicitation" for Track B purposes, thereby bifurcating the regulatory treatment of our existing assets and the Pinnacle West Energy assets. On November 15, 2002, we 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 V. ARIZONA CORPORATION COMMISSION, CV2002-0222 32. ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION COMMISSION, 1CA CC 02-0002. On December 13, 2002, we and the ACC staff agreed to principles for resolving certain issues raised by us in our appeals of the Track A Order. We and the ACC 76 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS are the only parties to the Track A Order appeals. The major provisions of this document include, among other things, the following: * The parties agreed that it would be appropriate for the ACC to consider the following matters in our upcoming general rate case, anticipated to be filed before June 30, 2003: * the generating assets to be included in our rate base, including the question of whether certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and Saguaro Unit 3) should be included in our rate base; * the appropriate treatment of the $234 million pretax asset write-off agreed to by us as part of a 1999 settlement agreement approved by the ACC among us and various parties related to the implementation of retail competition in Arizona; and * the appropriate treatment of costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. * Upon the ACC's issuance of a final decision that is no longer subject to appeal approving the Financing Application, with appropriate conditions, our appeals of the Track A Order would be limited to the issues described in the preceding bullet points, each of which would be presented to the ACC for consideration prior to any final judicial resolution. On February 21, 2003, a Notice of Claim was filed with the ACC and the Arizona Attorney General on behalf of Pinnacle West, Pinnacle West Energy and us to preserve their and our rights relating to the Track A Order. TRACK B ORDER The ACC Staff has conducted workshops on the Track B issues with various parties to determine and define the appropriate process to be used for competitive power procurement. On September 10, 2002, the ACC issued an order that, among other things, established a requirement that APS competitively procure certain power requirements. On March 14, 2003, the ACC issued the Track B Order which documented the decision made by the ACC at its open meeting on February 27, 2003, addressing this requirement. The order adopted most of the provisions of an ACC ALJ's recommendation that was issued on January 30, 2003. Under the ACC's Track B Order, we will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, we will be required to solicit competitive bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in our retail load and retail energy sales. The Track B Order also confirmed that it was "not intended to change the current rate base status of [APS'] existing assets." The order recognizes our right to reject any bids that are unreasonable, uneconomical or unreliable. The Track B procurement process will involve the ACC Staff and an independent monitor. The Track B Order also contains requirements relating to standards of conduct between us and any of our affiliates that may 77 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS participate in the competitive solicitation, requires that we treat bidders in a non-discriminatory manner and requires us to file a protocol regarding short-term and emergency procurements. The order permits the provision of corporate oversight support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with our confidential bidding information that is not available to other bidders. The order directs us to evaluate bids on cost, reliability and reasonableness. The decision requires bidders to allow the ACC to inspect their plants and requires assurances of appropriate competitive market conduct from senior officers of such bidders. Following the solicitation, we will prepare a report evaluating environmental issues relating to the procurement and a series of workshops on environmental risk management will be commenced thereafter. We expect to issue requests for proposals in March 2003 and to complete the selection process by June 1, 2003. Pinnacle West Energy will be eligible to bid to supply our electricity requirements. ACC APPLICATIONS On September 16, 2002, we filed a Financing Application requesting the ACC to allow us to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or Pinnacle West; to guarantee up to $500 million of Pinnacle West Energy's or Pinnacle West's debt; or a combination of both, not to exceed $500 million in the aggregate. The loan and/or the guarantee would be used to refinance debt incurred to fund the construction of Pinnacle West Energy generation assets. The Financing Application addressed, among other things, the following matters: * We noted that our April 19, 2002 filing with the ACC had sought unification of "[Pinnacle West Energy] Assets" (West Phoenix Units 4 and 5, Redhawk Units 1 and 2, and Saguaro Unit 3) and our generation assets under a common financial and regulatory regime. We further noted that the Track A Order's language regarding the treatment of the Pinnacle West Energy Assets for Track B purposes appears to postpone a decision regarding the inclusion of the Pinnacle West Energy Assets in our rate base, thereby effectively precluding the consolidation of the Pinnacle West Energy Assets at APS under a common financial and regulatory regime at the present time. * We stated that we did not intend or desire to foreclose the possibility that we would acquire all or part of the Pinnacle West Energy Assets or that we may propose that the Pinnacle West Energy Assets be included in our rate base or afforded cost-of-service regulatory treatment to the extent the Pinnacle West Energy Assets are used by our customers. We stated that these issues would be appropriate topics in our 2003 general rate case and noted that the Track A Order specifically stated that the ACC would not pre-judge the eventual rate treatment of the Pinnacle West Energy Assets. 78 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS * We stated that the Track A Order's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between us and Pinnacle West Energy under different regulatory regimes result in Pinnacle West Energy being unable to attain investment-grade credit ratings. This, in turn, precludes Pinnacle West Energy from accessing capital markets to refinance the bridge financing provided by Pinnacle West to fund the construction of the Pinnacle West Energy Assets or from effectively competing in the wholesale markets. We noted that Pinnacle West Energy had previously received investment-grade credit ratings contingent upon its receipt of our generation assets and that Pinnacle West's credit ratings could be adversely affected if Pinnacle West Energy is unable to finance its capital requirements. On November 4, 2002, Standard & Poor's lowered Pinnacle West's senior unsecured debt rating from "BBB" to "BBB-." * We stated that the amount of the requested loan and/or guarantee is our present estimate of the amount of credit support necessary through us to restore Pinnacle West Energy and Pinnacle West to their credit status prior to the ACC's issuance of the Track A Order. We further stated that if the requested amount proves to be inadequate, we reserve the right to submit a second financing application seeking additional credit support. On March 27, 2003, the ACC approved the Financing Application, subject to the following principal conditions: * any debt issued by us pursuant to the order must be unsecured; * we will be permitted to loan up to $500 million to Pinnacle West Energy (the "APS Loan"), guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate; * the APS Loan must be callable and secured by certain Pinnacle West Energy assets; * the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on our debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security); * the 264 basis points referred to in the previous bullet point will be capitalized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum; * the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC; * any demonstrable increase in our cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases; 79 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS * we must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce our common equity ratio below that threshold, unless otherwise waived by the ACC. The ACC will process any waiver request within sixty days, and for this sixty-day period this condition will be suspended. However, this condition, which will continue indefinitely, will not be permanently waived without an order of the ACC; and * certain waivers of the ACC's affiliated interest rules previously granted to APS and its affiliates will be withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each, a "Covered Transaction"), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, except that the foregoing restrictions will not apply to the following categories of Covered Transactions: * Covered Transactions less than $100 million, measured on a cumulative basis over the calendar year in which the Covered Transactions are made; * Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCor's anticipated accelerated asset sales activity during those years; * Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy's (a) West Phoenix Unit 5, located in Phoenix, with an expected commercial operation date in mid-2003, and (b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and * Covered Transactions related to the sale of 25% of the Silverhawk plant to Southern Nevada Water Authority if Southern Nevada Water Authority exercises its existing purchase option to do so. The ACC also ordered the ACC staff to conduct an inquiry into our and our affiliates' compliance with the retail electric competition and related rules and decisions. In mid-2003, Pinnacle West will need to refinance approximately $475 million of their indebtedness. We expect that this indebtedness will be repaid through funds borrowed by Pinnacle West Energy from us under the APS Loan. On November 22, 2002, the ACC approved our request to permit us to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million or (b) guarantee $125 million of Pinnacle West's short-term debt, subject to certain conditions. See Note 5. 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 has 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, and the FERC has announced that it will issue an additional white paper on the 80 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS proposed Standard Market Design in April 2003. We are reviewing the proposed rulemaking and 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. 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 in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our 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. 4. INCOME TAXES We are included in Pinnacle West's consolidated tax return. However, when Pinnacle West allocates income taxes to us, it does so based on our taxable income or loss alone. Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates. We have recorded a regulatory asset related to income taxes on our Balance Sheets in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. We amortize this amount as the differences reverse. In accordance with ACC settlement agreements, we are continuing to accelerate amortization of a regulatory asset related to income taxes over an eight-year period that will end June 30, 2004 (see Note 1). Accordingly, we are including this accelerated amortization in depreciation and amortization expense on the Statements of Income. As a result of a change in IRS guidance, we claimed a tax deduction related to a tax accounting method change on the 2001 Pinnacle West federal consolidated income tax return. The accelerated deduction has resulted in a $200 million reduction in the current income tax liability. In 2002, we received an income tax refund of approximately $115 million related to the 2001 Pinnacle West federal consolidated income tax return. The components of income tax expense for income before accounting change are (dollars in thousands): 81 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Year Ended December 31, ------------------------------------ 2002 2001 2000 ---------- ---------- ---------- Current: Federal $ (61,962) $ 174,251 $ 211,139 State (18,000) 35,401 50,252 ---------- ---------- ---------- Total current (79,962) 209,652 261,391 Deferred 206,767 (26,516) (65,726) ---------- ---------- ---------- Total income tax expense $ 126,805 $ 183,136 $ 195,665 ========== ========== ========== The following table compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): Year Ended December 31, ------------------------------------ 2002 2001 2000 ---------- ---------- ---------- Federal income tax expense at 35% statutory rate $ 114,152 $ 162,338 $ 175,791 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 15,036 20,563 20,007 Other (2,383) 235 (133) ---------- ---------- ---------- Income tax expense $ 126,805 $ 183,136 $ 195,665 ========== ========== ========== The following table sets forth the net deferred income tax liability recognized on the Balance Sheets at December 31, 2002 and 2001 (dollars in thousands): December 31, -------------------------- 2002 2001 ----------- ----------- Current asset/(liability) $ 4,094 $ (3,244) Long term liability (1,225,552) (1,023,079) ----------- ----------- Accumulated deferred income taxes - net $(1,221,458) $(1,026,323) =========== =========== 82 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS The components of the net deferred income tax liability were as follows (dollars in thousands): December 31, -------------------------- 2002 2001 ----------- ----------- DEFERRED TAX ASSETS Pension liability $ 61,966 $ 13,450 Risk management and trading activities 38,204 46,343 Deferred gain on Palo Verde Unit 2 sale-leaseback 23,562 25,374 Other 80,965 97,868 ----------- ----------- Total deferred tax assets 204,697 183,035 ----------- ----------- DEFERRED TAX LIABILITIES Plant-related (1,316,636) (1,069,207) Regulatory asset for income taxes (80,635) (121,757) Risk management and trading activities (28,884) (18,394) ----------- ----------- Total deferred tax liabilities (1,426,155) (1,209,358) ----------- ----------- Accumulated deferred income taxes - net $(1,221,458) $(1,026,323) =========== =========== 5. LINES OF CREDIT AND SHORT-TERM BORROWINGS We had committed lines of credit with various banks of $250 million at December 31, 2002 and 2001, which were available either to support the issuance of commercial paper or to be used for bank borrowings. These lines of credit mature in June 2003. The commitment fees at December 31, 2002 and 2001 for these lines of credit were 0.09% per annum. We had no bank borrowings outstanding under these lines of credit at December 31, 2002 and 2001. We had no commercial paper borrowings outstanding at December 31, 2002 and $171 million at December 31, 2001. The weighted average interest rate on commercial paper borrowings was 2.47% for the year ended December 31, 2002 and 4.72% for the year ended December 31, 2001. By Arizona statute, our short-term borrowings cannot exceed 7% of our total capitalization unless approved by the ACC. On November 22, 2002, the ACC approved our request to permit us to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West's short-term debt, subject to certain conditions. This interim loan matures in December 2003. There have been no borrowings on this line. 6. LONG-TERM DEBT Borrowings under our mortgage bond indenture are secured by substantially all of the Company's utility plant. We also have unsecured debt. The following table presents the components of long-term debt on the Balance Sheets outstanding at December 31, 2002 and 2001 (dollars in thousands): 83 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
December 31, Maturity Interest ------------------------- Dates (a) Rates 2002 2001 --------- ------ ----------- ----------- First mortgage bonds 2002 8.125%(b) $ -- $ 125,000 2004 6.625% 80,000 80,000 2023 7.25% 54,150 54,150 2024 8.75% (c) -- 121,668 2025 8.0% 33,075 33,075 2028 5.5% 25,000 25,000 2028 5.875% 154,000 154,000 Unamortized discount and premium (6,337) (5,266) Pollution control bonds 2024-2034 (d) 386,860 386,860 Pollution control bonds 2029 3.30% (e) -- 90,000 Pollution control bonds with senior notes (f) 2029 5.05% 90,000 -- Unsecured notes 2004 5.875% 125,000 125,000 Unsecured notes 2005 6.25% 100,000 100,000 Unsecured notes 2005 7.625% 300,000 300,000 Unsecured notes 2011 6.375% 400,000 400,000 Unsecured notes 2012 6.50% 375,000 -- Senior notes (g) 2006 6.75% 83,695 83,695 Capitalized lease obligations 2003-2012 5.78% 20,400 1,343 ----------- ----------- Total long-term debt 2,220,843 2,074,525 Less current maturities 3,503 125,451 ----------- ----------- Total long-term debt less current maturities $ 2,217,340 $ 1,949,074 =========== ===========
(a) This schedule does not reflect the timing of redemptions that may occur prior to maturity. (b) On March 15, 2002, we redeemed at maturity, $125 million of our First Mortgage Bonds, 8.125% Series due 2002. (c) On April 15, 2002, we redeemed $122 million of our First Mortgage Bonds, 8.75% Series due 2024. (d) The weighted-average rate was 1.94% at December 31, 2002 and 2.55% at December 31, 2001. Changes in short-term interest rates would affect the costs associated with this debt. (e) In November 2001, these bonds were converted to a one year fixed rate of 3.30%. These bonds were previously adjustable rate, and from January 1, 2001 until October 31, 2001, the weighted average rate was 2.72%. (f) On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned the proceeds to us pursuant to a loan agreement. The bonds were issued to refinance $90 million of outstanding pollution control bonds. The bondholders were issued $90 million of first mortgage bonds (senior note mortgage bonds) as collateral. 84 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (g) We currently have outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes, as well as, the $90 million issue discussed in footnote (f) above. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity and redemption provisions as the senior notes. Our payments of principal, premium and/or interest on the senior notes satisfy our corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When we repay all of our first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding. Our significant debt covenants related to our financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. We are in compliance with such covenants and anticipate that we will continue to meet all the significant covenant requirement levels. 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. Our financing agreements do not 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, we may be subject to increased interest costs under certain financing agreements. All of our bank agreements contain "cross-default" provisions under which a default by us in a specified amount under another agreement would result in a default and the potential acceleration of payment under the agreements. Our credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's business or financial condition. The following is a list of payments due on total long-term debt and capitalized lease requirements through 2007: * $ 4 million in 2003; * $ 208 million in 2004; * $ 403 million in 2005; * $ 87 million in 2006; * $ 2 million in 2007; and * $1,523 million, thereafter. Our first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. We may pay dividends on our common stock if there is a sufficient amount "available" from retained earnings and the excess of cumulative book depreciation (since the mortgage's inception) over mortgage depreciation, which is the cumulative amount of additional property pledged each year to address collateral depreciation. As of December 31, 2002, the amount "available" under the mortgage would have allowed us to pay 85 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS approximately $3 billion of dividends compared to our current annual common stock dividends of $170 million. 7. RETIREMENT PLANS AND OTHER BENEFITS PENSION PLANS Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance pension plan for all new employees in place of the defined benefit plan, and, effective April 1, 2003, the new plan will be offered as an alternative to the defined benefit plan for all existing employees. In 2002, we represented 87% of the total cost of this plan. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all of our employees. The supplemental excess benefit plan covers officers of the company and highly compensated employees designated for participation by Pinnacle West's Board of Directors. Our employees do not contribute to the plans. Generally, the benefits under these plans are calculated based on age, years of service and pay. Pinnacle West funds the qualified plan by contributing at least the minimum amount required under IRS regulations but no more than the maximum tax-deductible amount. The assets in the qualified plan at December 31, 2002 were mostly domestic common stocks and bonds and real estate. The following table shows our contributions and pension expense, including administrative costs, and after consideration of amounts capitalized or billed to electric plant participants for 2002, 2001, and 2000 (dollars in millions): 2002 2001 2000 ------ ------ ------ Contributions $ 26 $ 44 $ 23 Pension expense $ 11 $ 6 $ 2 The following table shows the components of Pinnacle West's consolidated net periodic pension cost before consideration of amounts capitalized or billed to electric plant participants for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands): 86 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
2002 2001 2000 ---------- ---------- ---------- Service cost - benefits earned during the period $ 30,333 $ 27,640 $ 26,040 Interest cost on projected benefit obligation 71,242 66,549 61,625 Expected return on plan assets (75,652) (77,340) (77,231) Amortization of: Transition asset (3,227) (3,227) (3,227) Prior service cost 2,912 3,008 2,370 Net actuarial loss/(gain) 1,846 907 (1,190) ---------- ---------- ---------- Net periodic pension cost $ 27,454 $ 17,537 $ 8,387 ========== ========== ==========
The following table shows a reconciliation of the funded status of the plans to the amounts recognized in Pinnacle West's Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands): 2002 2001 ---------- ---------- Funded status - pension plan assets less than projected benefit obligation $ (348,770) $ (166,773) Unrecognized net transition asset (10,327) (13,554) Unrecognized prior service cost 23,148 26,170 Unrecognized net actuarial losses 293,223 108,422 ---------- ---------- Accrued pension benefit liability recognized in the Consolidated Balance Sheets $ (42,726) $ (45,735) ========== ========== The following table sets forth Pinnacle West's defined benefit pension plans' change in projected benefit obligation for the plan years 2002 and 2001 (dollars in thousands):
2002 2001 ---------- ---------- Projected pension benefit obligation at beginning of year $ 931,646 $ 840,485 Service cost 30,333 27,640 Interest cost 71,242 66,549 Benefit payments (35,230) (33,282) Actuarial losses 71,696 21,632 Plan amendments (110) 8,622 ---------- ---------- Projected pension benefit obligation at end of year $1,069,577 $ 931,646 ========== ==========
The following table sets forth Pinnacle West's qualified defined benefit pension plans' change in the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands): 87 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 2002 2001 ---------- ---------- Fair value of pension plan assets at beginning of year $ 764,873 $ 775,196 Actual loss on plan assets (36,966) (22,876) Employer contributions 26,600 44,200 Benefit payments (33,700) (31,647) ---------- ---------- Fair value of pension plan assets at end of year $ 720,807 $ 764,873 ========== ========== The following table sets forth Pinnacle West's defined benefit pension plans' amounts recognized in Pinnacle West's Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands): 2002 2001 ---------- ---------- Accrued pension benefit liability $ (42,726) $ (45,735) Additional minimum liability (141,155) (3,297) Intangible asset 23,148 1,697 Accumulated other comprehensive loss - pretax 118,007 1,600 The following table shows Pinnacle West's accumulated benefit obligation in relation to the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands): 2002 2001 ---------- ---------- Projected benefit obligation $1,069,577 $ 931,646 Accumulated benefit obligation 904,687 752,230 Fair value of plan assets 720,807 764,873 The following are weighted-average assumptions as of December 31, 2002 and 2001: 2002 2001 ---------- ---------- Discount rate 6.75% 7.50% Rate of increase in compensation levels 4.00% 4.00% Expected long-term rate of return on assets 9.00% 10.00% EMPLOYEE SAVINGS PLAN BENEFITS Pinnacle West sponsors a defined contribution savings plan for the employees of Pinnacle West and its subsidiaries. In 2002, we represented 93% of the total cost of this plan. In a defined contribution savings plan, the 88 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS benefits a participant will receive result from regular contributions they make to a participant account. Under this plan, Pinnacle West makes matching contributions in Pinnacle West stock to participant accounts. After a five-year vesting period, participants have a choice to change the employer contribution match to other investments. At December 31, 2002, approximately 25% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately $4 million for 2002, $4 million for 2001, and $3 million for 2000. OTHER POSTRETIREMENT BENEFITS Pinnacle West sponsors other postretirement benefits for the employees of Pinnacle West and its subsidiaries. In 2002, we represented 87% of the total cost of this plan. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits. Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds. The following table shows our contributions and postretirement benefit expense after consideration of amounts capitalized or billed to electric plant participants for 2002, 2001 and 2000 (dollars in millions): 2002 2001 2000 ------ ------ ------ Contributions $ 7 $ 11 $ 5 Other postretirement benefit expense $ 9 $ 6 $ 2 The following table shows the components of Pinnacle West's net periodic other postretirement benefit costs before consideration of amounts capitalized or billed to electric plant participants for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):
2002 2001 2000 ---------- ---------- ---------- Service cost - benefits earned during the period $ 12,036 $ 9,438 $ 8,613 Interest cost on accumulated benefit obligation 25,235 21,585 19,315 Expected return on plan assets (21,116) (21,985) (22,381) Amortization of: Transition obligation 4,001 7,698 7,698 Prior service credit (75) -- -- Net actuarial loss/(gain) 3,072 (4,066) (7,983) ---------- ---------- ---------- Net periodic other postretirement benefit cost $ 23,153 $ 12,670 $ 5,262 ========== ========== ==========
The following table shows a reconciliation of the funded status of the plan to the amounts recognized in Pinnacle West's Consolidated Balance Sheets as of December 31, 2002 and 2001 (dollars in thousands): 89 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
2002 2001 ---------- ---------- Funded status - other postretirement plan assets less than accumulated other postretirement benefit obligation $ (186,400) $ (80,544) Unrecognized net obligation at transition 36,489 84,748 Unrecognized prior service credit (1,673) -- Unrecognized net actuarial loss/(gain) 148,268 (8,606) ---------- ---------- Net other postretirement benefit liability recognized in the Consolidated Balance Sheets $ (3,316) $ (4,402) ========== ==========
The following table sets forth Pinnacle West's other postretirement benefit plan's change in accumulated postretirement benefit obligation for the plan years 2002 and 2001 (dollars in thousands):
2002 2001 ---------- ---------- Accumulated other postretirement benefit obligation at beginning of year $ 318,355 $ 264,006 Service cost 12,036 9,438 Interest cost 25,235 21,585 Benefit payments (10,473) (10,194) Actuarial losses 108,979 33,520 Plan amendments (44,258)(a) -- ---------- ---------- Accumulated other postretirement benefit obligation at end of year $ 409,874 $ 318,355 ========== ==========
(a) The plan was amended January 1, 2002 to increase the deductibles, out of pocket maximums and prescription drug co-pays. The plan was amended in June 2002 to increase the participants' portion of premiums. 90 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS The following table sets forth Pinnacle West's other postretirement benefit plan's change in the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands):
2002 2001 ---------- ---------- Fair value of other postretirement benefit plan assets at beginning of year $ 237,810 $ 249,154 Actual loss on plan assets (27,802) (12,550) Employer contributions 23,600 11,400 Benefit payments (10,134) (10,194) ---------- ---------- Fair value of other postretirement benefit plan assets at end of year $ 223,474 $ 237,810 ========== ==========
The following are weighted-average assumptions as of December 31, 2002 and 2001: 2002 2001 ------ ------ Discount rate 6.75% 7.50% Expected long-term rate of return on assets - pretax 9.00% 10.00% Expected long-term rate of return on assets - after tax 7.84% 8.71% Initial health care cost trend rate - under age 65 8.00% 7.00% Initial health care cost trend rate - age 65 and over 8.00% 7.00% Ultimate health care cost trend rate 5.00% 5.00% Year ultimate health care trend rate is reached 2007 2006 The following table shows the effect of a 1% increase or decrease in the initial and ultimate health care expense and cost trend rate (dollars in millions):
1% increase 1% decrease ----------- ----------- Effect of the 2002 other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants $ 5 $ (4) Effect on the 2002 service and interest cost components of net periodic other postretirement benefit costs 7 (6) Effect on the accumulated other postretirement benefit obligation at December 31, 2002 54 (43)
91 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS SEVERANCE CHARGES In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $34 million before taxes in voluntary severance costs in 2002. No further charges are expected. 8. LEASES In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. We account for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, a regulatory asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis. See Note 18 for a discussion of VIEs, including the SPEs involved in the Palo Verde sale-leaseback transactions. In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. Total lease expense recognized in the Statements of Income was $52 million in 2002, $52 million in 2001 and $53 million in 2000. The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2003 to 2015. In accordance with the 1999 Settlement Agreement and previous settlement agreements, we are continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). All regulatory asset amortization is included in depreciation and amortization expense in the Statements of Income. The balance of this regulatory asset at December 31, 2002 was $14 million. Estimated future minimum lease payments for our operating leases are approximately $59 million for each of the years 2003 to 2007 and $456 million thereafter. 92 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 9. JOINTLY-OWNED FACILITIES We share ownership of some of our generating and transmission facilities with other companies. The following table shows our interest in those jointly-owned facilities recorded on the Balance Sheets at December 31, 2002. Our share of operating and maintaining these facilities is included in the Statements of Income in operations and maintenance expense.
PERCENT CONSTRUCTION OWNED BY PLANT IN ACCUMULATED WORK IN APS SERVICE DEPRECIATION PROGRESS -------- ---------- ------------ -------- (dollars in thousands) Generating facilities: Palo Verde Nuclear Generating Station Units 1 and 3 29.1% $1,829,225 $(905,278) $17,428 Palo Verde Nuclear Generating Station Unit 2 (see Note 8) 17.0% 574,745 (289,049) 68,475 Four Corners Steam Generating Station Units 4 and 5 15.0% 153,559 (82,434) 500 Navajo Steam Generating Station Units 1, 2 and 3 14.0% 235,743 (110,923) 3,010 Cholla Steam Generating Station Common Facilities (a) 62.8%(b) 76,322 (42,608) 1,733 Transmission facilities: ANPP 500KV System 35.8%(b) 68,314 (25,655) 31 Navajo Southern System 31.4%(b) 27,129 (17,405) 664 Palo Verde-Yuma 500KV System 23.9%(b) 9,591 (4,168) 383 Four Corners Switchyards 27.5%(b) 3,071 (1,979) -- Phoenix-Mead System 17.1%(b) 36,418 (2,906) -- Palo Verde - Estrella 500KV System 50.0%(b) -- -- 50,450
(a) PacifiCorp owns Cholla Unit 4 and we operate the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned. (b) Weighted average of interests. 10. COMMITMENTS AND CONTINGENCIES ENRON We recorded charges totaling $13 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. These charges take into consideration our rights of set-off with respect to the Enron related contractual obligations. The basis of the set-offs included, but was not limited to, provisions in the various contractual arrangements with Enron and its affiliates, including an International Swaps and Derivative Agreement (ISDA) between us and Enron North America. The write-off is also net of the expected recovery based on secondary market quotes from the bond market. The amounts were 93 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS written-off from the balances of the related assets and liabilities from risk management and trading activities on the Balance Sheets. PALO VERDE NUCLEAR GENERATING STATION 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 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 that 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 filed damages actions against the DOE in the Court of Federal Claims. In February 2002, the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the President's recommendation. Congress approved the Yucca Mountain site, overriding the Nevada veto. It is now expected that the DOE will submit a license application to the NRC in late 2004. We have existing fuel storage pools at Palo Verde and are in the process of completing construction of a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, we believe that spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit. Although some low-level waste has been stored on-site in a low-level waste facility, we are currently shipping low-level waste to off-site facilities. We currently believe that interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available. We currently estimate that we will incur $115 million (in 2002 dollars) over the life of Palo Verde for our share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2002, we had spent $2 million and had recorded accumulated spent nuclear fuel amortization of $44 million and a regulatory asset of $46 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. 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 $200 million ($300 million effective January 1, 2003) 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, we could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 94 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS million per incident. Based on our interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $77 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. We have 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 insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. PURCHASED POWER AND FUEL COMMITMENTS We are party to various purchased power and fuel contracts with terms expiring from 2003 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $135 million in 2003; $82 million in 2004; $28 million in 2005; $31 million in 2006; $17 million in 2007 and $162 million thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. Of the various purchased power and fuel contracts mentioned above some of those contracts have take-or-pay provisions. The contracts we have for the supply of our coal and nuclear fuel supply have take-or-pay provisions. The current take-or-pay nuclear fuel contracts expire in 2003, and had not been renewed as of December 31, 2002. The current take-or-pay coal contracts have terms that expire in 2007. The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions): Estimated Years Ending December 31, ------------------------------------------ 2003 2004 2005 2006 2007 ------ ------ ------ ------ ------ Coal $ 43 $ 44 $ 9 $ 9 $ 9 Nuclear Fuel 22 -- -- -- -- ------ ------ ------ ------ ------ Total take-or-pay commitments (a) $ 65 $ 44 $ 9 $ 9 $ 9 ====== ====== ====== ====== ====== (a) Total take-or-pay commitments are approximately $136 million. The total net present value of these commitments is approximately $119 million. COAL MINE RECLAMATION OBLIGATIONS We must reimburse certain coal providers for amounts incurred for coal mine reclamation. Our coal mine reclamation obligation is about $59 million at December 31, 2002 and is included in deferred credits-other in the Balance Sheets. 95 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS A regulatory asset has been established for amounts not yet recovered from ratepayers related to the coal obligations. In accordance with the 1999 Settlement Agreement with the ACC, we are continuing to accelerate the amortization of the regulatory asset for coal mine reclamation over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the Statements of Income. 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. This order calls for a hearing, with findings of fact due to the FERC after the ISO and PX provide necessary historical data. The FERC directed an ALJ to make findings of fact with respect to: (1) the mitigated price in each hour of the refund period; (2) the amount of refunds owed by each supplier according to the methodology established in the order; and (3) the amount currently owed to each supplier (with separate quantities due from each entity) by the CAISO, the California Power Exchange, the investor-owned utilities, and the State of California. We were a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, we should be a recipient as well as a payor of such amounts. On December 12, 2002, an ALJ issued Proposed Findings of Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great majority of the proposed findings, revising only the calculation of natural gas prices for the final determination of mitigated prices in the California markets. Sellers who may actually have paid more for natural gas than the proxy prices adopted by the FERC have 40 days in which to submit necessary data to the FERC, after which a technical conference will be held. Finalization of refund amounts is expected in mid-2003. We do not anticipate material changes in our exposure and still believes, subject to the finalization of the revised proxy prices, that we will be entitled to a net refund. On November 20, 2002, the FERC reopened discovery in these proceedings pursuant to instructions of the United States Court of Appeals for the Ninth Circuit, that the FERC permit parties to offer additional evidence of potential market manipulation for the period January 1, 2000 through June 20, 2001. Parties have submitted additional evidence and proposed findings, which the FERC continues to consider. The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC required that the record establish the volume of the transactions, the identification of the net sellers and net buyers, the price and terms and conditions of the sales contracts, and the extent of potential refunds. On September 24, 2001, an ALJ concluded that prices in the Pacific Northwest during the period December 25, 2000 through June 20, 2001 were the result of a number of factors in addition to price signals from the California markets, including the shortage of supply, excess demand, drought, and increased natural gas prices. Under these circumstances, the ALJ ultimately concluded that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. The FERC is currently reviewing the ALJ's report and recommendations. 96 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS On December 19, 2002, the FERC opened a new discovery period to permit the parties to offer additional evidence for the period January 1, 2000 through June 20, 2001. Additional evidence has been submitted and a FERC decision on the newly submitted evidence is expected soon. Based on public comments from the FERC, it is anticipated that this case will be sent back to the ALJ for further proceedings on spot market and balance of month transactions. Although the FERC has not yet made a final ruling in the Pacific Northwest matter nor 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 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. The report also recommended that the FERC issue an order to show cause why these transactions did not violate the ISO tariff, with potential disgorgement of any unjust profits. Although APS has not yet had an opportunity to review the transactions at issue, it believes that it was not engaged in any such improper transactions. Based on the information available, it also appears that such transactions would not have a material adverse impact on our financial position, results of operation or liquidity. SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO. PG&E filed for bankruptcy protection in 2001. 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. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET. AL., Docket No. EL02-71-000. 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 has been dismissed by the FERC and the State of California is now appealing the matter to the Ninth Circuit Court of Appeals. 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 ISO markets, including us, attempting to expand those matters to such other participants. We have not yet filed a responsive pleading in the matter, but we believe the claims by Reliant and Duke as they relate to us are without merit. 97 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS We were also named in a lawsuit regarding wholesale contracts in California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United States District Court in and for the District of Northern California, Case No. C02-2855 EMC. The complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market. 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 us 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 preliminary motions are being filed and we cannot currently predict the outcome of this matter. The "United States Justice Foundation" is suing numerous wholesale energy contract suppliers to California, including Pinnacle West, as well as the California Department of Water Resources, based upon an alleged conflict of interest arising from the activities of a consultant for Edison International who also negotiated long-term contracts for the California Department of Water Resources. MCCLINTOCK, ET AL. V. YUDHRAJA, Superior Court in and for the County of Los Angeles, Case No. GC 029447. The California Attorney General has indicated that an investigation by his office did not find evidence of improper conduct by the consultant. We believe the claims against Pinnacle West and us in the lawsuits mentioned in this paragraph are without merit and will have no material adverse impact on our financial position, results of operations or liquidity. POWER SERVICE AGREEMENT By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised us that it believes we overcharged Citizens by over $50 million under a power service agreement. We believe that our charges under the agreement were fully in accordance with the terms of the agreement. In addition, in testimony filed with the ACC on March 13, 2002, Citizens acknowledged that, based on its review, "if Citizens filed a complaint with FERC, it probably would lose the central issue in the contract interpretation dispute." We and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, Pinnacle West and Citizens entered into a power sale agreement under which Pinnacle West will supply Citizens with future specified amounts of electricity and ancillary services through May 31, 2008. This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001. LETTERS OF CREDIT We have entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2002 approximately $258 million of letters of credit were outstanding to support existing pollution control bonds of approximately $253 million. The letters of credit are available to fund the payment of principal and interest on such debt obligations. These letters of credit have expiration dates in 2003. We have also entered into approximately $115 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, we have approximately $5 million of letters of credit related to counterparty collateral requirements and approximately $5 million of letters of credit related to workers' compensation expiring in 2003. 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. 98 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS INDEMNIFICATIONS In conjunction with our financing agreements, including our sale-leaseback transactions, we generally provide indemnifications relating to liabilities arising from or related to the agreements, except with certain limited exceptions depending on the particular agreement. We have also 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 indemnification 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. CONSTRUCTION PROGRAM Total capital expenditures in 2003 are estimated at $401 million. LITIGATION We are party to various 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 ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial statements, results of operations or liquidity. 11. NUCLEAR DECOMMISSIONING COSTS We recorded $11 million for nuclear decommissioning expense in each of the years 2002, 2001 and 2000. We estimate it will cost approximately $1.8 billion ($528 million in 2002 dollars) to decommission our share of the three Palo Verde units. The majority of decommissioning costs are expected to be incurred over a 14-year period beginning in 2024. We charge decommissioning costs to expense over each unit's operating license term and we include them in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are recovered in rates. Our current estimates are based on a 2001 site-specific study for Palo Verde that assumes the prompt removal/dismantlement method of decommissioning. An independent consultant prepared this study. We are required by the ACC to update the study every three years. To fund the costs we expect to incur to decommission the plant, we established external decommissioning trusts in accordance with NRC regulations and ACC orders. We invest the trust funds primarily in fixed income securities and domestic stock and classify them as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation in accordance with industry practice. The following table shows the cost and fair value of our nuclear decommissioning trust fund assets, which were reported in investments and other assets on the Balance Sheets at December 31, 2002 and 2001 (dollars in millions): 99 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 2002 2001 ------ ------ Trust fund assets - at cost: Fixed income securities $ 113 $ 103 Domestic stock 68 61 ------ ------ Total $ 181 $ 164 ====== ====== Trust fund assets - fair value: Fixed income securities $ 117 $ 106 Domestic stock 77 96 ------ ------ Total $ 194 $ 202 ====== ====== See Note 2 for information on a new accounting standard on accounting for certain liabilities related to closure or removal of long-lived assets. 12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) Quarterly financial information for 2002 and 2001 is as follows:
(dollars in thousands) 2002 ------------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 ---------- ---------- ------------ ----------- Electric operating revenues (a) Regulated electricity segment $ 383,741 $ 507,711 $ 744,463 $ 423,424 Marketing and trading segment 10,693 2,369 9,126 11,866 Operating income $ 61,221 $ 97,555 $ 120,452 $ 49,772 Net income $ 31,763 $ 64,439 $ 86,570 $ 16,571
100 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
(dollars in thousands) 2001 ------------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 ---------- ---------- ------------ ----------- Electric operating revenues (a) Regulated electricity segment $ 412,807 $ 739,317 $ 973,398 $ 436,566 Marketing and trading segment 247,022 230,894 65,129 6,195 Operating income $ 97,034 $ 95,238 $ 135,139 $ 71,567 Income before accounting change $ 64,606 $ 69,639 $ 107,556 $ 38,887 Cumulative effect of change in accounting - net of income tax (2,755) -- (12,446) -- ---------- ---------- ---------- ---------- Net income $ 61,851 $ 69,639 $ 95,110 $ 38,887 ========== ========== ========== ==========
(a) Our utility business is seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations. We have reclassified certain operating revenues to conform to the current presentation of netting energy trading contracts (see Note 16). 13. FAIR VALUE OF FINANCIAL INSTRUMENTS We believe that the carrying amounts of our cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 2002 and 2001 due to their short maturities. We hold investments in debt and equity securities for purposes other than trading. The December 31, 2002 and 2001 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. On December 31, 2002, the carrying value of our long-term debt (excluding capitalized lease obligations) was $2.21 billion, with an estimated fair value of $2.30 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $2.08 billion on December 31, 2001, with an estimated fair value of $2.10 billion. The fair value estimates are based on quoted market prices of the same or similar issues. 14. STOCK-BASED COMPENSATION Pinnacle West offers stock-based compensation plans for officers and key employees of our company. In May 2002, Pinnacle West's shareholders approved the 2002 Long-term Incentive Plan (2002 plan), which allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. Pinnacle West has 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 101 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS granting of new non-qualified stock options at a price per option 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 term of the option cannot be longer than 10 years and the option cannot be repriced during its term. The 1994 plan provides for the granting of new options (which may be non-qualified stock options or incentive stock options) of up to 3.5 million shares at a price per option not less than the fair market value on the date the option is granted. The 1985 plan includes outstanding options but no new options will be granted from 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 provides 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. The fair value method of accounting is the preferred method. 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. We recorded approximately $333,000 in stock option expense before income taxes in our Statements of Income in 2002. This amount may not be reflective of the stock option expense we will record in future years because stock options typically vest over several years and additional grants are generally made each year. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." The standard amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. The standard also amends the disclosure requirements of SFAS No. 123. SFAS No. 148 is effective for fiscal years ending after December 15, 2002. We adopted the disclosure requirements in 2002. See Note 1 for our pro forma disclosures on stock-based compensation and our weighted-average assumptions used to calculate the fair value of our stock options. Total stock-based compensation expense, including stock option expense, was $3 million in 2002, $2 million in 2001 and $2 million in 2000. 15. BUSINESS SEGMENTS We have two principal business segments (determined by services and the regulatory environment): 102 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS * our regulated electricity segment, which consists of regulated traditional retail and wholesale electricity businesses and related activities, and includes electricity transmission, distribution and generation; and * our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading. See Note 1 for information about the transfers of the marketing and trading division. See Note 1 for more information regarding our marketing and trading activities. Financial data for the years ended December 31, 2002, 2001 and 2000 by business segments is provided as follows (dollars in millions): Business Segments for Year Ended December 31, 2002 ---------------------------------------- Regulated Marketing and Electricity Trading Total ----------- ---------- ---------- Operating revenues $ 2,059 $ 34 $ 2,093 Purchased power and fuel costs 595 33 628 Other operating expenses 604 -- 604 ---------- ---------- ---------- Operating margin 860 1 861 Depreciation and amortization 400 -- 400 Interest and other expenses 136 -- 136 ---------- ---------- ---------- Pretax margin 324 1 325 Income taxes 126 -- 126 ---------- ---------- ---------- Net income $ 198 $ 1 $ 199 ========== ========== ========== Total assets $ 6,522 $ -- $ 6,522 ========== ========== ========== Capital expenditures $ 501 $ -- $ 501 ========== ========== ========== 103 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Business Segments for Year Ended December 31, 2001 ---------------------------------------- Regulated Marketing and Electricity Trading Total ----------- ---------- ---------- Operating revenues $ 2,562 $ 549 $ 3,111 Purchased power and fuel costs 1,227 314 1,541 Other operating expenses 567 -- 567 ----------- ---------- ---------- Operating margin 768 235 1,003 Depreciation and amortization 421 -- 421 Interest and other expenses 119 -- 119 ----------- ---------- ---------- Pretax margin 228 235 463 Income taxes 90 93 183 ----------- ---------- ---------- Income before accounting change 138 142 280 Cumulative effect of change in accounting for derivatives - net of income taxes of $10 (15) -- (15) ----------- ---------- ---------- Net income $ 123 $ 142 $ 265 ========== ========== ========== Total assets $ 6,052 $ 174 $ 6,226 ========== ========== ========== Capital expenditures $ 471 $ -- $ 471 ========== ========== ========== Business Segments for Year Ended December 31, 2000 ---------------------------------------- Regulated Marketing and Electricity Trading Total ----------- ---------- ---------- Operating revenues $ 2,539 $ 395 $ 2,934 Purchased power and fuel costs 1,065 267 1,332 Other operating expenses 531 -- 531 ---------- ---------- ---------- Operating margin 943 128 1,071 Depreciation and amortization 425 -- 425 Interest and other expenses 144 -- 144 ---------- ---------- ---------- Pretax margin 374 128 502 Income taxes 146 49 195 ---------- ---------- ---------- Net income $ 228 $ 79 $ 307 ========== ========== ========== Total assets $ 5,958 $ 392 $ 6,350 ========== ========== ========== Capital expenditures $ 472 $ -- $ 472 ========== ========== ========== 16. DERIVATIVE AND TRADING ACCOUNTING We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market 104 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we enter into derivative transactions 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 commodities. 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. Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if hedge criteria is met, in common stock equity (as a component of other comprehensive income). We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income. See Note 1 for further discussion on our derivative instrument accounting policy. In 2001, we recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income), both as cumulative effects of a change in accounting for derivatives. The charge primarily resulted from electricity option contracts. The credit resulted from unrealized gains on cash flow hedges. In December 2001, the FASB issued revised guidance on the accounting for electricity contracts with option characteristics and the accounting for contracts that combine a forward contract and a purchased option contract. The effective date for the revised guidance was April 1, 2002. The impact of this guidance was immaterial to our financial statements. During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts and on January 1, 2003 for existing contracts, with early adoption permitted. As a result, our energy trading contracts that are derivatives continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked-to-market as trading activities under EITF 98-10 that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Statements of Income on a net basis. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading activities, which continue to be accounted for in accordance with SFAS No. 133. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. The impact of this guidance was immaterial to our financial statements. 105 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Balance Sheets. For non-trading derivative instruments that qualify for cash flow hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of accumulated other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings. Derivatives associated with trading activities are adjusted to fair value through income. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Conversely, all non-trading contracts and derivatives are to be reported gross on the income statement. Previous guidance under EITF 98-10 permitted non-financially settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the Statements of Income and restated prior year amounts for all periods presented. Reclassification of such trading activity to a net basis of reporting resulted in reductions in both revenues and purchased power and fuel costs, but did not have any impact on our financial condition, results of operations or cash flows. The changes in derivative fair value included in the Statements of Income for the years ended December 31, 2002 and 2001 are comprised of the following (dollars in thousands): 2002 2001 ---------- ---------- Gains/(losses) on the ineffective portion of derivatives qualifying for hedge accounting (a) $ 8,482 $ (6,056) Losses from the discontinuance of cash flow hedges (9,206) (4,683) Losses from non-hedge derivatives (12,645) (7,157) Prior period mark-to-market losses realized upon delivery of commodities 10,413 25,948 ---------- ---------- Total pretax gain/(loss) $ (2,956) $ 8,052 ========== ========== (a) Time value component of options excluded from assessment of hedge effectiveness. As of December 31, 2002, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately two years. During the twelve months ending December 31, 2003, we estimate that a net loss of $26 million before income 106 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions. CREDIT RISK We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of counterparties. Despite the fact that the great majority of trading counterparties 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 earnings for a given period. Counterparties in the portfolio consist principally of 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. 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. Credit valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See "Mark-to-Market Accounting" in Note 1 for a discussion of our credit valuation adjustment policy. 17. OTHER INCOME AND OTHER EXPENSE The following table provides detail of other income and other expense for the years ended December 31, 2002, 2001 and 2000 (dollars in thousands): Year Ended December 31 -------------------------------------- 2002 2001 2000 ---------- ---------- ---------- Other income: Environmental insurance recovery $ -- $ 12,349 $ -- Equity earnings - net -- -- 1,624 Interest income 3,455 5,004 4,924 Miscellaneous 1,694 2,854 3,142 ---------- ---------- ---------- Total other income $ 5,149 $ 20,207 $ 9,690 ========== ========== ========== Other expense: Equity losses - net $ (1,131) $ (3,355) $ -- Non-operating costs (a) (16,424) (14,637) (14,853) Miscellaneous (1,783) (2,798) (5,694) ---------- ---------- ---------- Total other expense $ (19,338) $ (20,790) $ (20,547) ========== ========== ========== (a) As defined by FERC, includes below-the-line non-operating utility costs (primarily community relations and environmental compliance). 107 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 18. VARIABLE INTEREST ENTITIES In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable Interest Entities." FIN No. 46 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. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003. In 1986, we 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. See Note 8 for further information about the sale-leaseback transactions. Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to consolidate the Palo Verde SPEs. However, we will continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements. We are exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that we do 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), we 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 December 31, 2002, we would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million. 19. INTANGIBLE ASSETS On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible Assets." This statement addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, "Intangible Assets." We have no goodwill recorded and have separately disclosed other intangible assets on our Balance Sheets. The intangible assets continue to be amortized over their finite useful lives. Thus, there was no impact on our financial position as a result of the adoption of SFAS No. 142. The Company's gross intangible assets (which are primarily software) were $193 million at December 31, 2002 and $170 million at December 31, 2001. The related accumulated amortization was $100 million at December 31, 2002 and $87 million at December 31, 2001. Amortization expense was $19 million in 2002, $21 million in 2001 and $20 million in 2000. Estimated amortization expense on existing intangible assets over the next five years is $21 million in 2003, $20 million in 2004, $19 million in 2005, $17 million in 2006 and $14 million in 2007. 108 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 20. SUBSEQUENT EVENTS See "ACC Applications" in Note 3 for information regarding the ACC's approval on March 27, 2003 of a $500 million financing arrangement between us and Pinnacle West Energy and "Track B Order" in Note 3 for information regarding the ACC order issued on March 14, 2003, mandating a process by which we must competitively procure energy. See "California Energy Issues and Refunds in the Pacific Northwest" in Note 10 for information regarding the FERC's adoption on March 26, 2003 of an ALJ's proposed findings, and issuance on March 26, 2003 of a Final Report on Price Manipulation in Western Markets. 109 ARIZONA PUBLIC SERVICE COMPANY SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (DOLLARS IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ADDITIONS BALANCE AT CHARGED CHARGED TO BALANCE AT BEGINNING TO COST AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD ----------- --------- --------- -------- ---------- ------- RESERVE FOR UNCOLLECTIBLES Year ended December 31, 2002 $ 3,349 $ 2,680 $ -- $ 4,688 $ 1,341 Year ended December 31, 2001 $ 2,380 $ 7,609 $ -- $ 6,640 $ 3,349 Year ended December 31, 2000 $ 1,538 $ 5,438 $ -- $ 4,596 $ 2,380
110 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Not applicable. ITEM 11. EXECUTIVE COMPENSATION Not applicable. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Not applicable. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Not applicable. 111 ITEM 14. CONTROLS AND PROCEDURES As of a date within 90 days of the date of this report (the "Evaluation Date"), we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer, concluded that, as of the Evaluation Date, our disclosure controls and procedures were adequate to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation, including any corrective actions with regard to significant deficiencies and internal weaknesses. 112 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES See the Index to Financial Statements in Part II, Item 8. EXHIBITS FILED EXHIBIT NO. DESCRIPTION - ----------- ----------- 12.1 -- Computation of Ratio of Earnings to Fixed Charges 23.1 -- Consent of Deloitte & Touche LLP 99.1 -- Certification of Jack E. Davis, the Company's principal executive officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.2 -- Certification of Donald E. Brandt, the Company's principal financial officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.3 -- Risk Factors In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 3.1 Bylaws, amended as of 3.2 to Pinnacle West 1-8962 11-14-02 September 18, 2002 September 2002 Form 10-Q Report 3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95 Directors temporarily Report suspending Bylaws in part 3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93 restated as of May 25, 1988 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report
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EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 4.1 Mortgage and Deed of Trust 4.1 to September 1992 1-4473 11-9-92 Relating to the Company's Form 10-Q Report First Mortgage Bonds, together with forty-eight indentures supplemental thereto 4.2 Forty-ninth Supplemental 4.1 to 1992 Form 10-K 1-4473 3-30-93 Indenture Report 4.3 Fiftieth Supplemental 4.2 to 1993 Form 10-K 1-4473 3-30-94 Indenture Report 4.4 Fifty-first Supplemental 4.1 to August 1, 1993 1-4473 9-27-93 Indenture Form 8-K Report 4.5 Fifty-second Supplemental 4.1 to September 30, 1993 1-4473 11-15-93 Indenture Form 10-Q Report 4.6 Fifty-third Supplemental 4.5 to Registration 1-4473 3-1-94 Indenture Statement No. 33-61228 by means of February 23, 1994 Form 8-K Report 4.7 Fifty-fourth Supplemental 4.1 to Registration 1-4473 11-22-96 Indenture Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report 4.8 Fifty-fifth Supplemental 4.8 to Registration 1-4473 4-9-97 Indenture Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report 4.9 Fifty-sixth Supplemental 4.1 to Pinnacle West 2002 1-8962 3-31-03 Indenture Form 10-K Report 4.10 Fifty-seventh Supplemental 4.2 to Pinnacle West 2002 1-8962 3-31-03 Indenture Form 10-K Report
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EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 4.11 Agreement, dated March 21, 4.1 to 1993 Form 10-K 1-4473 3-30-94 1994, relating to the filing Report of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company's total assets 4.12 Indenture dated as of January 4.6 to Registration 1-4473 1-11-95 1, 1995 among the Company Statement Nos. 33-61228 and The Bank of New York, and 33-55473 by means of as Trustee January 1, 1995 Form 8-K Report 4.13 First Supplemental Indenture 4.4 to Registration 1-4473 1-11-95 dated as of January 1, 1995 Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report 4.14 Indenture dated as of 4.5 to Registration 1-4473 11-22-96 November 15, 1996 among Statements Nos. 33-61228, the Company and The Bank 33-55473, 33-64455 and of New York, as Trustee 333-15379 by means of November 19, 1996 Form 8-K Report 4.15 First Supplemental Indenture 4.6 to Registration 1-4473 11-22-96 Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report 4.16 Second Supplemental Inden- 4.10 to Registration 1-4473 4-9-97 ture dated as of April 1, 1997 Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report 4.17 Indenture dated as of January 4.10 to Registration 1-4473 1-16-98 15, 1998 among the Company Statement Nos. 333-15379 and The Chase Manhattan and 333-27551 by means Bank, as Trustee of January 13, 1998 Form 8-K Report
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EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 4.18 First Supplemental Indenture 4.3 to Registration 1-4473 1-16-98 dated as of January 15, 1998 Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report 4.19 Second Supplemental 4.3 to Registration 1-4473 2-22-99 Indenture dated as of Statement Nos. 333-27551 February 15, 1999 and 333-58445 by means of February 18, 1999 Form 8-K Report 4.20 Third Supplemental Indenture 4.5 to Registration 1-4473 11-5-99 dated as of November 1, 1999 Statement No. 333-58445 by means of November 2, 1999 Form 8-K Report 4.21 Fourth Supplemental Inden- 4.1 to Registration 1-4473 8-4-00 ture dated as of August 1, Statement Nos. 333-58445 2000 and 333-94277 by means of August 2, 2000 Form 8-K Report 4.22 Fifth Supplemental Inden- 4.1 to September 2001 1-4473 11-6-01 ture dated as of October 1, Form 10-Q 2001 4.23 Sixth Supplemental Inden- 4.1 to Registration 1-4473 2-28-02 ture dated as of March 1, Statement Nos. 2002 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report 10.1 Two separate 10.2 to September 1991 1-4473 11-14-91 Decommissioning Trust Form 10-Q Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between the Company and Mellon Bank, N.A., as Decommissioning Trustee
116
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.2 Amendment No. 1 to 10.1 to 1994 Form 10-K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 1) dated as of December 1, 1994 10.3 Amendment No. 2 to 10.4 to 1996 Form 10-K 1-4473 3-28-97 Decommissioning Trust Report Agreement (PVNGS Unit 1) dated as of July 1, 1991 10.4 Amendment No. 1 to 10.2 to 1994 Form 10-K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 3) dated as of December 1, 1994 10.5 Amendment No. 2 to 10.6 to 1996 Form 10-K 1-4473 3-28-97 Decommissioning Trust Report Agreement (PVNGS Unit 3) dated as of July 1, 1991 10.6 Amended and Restated 10.1 to Pinnacle West 1-8962 3-26-92 Decommissioning Trust 1991 Form 10-K Report Agreement (PVNGS Unit 2) dated as of January 31, 1992, among the Company, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2
117
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.7 First Amendment to Amended 10.2 to 1992 Form 10-K 1-4473 3-30-93 and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992 10.8 Amendment No. 2 to 10.3 to 1994 Form 10-K 1-4473 3-30-95 Amended and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of November 1, 1994 10.9 Amendment No. 3 to 10.1 to June 1996 Form 1-4473 8-9-96 Amended and Restated 10-Q Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 10.10 Amendment No. 4 to 10.5 to 1996 Form 10-K 1-4473 3-28-97 Amended and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 10.11 Amendment No. 5 to the 10.1 to Pinnacle West's 1-8962 5-15-02 Amended and Restated March 2002 Form 10-Q Decommissioning Trust Report Agreement (PVNGS Unit 2), dated as of June 30, 2000 10.12 Amendment No. 3 to the 10.2 to Pinnacle West's 1-8962 5-15-02 Decommissioning Trust March 2002 Form 10-Q Agreement (PVNGS Unit Report 1), dated as of March 18, 2002
118
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.13 Amendment No. 6 to the 10.3 to Pinnacle West's 1-8962 5-15-02 Amended and Restated March 2002 Form 10-Q Decommissioning Trust Report Agreement (PVNGS Unit 2), dated as of March 18, 2002 10.14 Amendment No. 3 to the 10.4 to Pinnacle West's 1-8962 5-15-02 Decommissioning Trust March 2002 Form 10-Q Agreement (PVNGS Unit Report 3), dated as of March 18, 2002 10.15 Asset Purchase and Power 10.1 to June 1991 Form 1-4473 8-8-91 Exchange Agreement dated 10-Q Report September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991 10.16 Long-Term Power Trans- 10.2 to June 1991 Form 1-4473 8-8-91 actions Agreement dated 10-Q Report September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 8, 1991 10.17 Contract, dated July 21, 1984, 10.31 to Pinnacle West's 2-96386 3-13-85 with DOE providing for the Form S-14 Registration disposal of nuclear fuel Statement and/or high-level radioactive waste, ANPP 10.18 Amendment No. 1 dated 10.3 to 1995 Form 10-K 1-4473 3-29-96 April 5, 1995 to the Long- Report Term Power Transactions Agreement and Asset Purchase and Power Exchange Agree- ment between PacifiCorp and the Company
119
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.19 Restated Transmission 10.4 to 1995 Form 10-K 1-4473 3-29-96 Agreement between Report PacifiCorp and the Company dated April 5, 1995 10.20 Contract among PacifiCorp, 10.5 to 1995 Form 10-K 1-4473 3-29-96 the Company and United Report States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995 10.21 Reciprocal Transmission 10.6 to 1995 Form 10-K 1-4473 3-29-96 Service Agreement between Report the Company and PacifiCorp dated as of March 2, 1994 10.22 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77 Navajo Tribe of Indians, Registration Statement Four Corners Plant 10.23 Supplemental and Additional 5.02 to Form S-7 2-59644 9-1-77 Indenture of Lease, including Registration Statement amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant 10.24 Amendment and Supplement 10.36 to Registration 1-8962 7-25-85 No. 1 to Supplemental and Statement on Form 8-B of Additional Indenture of Pinnacle West Lease, Four Corners, dated April 25,1985 10.25 Application and Grant of 5.04 to Form S-7 2-59644 9-1-77 multi-party rights-of-way Registration Statement and easements, Four Corners Plant Site
120
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.26 Application and Amendment 10.37 to Registration 1-8962 7-25-85 No. 1 to Grant of multi-party Statement on Form 8-B of rights-of-way and easements, Pinnacle West Four Corners Power Plant Site, dated April 25, 1985 10.27 Four Corners Project 10.7 to Pinnacle West 1-8962 3-14-01 Co-Tenancy Agreement 2000 Form 10-K Report Amendment No. 6 10.28 Application and Grant of 5.05 to Form S-7 2-59644 9-1-77 Arizona Public Service Registration Statement Company rights-of-way and easements, Four Corners Plant Site 10.29 Application and Amendment 10.38 to Registration 1-8962 7-25-85 No. 1 to Grant of Arizona Statement on Form 8-B of Public Service Company Pinnacle West rights-of-way and easements, Four Corners Power Plant Site, dated April 25, 1985 10.30 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70 Units 1, 2, and 3 Registration Statement 10.31 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70 rights-of-way and ease- Registration Statement ments, Navajo Plant 10.32 Water Service Contract 5(l) to Form S-7 2-39442 3-16-71 Assignment with the United Registration Statement States Department of Interior, Bureau of Reclamation, Navajo Plant
121
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.33 Arizona Nuclear Power 10.1 to 1988 Form 10-K 1-4473 3-8-89 Project Participation Agree- Report ment, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto 10.34 Amendment No. 13 dated as 10.1 to March 1991 Form 1-4473 5-15-91 of April 22, 1991, to Arizona 10-Q Report Nuclear Power Project Partici- pation Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improve- ment and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles
122
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.35 Amendment No. 14, to 10.4 to the Pinnacle West 1-8962 8-14-00 Arizona Nuclear Power June 30, 2000 Form 10-Q Project Participation Report Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improve- ment and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles 10.36(c) Facility Lease, dated as of 4.3 to Form S-3 33-9480 10-24-86 August 1, 1986, between Registration Statement State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee 10.37(c) Amendment No. 1, dated as 10.5 to September 1986 1-4473 12-4-86 of November 1, 1986, to Form 10-Q Report by Facility Lease, dated as of means of Amendment No. August 1, 1986, between 1 on December 3, 1986 State Street Bank and Trust Form 8 Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee
123
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.38(c) Amendment No. 2 dated as 10.3 to 1988 Form 10-K 1-4473 3-8-89 of June 1, 1987 to Facility Report Lease dated as of August 1, 1986 between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee 10.39(c) Amendment No. 3, dated as 10.3 to 1992 Form 10-K 1-4473 3-30-93 of March 17, 1993, to Report Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee 10.40 Facility Lease, dated as of 10.1 to November 18, 1986 1-4473 1-20-87 December 15, 1986, between Form 8-K Report State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee 10.41 Amendment No. 1, dated as of 4.13 to Form S-3 1-4473 8-24-87 August 1, 1987, to Facility Registration Statement Lease, dated as of December No. 33-9480 by means of 15, 1986, between State Street August 1, 1987 Form 8-K Bank and Trust Company, as Report successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee
124
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.42 Amendment No. 2, dated as 10.4 to 1992 Form 10-K 1-4473 3-30-93 of March 17, 1993, to Report Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee 10.43(a) Directors' Deferred 10.1 to June 1986 Form 1-4473 8-13-86 Compensation Plan, as 10-Q Report restated, effective January 1, 1986 10.44(a) Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Directors' Deferred Compensation Plan, effective as of January 1, 1993 10.45(a) Third Amendment to the 10.1 to September 1994 1-4473 11-10-94 Arizona Public Service Form 10-Q Company Directors' Deferred Compensation Plan effective as of May 1, 1993 10.46(a) Fourth Amendment dated 10.8 to Pinnacle West's 1-8962 3-30-00 December 28, 1999 to the 1999 Form 10-K Arizona Public Service Company Directors Deferred Compensation Plan
125
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.47(a) Arizona Public Service 10.4 to 1988 Form 10-K 1-4473 3-8-89 Company Deferred Report Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively 10.48(a) Third Amendment to the 10.3 to 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Deferred Compensation Plan, effective as of January 1, 1993 10.49(a) Fourth Amendment to the 10.2 to September 1994 1-4473 11-10-94 Arizona Public Service Form 10-Q Report Company Deferred Compensation Plan effective as of May 1, 1993 10.50(a) Fifth Amendment to the 10.3 to 1997 Form 10-K 1-4473 3-28-97 Arizona Public Service Report Company Deferred Compensation Plan
126
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.51(a) Sixth Amendment to 10.8 to Pinnacle West 1-8962 3-14-01 Arizona Public Service 2000 Form 10-K Report Company Deferred Compensation Plan 10.52(a) Schedules of William J. Post 10.2 to Pinnacle West 1-8962 3-31-03 and Jack E. Davis to Form 10-K Report Arizona Public Service Company Deferred Compensation Plan, as amended 10.53(a) Pinnacle West Capital 10.10 to 1995 Form 10-K 1-4473 3-29-96 Corporation, Arizona Public Report Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996 10.54(a) First Amendment effective as 10.6 to Pinnacle West's 1-8962 3-30-00 of January 1, 1999, to the 1999 Form 10-K Report Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compen- sation Plan 10.55(a) Second Amendment effective 10.10 to Pinnacle West's 1-8962 3-30-00 as of January 1, 2000, to the 1999 Form 10-K Report Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compen- sation Plan
127
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.56(a) Pinnacle West Capital 10.13 to Pinnacle West's 1-8962 3-30-00 Corporation Supplemental 1999 Form 10-K Report Excess Benefit Retirement Plan, as amended and restated, dated December 7, 1999 10.57(a) First Amendment to the 10.7 to Pinnacle West's 1-8962 3-27-02 Pinnacle West Capital 2001 Form 10-K Report Corporation Supplemental Excess Benefit Retirement Plan 10.58(a) Second Amendment to the 10.8 to Pinnacle West's 1-8962 3-27-02 Pinnacle West Capital 2001 Form 10-K Report Corporation Supplemental Excess Benefit Retirement Plan 10.59(a) Pinnacle West Capital 10.7 to 1994 Form 10-K 1-4473 3-30-95 Corporation and Arizona Report Public Service Company Directors' Retirement Plan effective as of January 1, 1995 10.60(a) Pinnacle West Capital 99.2 to Pinnacle West's 1-8962 7-3-00 Corporation and Arizona Registration Statement on Public Service Company Form S-8 No. 333-40796 Directors' Retirement Plan, as amended and restated on June 21, 2000 10.61(a) Arizona Public Service 10.1 to September 1997 1-4473 11-12-97 Company Director Form 10-K Report Equity Plan 10.62(a) Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95 December 21, 1993, between Report the Company and William L. Stewart
128
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.63(a) Letter Agreement dated 10.8 to 1996 Form 10-K 1-4473 3-28-97 August 16, 1996 between Report the Company and William L. Stewart 10.64(a) Letter Agreement between 10.2 to September 1997 1-4473 11-12-97 the Company and Form 10-Q Report William L. Stewart 10.65(a) Letter Agreement dated 10.9 to Pinnacle West's 1-8962 3-30-00 December 13, 1999 between 1999 Form 10-K Report the Company and William L. Stewart 10.66(a) Amendment to Letter 10.1 to Pinnacle West's 1-8962 8-13-02 Agreement, effective as of June 2002 Form 10-Q January 1, 2002, between Report APS and William L. Stewart 10.67(a) Letter Agreement dated as 10.8 to 1995 Form 10-K 1-4473 3-29-96 of January 1, 1996 between Report the Company and Robert G. Matlock & Associates, Inc. for consulting services 10.68(a) Letter Agreement dated 10.17 to Pinnacle West's 1-8962 3-30-00 October 3, 1997 between 1999 Form 10-K Report the Company and James M. Levine 10.69(a) Summary of James M. 10.2 to Pinnacle West's 1-8962 5-15-02 Levine Retirement March 2002 Form Benefits 10-Q Report 10.70(a) Employment Agreement, 10.1 to Pinnacle West's 1-8962 11-14-02 effective as of October 1, November 2002 Form 2002, between APS and 10-Q James M. Levine 10.71(a) Letter Agreement dated 10.4 to Pinnacle West's 1-8962 3-31-03 June 28, 2001 between 2002 Form 10-K Report Pinnacle West Capital Corporation and Steve Wheeler
129
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.72(a)(d) Key Executive Employment 10.1 to Pinnacle West's 1-8962 8-16-99 and Severance Agreement June 1999 Form 10-Q between Pinnacle West and Report certain executive officers of Pinnacle West and its subsidiaries 10.73(a) Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93 Corporation Stock Option Report and Incentive Plan 10.74(a) First Amendment dated 10.11 to Pinnacle West's 1-8962 3-30-00 December 7, 1999 to the 1999 Form 10-K Report Pinnacle West Capital Corporation Stock Option and Incentive Plan 10.75(a) Pinnacle West Capital A to the Proxy Statement 1-8962 4-16-94 Corporation 1994 Long- for the Plan Report Term Incentive Plan Pinnacle West 1994 effective as of Annual Meeting of March 23, 1994 Shareholders 10.76(a) First Amendment dated 10.12 to Pinnacle West's 1-8962 3-30-00 December 7, 1999, to the 1999 Form 10-K Report Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan 10.77(a) Pinnacle West Capital 10.5 to Pinnacle West's 1-8962 3-31-03 Corporation 2002 Long-Term 2002 Form 10-K Report Incentive Plan 10.78(a) Trust for the Pinnacle West 10.14 to Pinnacle West's 1-8962 3-30-00 Capital Corporation, Arizona 1999 Form 10-K Report Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996 10.79(a) First Amendment dated 10.15 to Pinnacle West's 1-8962 3-30-00 December 7, 1999, to the 1999 Form 10-K Report Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans
130
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.80(a) 2003 Management Officer 10.1 to Pinnacle West's 1-8962 3-31-03 Incentive Plan 2002 Form 10-K Report 10.81(a) 2003 CEO Variable 10.2 to Pinnacle West's 1-8962 3-31-03 Incentive Plan 2002 Form 10-K Report 10.82 Agreement No. 13904 (Option 10.3 to 1991 Form 10-K 1-4473 3-19-92 and Purchase of Effluent) Report with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23, 1973 10.83 Agreement for the Sale and 10.4 to 1991 Form 10-K 1-4473 3-19-92 Purchase of Wastewater Report Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981,including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4, 1986 10.84 Territorial Agreement 10.1 to March 1998 1-4473 5-15-98 between the Company Form 10-Q Report and Salt River Project 10.85 Power Coordination 10.2 to March 1998 1-4473 5-15-98 Agreement between Form 10-Q Report the Company and Salt River Project 10.86 Memorandum of Agreement 10.3 to March 1998 1-4473 5-15-98 between the Company and Form 10-Q Report Salt River Project
131
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.87 Addendum to Memorandum 10.2 to May 19, 1998 1-4473 6-26-98 of Agreement between the Form 8-K Report Company and Salt River Project dated as of May 19, 1998 99.1 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93 among PVNGS II Funding Report Corp., Inc., the Company and Chemical Bank, as Trustee 99.2 Supplemental Indenture to 4.3 to 1992 Form 10-K 1-4473 3-30-93 Collateral Trust Indenture Report among PVNGS II Funding Corp., Inc., the Company and Chemical Bank, as Trustee 99.3(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92 dated as of August 1, 1986, Form 10-Q Report among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein
132
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.4(c) Amendment No. 1 dated as 10.8 to September 1986 1-4473 12-4-86 of November 1, 1986, to Form 10-Q Report by Participation Agreement, means of Amendment No. dated as of August 1,1986, 1, on December 3, 1986 among PVNGS Funding Form 8 Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein 99.5(c) Amendment No. 2, dated as 28.4 to 1992 Form 10-K 1-4473 3-30-93 of March 17, 1993, to Report Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein
133
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.6(c) Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86 Security Agreement and Registration Statement Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.7(c) Supplemental Indenture No. 10.6 to September 1986 1-4473 12-4-86 1, dated as of November 1, Form 10-Q Report by 1986 to Trust Indenture, means of Amendment No. Mortgage, Security Agree- 1 on December 3, 1986 ment and Assignment of Form 8 Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.8(c) Supplemental Indenture No. 2 4.4 to 1992 Form 10-K 1-4473 3-30-93 to Trust Indenture, Mortgage, Report Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.9(c) Assignment, Assumption and 28.3 to Form S-3 33-9480 10-24-86 Further Agreement, dated as Registration Statement of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
134
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.10(c) Amendment No. 1, dated 10.10 to September 1986 1-4473 12-4-86 as of November 1, 1986, to Form 10-Q Report by Assignment, Assumption and means of Amendment No. Further Agreement, dated as 1 on December 3, 1986 of August 1, 1986, between Form 8 the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.11(c) Amendment No. 2, dated 28.6 to 1992 Form 10-K 1-4473 3-30-93 as of March 17, 1993, to Report Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.12 Participation Agreement, 28.2 to September 1992 1-4473 11-9-92 dated as of December 15, Form 10-Q Report 1986, among PVNGS Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, the Company, and the Owner Participant named therein
135
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.13 Amendment No. 1, dated 28.20 to Form S-3 1-4473 8-10-87 as of August 1, 1987, to Registration Statement Participation Agreement, No. 33-9480 by means of a dated as of December 15, November 6, 1986 Form 1986, among PVNGS 8-K Report Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, the Company, and the Owner Participant named therein 99.14 Amendment No. 2, dated 28.5 to 1992 Form 10-K 1-4473 3-30-93 as of March 17, 1993, to Report Participation Agreement, dated as of December 15, 1986, among PVNGS Fund- ing Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Owner Participant named therein 99.15 Trust Indenture, Mortgage, 10.2 to November 18, 1986 1-4473 1-20-87 Security Agreement and Form 8-K Report Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
136
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.16 Supplemental Indenture No. 4.13 to Form S-3 1-4473 8-24-87 1, dated as of August 1, 1987, Registration Statement to Trust Indenture, Mortgage, No. 33-9480 by means of Security Agreement and August 1, 1987 Form 8-K Assignment of Facility Report Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.17 Supplemental Indenture 4.5 to 1992 Form 10-K 1-4473 3-30-93 No. 2 to Trust Indenture, Report Mortgage, Security Agree- ment and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.18 Assignment, Assumption and 10.5 to November 18, 1986 1-4473 1-20-87 Further Agreement, dated as Form 8-K Report of December 15, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
137
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.19 Amendment No. 1, dated 28.7 to 1992 Form 10-K 1-4473 3-30-93 as of March 17, 1993, to Report Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.20(c) Indemnity Agreement dated 28.3 to 1992 Form 10-K 1-4473 3-30-93 as of March 17, 1993 by the Report Company 99.21 Extension Letter, dated as of 28.20 to Form S-3 1-4473 8-10-87 August 13, 1987, from the Registration Statement signatories of the No. 33-9480 by means of a Participation Agreement to November 6, 1986 Form Chemical Bank 8-K Report 99.22 Rate Reduction Agreement 10.1 to December 4, 1995 1-4473 12-14-95 dated December 4, 1995 Form 8-K Report between the Company and the ACC Staff 99.23 Arizona Corporation 10.1 to March 1996 1-4473 5-14-96 Commission Order Form 10-Q Report dated April 24, 1996 99.24 Arizona Corporation 99.1 to 1996 Form 10-K 1-4473 3-28-97 Commission Order, Report Decision No. 59943, dated December 26, 1996, including the Rules regard- ing the introduction of retail competition in Arizona 99.25 Retail Electric Competition 10.1 to June 1998 1-4473 8-14-98 Rules Form 10-Q Report
138
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.26 Arizona Corporation 10.1 to September 1999 1-4473 11-15-99 Commission Order, 10-Q Report Decision No. 61973, dated October 6, 1999, approving our Settlement Agreement 99.27 Arizona Corporation 10.2 to September 1999 1-4473 11-15-99 Commission Order, 10-Q Report Decision No. 61969, dated September 29, 1999, includ- ing the Retail Electric Competition Rules 99.28 Addendum to Settlement 10.1 to Pinnacle West 1-8962 11-14-00 Agreement September 2000 10-Q 99.29 ACC Opinion and Order 99.1 to Pinnacle West's 1-8962 9-17-02 dated September 10, 2002, September 10, 2002 Decision No. 65154 Form 8-K Report 99.30 Arizona Public Service 99.2 to Pinnacle West's 1-8962 9-17-02 Company Application filed September 10, 2002 with the Arizona Form 8-K Report Corporation Commission on September 16, 2002 99.31 Track "A" Appeals Issues - 99.1 to Pinnacle West's 1-8962 12-16-02 Principles for Resolution November 15, 2002 Form 8-K Report
- ---------- (a) Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. (b) Reports filed under File No. 1-4473 were filed in the office of the Securities and Exchange Commission located in Washington, D.C. (c) An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit. (d) Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional officers and key employees of the Company. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit. 139 REPORTS ON FORM 8-K During the quarter ended December 31, 2002 and the period ended March 31, 2003, the Company filed the following Reports on Form 8-K: Report dated October 17, 2002 regarding Pinnacle West's earnings outlook. Report dated November 14, 2002 regarding an ACC staff recommendation that the Interim Financing Application be approved. Report dated November 15, 2002 regarding: (i) appeals of the Track A Order and an agreement between APS and the ACC staff; (ii) ACC staff testimony on the Financing Application; and (iii) EITF 02-3. Report dated November 22, 2002 regarding ACC approval of the Interim Financing Application and Pinnacle West Energy's decision to cancel Redhawk Units 3 and 4. Report dated January 15, 2003 regarding NAC losses and Pinnacle West's earnings outlook. Report dated January 30, 2003 regarding an ACC staff report on Track B. Report dated February 24, 2003 regarding reclassifications of revenue from electricity trading activities to a net basis of reporting. Report dated February 27, 2003 regarding the ACC Track B decision. Report dated March 11, 2003 regarding an ACC ALJ recommendation on the Financing Application. Report dated March 27, 2003, regarding ACC approval of a financing arrangement. 140 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY Date: March 31, 2003 (Registrant) Jack E. Davis -------------------------------------- (Jack E. Davis, President and Chief Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date --------- ----- ---- William J. Post Director March 31, 2003 - ------------------------------- (William J. Post, Chairman of the Board of Directors) Jack E. Davis Principal Executive Officer March 31, 2003 - ------------------------------- and Director (Jack E. Davis, President and Chief Executive Officer) Donald E. Brandt Principal Financial Officer March 31, 2003 - ------------------------------- (Donald E. Brandt, Senior Vice President, and Chief Financial Officer) Chris N. Froggatt Principal Accounting Officer March 31, 2003 - ------------------------------- (Chris N. Froggatt, Vice President and Controller) Edward N. Basha, Jr. Director March 31, 2003 - ------------------------------- (Edward N. Basha, Jr.) 141 Michael L. Gallagher Director March 31, 2003 - ------------------------------- (Michael L. Gallagher) Pamela Grant Director March 31, 2003 - ------------------------------- (Pamela Grant) Roy A. Herberger, Jr. Director March 31, 2003 - ------------------------------- (Roy A. Herberger, Jr.) Martha O. Hesse Director March 31, 2003 - ------------------------------- (Martha O. Hesse) William S. Jamieson, Jr. Director March 31, 2003 - ------------------------------- (William S. Jamieson, Jr.) Humberto S. Lopez Director March 31, 2003 - ------------------------------- (Humberto S. Lopez) Robert G. Matlock Director March 31, 2003 - ------------------------------- (Robert G. Matlock) Kathryn L. Munro Director March 31, 2003 - ------------------------------- (Kathryn L. Munro) Bruce J. Nordstrom Director March 31, 2003 - ------------------------------- (Bruce J. Nordstrom) CERTIFICATIONS I, Jack E. Davis, certify that: 1. I have reviewed this annual report on Form 10-K of Arizona Public Service Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 142 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 31, 2003. Jack E. Davis ---------------------------------------- Jack E. Davis President and Chief Executive Officer I, Donald E. Brandt, certify that: 1. I have reviewed this annual report on Form 10-K of Arizona Public Service Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 143 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 31, 2003. Donald E. Brandt ---------------------------------------- Donald E. Brandt Senior Vice President and Chief Financial Officer 144 EX-12.1 4 ex12-1.txt COMPUTATION OF EARNINGS TO FIXED CHARGES Exhibit 12.1 ARIZONA PUBLIC SERVICE COMPANY Computation of Earnings to Fixed Charges ($000's)
2002 2001 2000 1999 1998 ---------- ---------- ---------- ---------- ---------- Income From Continuing Operations $ 199,343 $ 280,688 $ 306,594 $ 268,322 $ 255,247 Income Taxes 126,805 183,136 195,665 133,015 133,452 Fixed Charges 168,985 166,939 179,381 179,088 183,398 ---------- ---------- ---------- ---------- ---------- Total $ 495,133 630,763 681,640 580,425 572,097 Fixed Charges: Interest Charges 133,878 130,525 141,886 140,948 144,695 Amortization of Debt Discount 2,888 2,650 2,105 2,084 2,410 Estimated Interest Portion of Annual Rents 32,219 33,764 35,390 36,056 36,293 ---------- ---------- ---------- ---------- ---------- Total Fixed Charges 168,985 166,939 179,381 179,088 183,398 Ratio of Earnings to Fixed Charges (rounded down) 2.93 3.77 3.79 3.24 3.11 ========== ========== ========== ========== ==========
EX-23.1 5 ex23-1.txt CONSENT OF DELOITTE & TOUCHE LLP Exhibit 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-51085 and 333-90824 of Arizona Public Service Company on Form S-3 and in Registration Statement 333-46161 of Arizona Public Service Company on Form S-8 of our report dated February 3, 2003 (March 14, 26 and 27, 2003 as to Note 20) (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in 2001 in the method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES) appearing in this Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 2002. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona March 27, 2003 EX-99.1 6 ex99-1.txt CERTIFICATION OF JACK E. DAVIS Exhibit 99.1 FORM OF CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (JACK E. DAVIS) I, Jack E. Davis, President and Chief Executive Officer of Arizona Public Service Company ("APS"), certify, to the best of my knowledge, that: (a) the attached Annual Report on Form 10-K of APS for the fiscal year ended December 31, 2002 (the "December 2002 Form 10-K") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (b) the information contained in the December 2002 Form 10-K Report fairly presents, in all material respects, the financial condition and results of operations of APS. Jack E. Davis ---------------------------------------- Jack E. Davis President and Chief Executive Officer Date: March 31, 2003 EX-99.2 7 ex99-2.txt CERTIFICATION OF DONALD E. BRANDT Exhibit 99.2 FORM OF CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (DONALD E. BRANDT) I, Donald E. Brandt, Senior Vice President and Chief Financial Officer, of Arizona Public Service Company ("APS"), certify, to the best of my knowledge, that: (a) the attached Annual Report on Form 10-K of APS for the fiscal year ended December 31, 2002 (the "December 2002 Form 10-K") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (b) the information contained in the December 2002 Form 10-K Report fairly presents, in all material respects, the financial condition and results of operations of APS. Donald E. Brandt ---------------------------------------- Donald E. Brandt Senior Vice President and Chief Financial Officer Date: March 31, 2003 EX-99.3 8 ex99-3.txt RISK FACTORS Exhibit 99.3 RISK FACTORS Set forth below and in other documents we file with the SEC are risks and uncertainties that could affect our financial results. IF WE ARE NOT ABLE TO ACCESS CAPITAL AT COMPETITIVE RATES, OUR ABILITY TO IMPLEMENT OUR FINANCIAL STRATEGY WILL BE ADVERSELY AFFECTED. We rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of our credit rating may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include: * an economic downturn; * capital market conditions generally; * the bankruptcy of an unrelated energy company; * market prices for electricity and gas; * terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies; or * the overall health of the utility industry. Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by: * increasing the cost of future debt financing; * increasing our vulnerability to adverse economic and industry conditions; * requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; and * placing us at a competitive disadvantage compared to our competitors that have less debt. See the following Risk Factor for more information relating to this discussion. A SIGNIFICANT REDUCTION IN OUR CREDIT RATINGS COULD MATERIALLY AND ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS. We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing costs which would diminish our financial results. We would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. A downgrade could require additional support in the form of letters of credit or cash or other collateral and otherwise have a material adverse effect on our business, financial condition and results of operations. If our short-term ratings were to be lowered, it could limit our access to the commercial paper market. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating. DEREGULATION OR RESTRUCTURING OF THE ELECTRIC INDUSTRY MAY RESULT IN INCREASED COMPETITION, WHICH COULD HAVE A SIGNIFICANT ADVERSE IMPACT ON OUR BUSINESS AND OUR FINANCIAL RESULTS. Retail competition could have a significant adverse financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. In 1999, the ACC approved rules that provide a framework for the introduction of retail electric competition in Arizona. Under the rules, as modified by a 1999 settlement agreement among us and various parties, we were required to transfer all of our competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. Pursuant to an ACC order dated September 10, 2002, the ACC unilaterally modified the 1999 settlement agreement and directed us to cancel any plans to divest interests in any of our generating assets. The ACC has further established a requirement that we solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. These regulatory developments and legal challenges to the rules have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory. As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, and wholesale power marketers and brokers. This increased competition could affect our load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and the relatively low barriers to entry, we expect wholesale competition to increase. As competition continues to increase, our financial position and results of operations could be adversely affected. 2 THE PROCUREMENT OF WHOLESALE POWER BY US WITHOUT THE ABILITY TO ADJUST RETAIL RATES COULD HAVE AN ADVERSE IMPACT ON OUR BUSINESS AND FINANCIAL RESULTS. A 1999 settlement agreement limits our ability to change retail rates until at least July 1, 2004, which could have a significant adverse financial impact on us if wholesale power prices significantly exceed the amount included for generation costs in our current bundled retail rates. Under the ACC's rules, we are the "provider of last resort" for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 settlement agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount of generation costs per kilowatt hour (kWh) included in our current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. The ACC has further established a requirement that we solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. This competitive procurement process may adversely affect the cost of our procurement of wholesale power. In sum, there can be no assurance that we would be able to fully recover the costs of wholesale power under our present rate structure. Although we could seek to adjust our rates under the emergency provisions of the settlement agreement discussed above, ACC approval of such an adjustment also cannot be assured. WE ARE SUBJECT TO COMPLEX GOVERNMENT REGULATION WHICH MAY HAVE A NEGATIVE IMPACT ON OUR BUSINESS AND OUR RESULTS OF OPERATIONS. We are subject to governmental regulation which may have a negative impact on our business and results of operations. We are a "subsidiary company" of a "holding company" within the meaning of the Public Utility Holding Company Act ("PUHCA"); however, we are exempt from the provisions of PUHCA by virtue of the filing of an annual exemption statement with the SEC by our parent company, Pinnacle West Capital Corporation. We are subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. The Federal Energy Regulatory Commission ("FERC"), the Nuclear Regulatory Commission ("NRC"), the Environmental Protection Agency ("EPA"), and the Arizona Corporation Commission ("ACC") regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. We believe the necessary permits, approvals and certificates have been obtained for our existing operations. However, we are unable to predict the impact on our business and operating results from the future regulatory activities of any of 3 these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations. RECENT EVENTS IN THE ENERGY MARKETS THAT ARE BEYOND OUR CONTROL MAY HAVE NEGATIVE IMPACTS ON OUR BUSINESS. As a result of the energy crisis in California during the summer of 2001, the recent volatility of natural gas prices in North America, the filing of bankruptcy by the Enron Corporation, and investigations by governmental authorities into energy trading activities, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. The capital markets and ratings agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws, but it is difficult or impossible to predict or control what effect these or related issues may have on our business or our access to the capital markets. OUR RESULTS OF OPERATIONS CAN BE ADVERSELY AFFECTED BY MILDER WEATHER. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our overall operating results fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish our results of operations and harm our financial condition. THERE ARE INHERENT RISKS IN THE OPERATION OF NUCLEAR FACILITIES, SUCH AS ENVIRONMENTAL, HEALTH AND FINANCIAL RISKS AND THE RISK OF TERRORIST ATTACK. We have an ownership interest in and operate the Palo Verde Nuclear Generating Station ("Palo Verde"). Palo Verde is subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks. We maintain nuclear decommissioning trust funds and external insurance coverage to minimize our financial exposure to these risks; however, it is possible that damages could exceed the amount of insurance coverage. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. 4 The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict. THE USE OF DERIVATIVE CONTRACTS IN THE NORMAL COURSE OF OUR BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS. Our operations include managing market risks related to commodity prices, changes in interest rates, and investments held by our pension plan and nuclear decommissioning trust funds. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances and credits. We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions 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 commodity. We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties 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 adverse impact on our earnings for a given period. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our pension plan and nuclear decommissioning trust funds. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan and nuclear decommissioning trust funds also have risks associated with changing market values of equity investments. Most of the pension costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices. THE UNCERTAIN OUTCOME REGARDING THE CREATION OF REGIONAL TRANSMISSION ORGANIZATIONS, OR RTOS, MAY MATERIALLY IMPACT OUR OPERATIONS, CASH FLOWS OR FINANCIAL POSITION. In a December 1999 order, the FERC set minimum characteristics and functions that must be met by utilities that participate in regional transmission organizations. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and nondiscriminatory markets, and exclusive authority to maintain short-term reliability. On October 16, 2001, we and other owners of electric transmission lines in the Southwest filed with the FERC a request for a declaratory order confirming that our proposal to form WestConnect RTO, LLC would satisfy the FERC's requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC's RTO requirements and provide the basic framework for a standard market design for the Southwest. As 5 of March 28, 2003, the FERC was considering various aspects of its order as a result of requests for clarification filed by the WestConnect applicants. WE ARE SUBJECT TO NUMEROUS ENVIRONMENTAL LAWS AND REGULATIONS WHICH MAY INCREASE OUR COST OF OPERATIONS, IMPACT OUR BUSINESS PLANS, OR EXPOSE US TO ENVIRONMENTAL LIABILITIES. We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise. In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations. 6 -----END PRIVACY-ENHANCED MESSAGE-----