-----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, PADP415Irh3eiwZlvYcfjQ2SLZVRc0Gg7v2P1Wtta/HqO+Zha5vb/JLGzrInYfki PvtKJ3xM33ePyeCjrElMPQ== 0000950147-03-000433.txt : 20030331 0000950147-03-000433.hdr.sgml : 20030331 20030331150000 ACCESSION NUMBER: 0000950147-03-000433 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PINNACLE WEST CAPITAL CORP CENTRAL INDEX KEY: 0000764622 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 860512431 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-08962 FILM NUMBER: 03629630 BUSINESS ADDRESS: STREET 1: 400 E VAN BUREN ST PO BOX 52132 STREET 2: P O BOX 52132 CITY: PHOENIX STATE: AZ ZIP: 85072-2132 BUSINESS PHONE: 6022501000 MAIL ADDRESS: STREET 1: 400 E VAN BUREN ST STREET 2: PO BOX 52132 CITY: PHOENIX STATE: AZ ZIP: 85072-2132 FORMER COMPANY: FORMER CONFORMED NAME: AZP GROUP INC DATE OF NAME CHANGE: 19870506 10-K 1 e-9738.txt ANNUAL REPORT FOR THE YEAR 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 1-8962 PINNACLE WEST CAPITAL CORPORATION (Exact name of registrant as specified in its charter) ARIZONA 86-0512431 (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 400 North Fifth Street, P.O. Box 53999 (602) 250-1000 Phoenix, Arizona 85072-3999 (Registrant's telephone number, (Address of principal executive including area code) offices, including zip code) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: ================================================================================ Name Of Each Exchange On Title Of Each Class Which Registered - -------------------------------------------------------------------------------- Common Stock, New York Stock Exchange No Par Value Pacific Stock Exchange ================================================================================ SECURITIES REGISTERED PURSUANT TO SECTION 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 definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or 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 [X] No [ ] State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter: $3,348,326,875 as of June 28, 2002 ================================================================================ DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 21, 2003 are incorporated by reference into Part III hereof. ================================================================================ TABLE OF CONTENTS PAGE GLOSSARY..................................................................... 1 PART I Item 1. Business.......................................................... 4 Item 2. Properties........................................................ 22 Item 3. Legal Proceedings................................................. 27 Item 4. Submission of Matters to a Vote of Security Holders............... 27 Supplemental Item. Executive Officers of the Registrant.............................. 28 PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters............................................. 30 Item 6. Selected Consolidated Financial Data.............................. 31 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations....................................... 35 Item 7A. Quantitative and Qualitative Disclosures about Market Risk........ 71 Item 8. Financial Statements and Supplementary Data....................... 73 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................................139 PART III Item 10. Directors and Executive Officers of the Registrant................139 Item 11. Executive Compensation............................................139 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters...................................139 Item 13. Certain Relationships and Related Transactions....................141 Item 14. Controls and Procedures...........................................142 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..142 SIGNATURES...................................................................173 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, a subsidiary of the Company APS Energy Services - APS Energy Services Company, Inc., a subsidiary of the Company 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 - Pinnacle West Capital Corporation CPUC - California Public Utility Commission DOE - United States Department of Energy EITF - the FASB's Emerging Issues Task Force El Dorado - El Dorado Investment Company, a subsidiary of the Company EPA - United States Environmental Protection Agency ERMC - the Company's Energy Risk Management Committee FASB - Financial Accounting Standards Board FERC - United States Federal Energy Regulatory Commission FIN - FASB Interpretation Financing Application - APS 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 - APS 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 NAC - NAC International Inc., a subsidiary of El Dorado 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, the Company Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the Company 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 SNWA - Southern Nevada Water Authority SPE - special-purpose entity Standard & Poor's - Standard & Poor's Corporation SunCor - SunCor Development Company, a subsidiary of the Company Superfund - Comprehensive Environmental Response, Compensation and Liability Act System - non-trading energy related activities T&D - transmission and distribution 2 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 3 PART I ITEM 1. BUSINESS CURRENT STATUS GENERAL We were incorporated in 1985 under the laws of the State of Arizona and own all of the outstanding equity securities of APS. APS is 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 one-half of the Phoenix metropolitan area. Electricity is delivered through a distribution system owned by APS. APS also generates, sells and delivers electricity to wholesale customers in the western United States. Our other major subsidiaries are: * Pinnacle West Energy, through which we conduct our competitive electricity generation operations; * APS Energy Services, which provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States; * SunCor, a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah; and * El Dorado, which owns a majority interest in NAC (specializing in spent nuclear fuel technology) and holds miscellaneous small investments, including interests in Arizona community-based ventures. We discuss each of these subsidiaries in greater detail below. MARKETING AND TRADING In early 2003, we moved our marketing and trading division from Pinnacle West to APS 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 APS' generating assets to Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" below). The marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS' Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. The division focuses primarily on managing APS' purchased power and fuel risks in connection with its 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 APS' implementation of an 4 ACC-mandated process by which APS 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 three principal business segments (determined by products, services and the regulatory environment): * our regulated electricity segment (76% 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; * our marketing and trading segment (12% of operating revenues in 2002), which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services' commodity-related energy services; and * our real estate segment (9% of operating revenues in 2002), which consists of SunCor's real estate development and investment activities. See Note 17 of Notes to Consolidated Financial Statements in Item 8 for financial information about our business segments. EMPLOYEES At December 31, 2002, we employed about 7,200 people, including the employees of our subsidiaries. Of these employees, about 5,100 were employees of our major subsidiary, APS, and employees assigned to jointly-owned generating facilities for which APS serves as the generating facility manager. About 2,100 people were employed by Pinnacle West and our other subsidiaries. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). 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 APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its 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, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its generation assets to Pinnacle West Energy on or before that 5 date. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed APS not to transfer its generation assets to Pinnacle West Energy. See Note 3 of Notes to Consolidated 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. APS FINANCING APPLICATION On September 16, 2002, APS filed an application with the ACC requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or a combination of both, not to exceed $500 million in the aggregate. In its application, APS stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS 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 we 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 of Notes to Consolidated Financial Statements in Item 8 for additional information. COMPETITIVE PROCUREMENT PROCESS 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. Under the order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS 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 APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' 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 APS' right to reject any bids that are unreasonable, uneconomical or unreliable. APS expects 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 APS' electricity requirements. See "Track B Order" in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional information. APS GENERAL RATE CASE As required by the 1999 Settlement Agreement, on or before June 30, 2003, APS will file a general rate case with the ACC. In this rate case, APS will update its cost of service and rate design. In addition, APS expects to seek: 6 * 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 APS as a result of the 1999 Settlement Agreement; and * recovery of costs incurred by APS 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. AVAILABLE INFORMATION We make available free of charge on or through our Internet website (www.pinnaclewest.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information on our website is not part of this report. 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; 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; the successful completion of our generation construction program; regulatory issues associated with generation construction, such as permitting and licensing; 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; the strength of the real estate market in SunCor's market areas, which include Arizona, New Mexico and Utah; and other uncertainties, all of which are difficult to predict and many of which are beyond our control. 7 REGULATION AND COMPETITION RETAIL The ACC regulates APS' retail electric rates and its issuance of securities. The ACC must also approve any transfer of APS' utility property and certain transactions between APS 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 Consolidated Financial Statements in Item 8 for a discussion of the status of electric industry restructuring in Arizona. APS is 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). APS also faces 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 APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete effectively in a restructured industry. WHOLESALE GENERAL The FERC regulates rates for wholesale power sales and transmission services. During 2002, approximately 20% of our electric operating revenues resulted from such sales and services. In early 2003, we moved our marketing and trading division from Pinnacle West to APS 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 APS' generating assets to Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" above). The marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS' Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. The division focuses primarily on managing APS' purchased power and fuel risks in connection with its costs of serving retail customer energy requirements. See "Track B Order" in Note 3 of Notes to Consolidated Financial Statements in Item 8 for information regarding an ACC-mandated process by which APS must competitively procure energy. See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding our generation construction plans. 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 8 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, APS 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. APS 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 APS 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 Consolidated Financial Statements in Item 8 for additional information regarding the Notice of Proposed Rulemaking). On November 12, 2002, APS 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 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 the 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 9 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 APS should be required to continue funding the AISA. BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY Following is a discussion of the business of APS, our major subsidiary. GENERAL APS was incorporated in 1920 under the laws of Arizona and currently has more than 902,000 customers. APS 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 one-half of the Phoenix metropolitan area. Electricity is delivered through a distribution system that APS owns. APS also generates, sells and delivers electricity to wholesale customers in the western United States. APS' marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy's generation output that is not needed for APS' Native Load, which includes loads for retail customers and cost-of-service wholesale customers. APS does not distribute any products. During 2002, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 4% of consolidated electric revenues. At December 31, 2002, APS employed approximately 5,100 people, which includes employees assigned to jointly-owned generating facilities for which APS serves as the generating facility manager. APS' principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). PURCHASED POWER AND GENERATING FUEL See "Properties - Capacity" in Item 2 for information about our power plants by fuel types. 2002 ENERGY MIX Our consolidated sources of energy during 2002 were: purchased power - 49.9% (approximately 90% of which was for wholesale power operations); coal - 23.8%; nuclear -17.7%; gas - 8.5%; and other (includes oil, hydro and solar) - 0.1%. 10 APS' 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 APS. APS purchases 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. APS purchases a portion of Cholla's coal requirements on the spot market to take advantage of competitive pricing options. Following expiration of current contracts, APS believes 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 APS. APS purchases 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 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 - Capacity" in Item 2 for information about APS' ownership interest in Cholla, Four Corners and the Navajo Generating Station. See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding our coal mine reclamation obligations. NATURAL GAS SUPPLY APS and Pinnacle West Energy purchase the majority of their natural gas requirements for their gas-fired plants under contracts with a number of natural gas suppliers. APS' and Pinnacle West Energy's 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 the gas transportation rights of APS and Pinnacle West Energy (and other companies with the same contract type) could be significantly impacted. Various parties, including APS and Pinnacle West Energy, 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 11 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. APS 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. APS 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 APS. The fuel cycle for Palo Verde is comprised of the following stages: * 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 12 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). APS has existing fuel storage pools at Palo Verde and has 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, APS believes 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 11 of Notes to Consolidated 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, APS is currently shipping low-level waste to off-site facilities. APS currently believes 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. APS believes that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, APS acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which APS is less able to predict. APS expects to vigorously protect and pursue its rights related to this matter. PURCHASED POWER AGREEMENTS In addition to that available from its own generating capacity (see "Properties" in Item 2), APS purchases 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 APS is based in large part on customer demand within certain areas now served by APS pursuant to a related territorial agreement. The generating capacity available to APS pursuant to the contract was 336 MW from January through May 2002, and starting in June 2002, it changed to 343 MW. In 2002, APS 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. APS may also cancel the contract on five years' notice, given no earlier than December 31, 2006. In September 1990, APS entered into a thirty-year seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS 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, APS received approximately 571,392 MWh of energy under the capacity exchange. APS 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. 13 CONSTRUCTION PROGRAM During the years 2000 through 2002, APS incurred approximately $1.4 billion in capital expenditures. APS' 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. APS' capital expenditures were approximately $501 million in 2002. APS' 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 ======= ======= 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 APS' generation (production) assets. APS conducts a continuing review of its 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 APS' construction program and for information about Pinnacle West Energy's generation construction plans. MORTGAGE REPLACEMENT FUND REQUIREMENTS So long as any of its first mortgage bonds are outstanding, APS is required for each calendar year to deposit with the trustee under its mortgage cash in a formularized amount related to net additions to its mortgaged utility plant. APS 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 APS has issued under the mortgage that are callable prior to maturity are redeemable at their par value plus accrued interest with cash APS deposits 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 Consolidated Financial Statements in Item 8 for information regarding APS' 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 14 * 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 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 15 how the State of Arizona and/or EPA Region IX will proceed to implement the Annex, so the actual impact on APS 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, APS currently cannot estimate the capital expenditures, if any, which would result from the final rules. However, APS does not currently expect these rules to have a material adverse effect on its 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 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 APS to make related expenditures, such as permit fees. APS does not expect any of these expenditures to have a material impact on its 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. APS does not currently expect the FIP to have a material impact on its 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 APS that the EPA considers APS to be a PRP in the Indian Bend Wash Superfund Site, South Area. APS' 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, APS does not expect this matter to have a material impact on its financial position, results of operations or liquidity. MANUFACTURED GAS PLANT SITES APS is currently investigating properties which it now owns or which were previously owned by it or its 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 * APS has any responsibility for remedial action. 16 Where appropriate, APS has begun clean-up of certain of these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or liquidity. ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY ADEQ issued to APS 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 APS to achieve and document compliance with specific environmental requirements. APS has 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 APS that the ADEQ expects to take enforcement action against APS regarding the violations included in the NOVs, as well as related violations. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or liquidity. 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. APS is the Four Corners operating agent. APS owns a 100% interest in Four Corners Units 1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. APS owns 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 17 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. APS 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. APS believes that the Clean Air Act does not supersede these pre-existing agreements. APS 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. WATER SUPPLY Assured supplies of water are important for our generating plants. At the present time, APS has adequate water to meet its 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 APS' operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is 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 its allocation to offset the loss. A summons served on APS 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. APS' 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, APS 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, APS seeks confirmation of such rights. Three of APS' other power plants and two of Pinnacle West Energy's power plants are also located within the geographic area subject to the summons. APS' claims dispute the court's jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks 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 18 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 APS' water rights claims has been set in this matter. APS has 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). APS' groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. APS' claims dispute the court's jurisdiction over its groundwater rights. Alternatively, APS seeks 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 APS' water rights claims has been set in this matter. Although the foregoing matters remain subject to further evaluation, APS expects that the described litigation will not have a material adverse impact on its 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. BUSINESS OF PINNACLE WEST ENERGY CORPORATION Pinnacle West Energy was incorporated in 1999 under the laws of the State of Arizona and is engaged principally in the development of generating plants and production of wholesale electricity. Pinnacle West Energy is the subsidiary through which we conduct our competitive generation operations. Pinnacle West Energy had approximately 100 employees as of December 31, 2002. Pinnacle West Energy's principal offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone (602) 250-4145). Pinnacle West Energy's capital expenditures in 2002 were $374 million. Projected capital expenditures are $268 million in 2003; $31 million in 2004; and $20 million in 2005. These amounts exclude capitalized interest costs and include capitalized property taxes. These capital expenditures do not reflect an expected reimbursement in 2004 by SNWA of about $100 million of Pinnacle West Energy's cumulative capital expenditures for the Silverhawk project in exchange for SNWA's option to purchase a 25% interest in the project. Pinnacle West Energy's Arizona plants were built as a result of what we believed was a regulatory restriction against APS construction of additional plants and based on the requirement in the 1999 Settlement Agreement that APS 19 transfer its generation assets. The amounts in the preceding paragraph relate only to Pinnacle West Energy's generation assets. As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Affecting Our Financial Outlook" in Item 7, as part of its 2003 general rate case, APS intends 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). At December 31, 2002, Pinnacle West Energy had total assets of $1.2 billion. Pinnacle West Energy reported a net loss of $19 million in 2002, net income of $18 million in 2001 and a net loss of $2 million in 2000. 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 APS' implementation of an ACC-mandated process by which APS must competitively procure energy. See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding Pinnacle West Energy's generation construction plans. BUSINESS OF APS ENERGY SERVICES COMPANY, INC. APS Energy Services was incorporated in 1998 under the laws of the State of Arizona and provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States. APS Energy Services had approximately 100 employees as of December 31, 2002. APS Energy Services' principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone (602) 250-5000). APS Energy Services reported pretax income of $28 million in 2002 and pretax losses of $10 million in 2001 and $13 million in 2000. Income taxes related to APS Energy Services are recorded by the parent company. At December 31, 2002, APS Energy Services had total assets of $90 million. BUSINESS OF SUNCOR DEVELOPMENT COMPANY SunCor was incorporated in 1965 under the laws of the State of Arizona and is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah. The principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410 Tempe, Arizona 85281 (telephone (480) 317-6800). SunCor and its subsidiaries had approximately 800 full- and part-time employees at December 31, 2002. SunCor's assets consist primarily of land with improvements, commercial buildings and other real estate investments. SunCor's largest project is the Palm Valley master-planned community, which has approximately 6,900 acres remaining to be developed west of Phoenix in the area of the towns of Avondale, Goodyear and Litchfield Park, Arizona. SunCor has completed the master plan for development of Palm Valley. SunCor projects under development include seven master-planned communities and several commercial projects. The commercial projects and five of the master-planned communities are in Arizona. Other master-planned communities are located near St. George, Utah, and Santa Fe, New Mexico. Several of the master-planned communities and commercial projects are joint ventures with other developers, financial partners or landowners. SunCor opened two new projects in 2002: 20 * Hayden Ferry Lakeside - an 18-acre, mixed-use commercial and residential project located in Tempe, Arizona that opened its first office building in July 2002; and * StoneRidge - an 1,850-acre, master-planned community with a golf course in Prescott Valley, Arizona that opened its initial phase of home and lot sales and its golf course in 2002. For the past three years, SunCor's operating revenues were about: $236 million in 2002; $169 million in 2001; and $158 million in 2000. For those same periods, SunCor's net income was about: $19 million in 2002; $3 million in 2001; and $11 million in 2000. SunCor's capital needs consist primarily of capital expenditures for land development and home construction for SunCor's home-building subsidiary, Golden Heritage Homes, Inc. SunCor's capital expenditures were approximately $72 million in 2002. On the basis of projects currently under development, SunCor expects its capital needs over the next three years to be: $64 million in 2003; $23 million in 2004; and $20 million in 2005. At December 31, 2002, SunCor had total assets of about $534 million. See Note 6 of Notes to Consolidated Financial Statements in Item 8 for information regarding SunCor's long-term debt. SunCor intends to continue its focus on real estate development of master-planned communities, mixed-use residential, commercial, office and industrial projects. As discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7, we are undertaking an aggressive effort to accelerate SunCor's asset sales activities to approximately double SunCor's annual earnings in the 2003 to 2005 period (compared with $19 million in earnings recorded in 2002) and to permit SunCor to make annual cash distributions to Pinnacle West of $80 - $100 million during that same period. BUSINESS OF EL DORADO INVESTMENT COMPANY El Dorado was incorporated in 1983 under the laws of the State of Arizona. At December 31, 2002, El Dorado owned a majority interest in NAC, a company specializing in spent nuclear fuel technology, and also held miscellaneous small investments, including interests in Arizona community-based ventures. El Dorado's short-term goal is to prudently realize the value of its existing investments. On a long-term basis, we may use El Dorado, when appropriate, as our subsidiary for investments that are strategic to our principal business of generating, distributing and marketing electricity. El Dorado's offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone (602) 250-3517). El Dorado had approximately 100 employees (all NAC) as of December 31, 2002. El Dorado reported a pretax loss of $55 million in 2002 (during 2002, income tax benefits related to El Dorado were recorded by the parent company) and net income of $0.2 million in 2001 and $2 million in 2000. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 and Note 22 of Notes to Consolidated Financial Statements in Item 8 for information regarding El Dorado's 2002 losses. At December 31, 2002, El Dorado had total assets of $36 million. 21 ITEM 2. PROPERTIES CAPACITY Our generating facilities are described below. For APS' plants, the "net accredited capacities" are reported, consistent with industry practice for regulated utilities. For Pinnacle West Energy, the "permitted capacities" are reported, consistent with industry practice for unregulated plants. APS - NET ACCREDITED CAPACITY APS' 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 APS facilities ......................................... 3,983,900 ========= PINNACLE WEST ENERGY - PERMITTED CAPACITIES Pinnacle West Energy's present generating facilities have permitted capacities as follows: Gas or Oil: Two combined cycle units at Redhawk and one combined-cycle unit at West Phoenix .............................................. 1,180,000(b) One combustion turbine unit at Saguaro ......................... 80,000 --------- Total Pinnacle West Energy facilities .......................... 1,260,000 ========= - ---------- (a) Does not include West Phoenix steam units (108,300 kW), which were retired in December 2002. (b) See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding Pinnacle West Energy's generation construction plans. 22 RESERVE MARGIN APS' 2002 peak one-hour demand on its 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 APS under long-term purchase power contracts as well as APS' and Pinnacle West Energy's generating capacity, APS' 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 APS from its 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 "Business of Arizona Public Service Company - Purchased Power Agreements" in Item 1 for information about certain of APS' 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 9 of Notes to Consolidated 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 APS, 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, 23 renewables, etc. "Non-bypassable" means that if a customer chooses to take energy from an "energy service provider" other than APS, the customer will still have to pay this charge as part of the customer's APS electric bill. Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on the external sinking fund mechanism are not met. APS currently relies on the external sinking fund mechanism to meet the NRC financial assurance requirements for its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS' 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 APS to maintain its external sinking fund mechanism. See Note 12 of Notes to Consolidated 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 11 of Notes to Consolidated Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde. PROPERTY NOT HELD IN FEE OR SUBJECT TO ENCUMBRANCES JOINTLY-OWNED FACILITIES APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS' interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2002: PERCENT OWNED BY APS ------------ 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) 24 (a) PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned. (b) Weighted average of interests. PALO VERDE LEASES In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. APS accounts 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 9 and 20 of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale-leaseback transactions. APS FIRST MORTGAGE LIEN APS' 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 Consolidated Financial Statements in Item 8 for information regarding APS' 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. INFORMATION REGARDING PROPERTIES OF PINNACLE WEST ENERGY AND SUNCOR See "Business of Pinnacle West Energy Corporation" and "Business of SunCor Development Company" for information regarding Pinnacle West Energy's and SunCor's properties. 25 [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. 26 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 Consolidated Financial Statements in Item 8 for a discussion of the ACC retail electric competition Rules, the Track A Order and related litigation. See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information relating to the FERC proceedings on California energy market issues and a claim by Citizens that APS overcharged Citizens under a power service agreement. See also Note 22 of Notes to Consolidated Financial Statements in Item 8 for information relating to a breach of contract claim by Maine Yankee against Pinnacle West and NAC. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 27 SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE REGISTRANT Our executive officers are as follows: Name Age at March 1, 2003 Position(s) at March 1, 2003 - ---- -------------------- ---------------------------- William J. Post 52 Chairman of the Board and Chief Executive Officer (1) Jack E. Davis 56 President, and President and Chief Executive Officer, APS (1) Robert S. Aiken 46 Vice President, Federal Affairs John G. Bohon 57 Vice President, Corporate Services & Human Resources Donald E. Brandt 48 Senior Vice President and Chief Financial Officer Dennis L. Brown 52 Vice President and Chief Information Officer Armando B. Flores 59 Executive Vice President, Corporate Business Services Edward Z. Fox 49 Vice President, Communications, Environment & Safety Barbara M. Gomez 48 Treasurer James M. Levine 53 Executive Vice President, APS and President, Pinnacle West Energy Nancy C. Loftin 49 Vice President, General Counsel and Secretary Gregg R. Overbeck 56 Senior Vice President, APS, Nuclear Martin L. Shultz 58 Vice President, Government Affairs Steven M. Wheeler 54 Senior Vice President, APS Transmission, Regulation and Planning - ---------- (1) Member of the Board of Directors. The executive officers of Pinnacle West are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and the principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows: Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the following capacities: from August 1999 to February 2001 as President; from February 1997 to February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post is also a director of APS, Pinnacle West Energy and Phelps Dodge Corporation. 28 Mr. Davis was elected to his present position effective February 2001. Prior to that time he was Chief Operating Officer and Executive Vice President of Pinnacle West (April 2000-February 2001) and Executive Vice President, Commercial Operations of APS (September 1996-October 1998). Mr. Davis is President of APS (since October 1998) and Chief Executive Officer of APS (since October 2002). He is a director of APS and Pinnacle West Energy. Mr. Aiken was elected to his present position in July 1999. Prior to that time he was Pinnacle West's Manager, Federal Affairs (November 1986-July 1999). Mr. Bohon was elected to his present position in July 1999. Prior to that time he was Vice President, Corporate Services and Human Resources of APS (October 1998-July 1999) and Vice President, Procurement of APS (April 1997-October 1998). Mr. Brandt was elected to his present position in December 2002. Prior to that time he was Senior Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services company). Mr. Brandt was elected Senior Vice President and Chief Financial Officer of APS in January 2003. Mr. Brown was elected to his present position in June 2001. Prior to that time he was Director, Information Technology of Pinnacle West (October 1999 - June 2001) and Global Solution Executive for IBM Utilities and Energy Services of IBM prior to that time. Mr. Flores was elected to his present position in July 1999. Prior to that time, he was Executive Vice President, Corporate Business Services of APS (October 1998-July 1999) and Senior Vice President, Corporate Business Services of APS (September 1996-October 1998). Mr. Fox was elected to his present position in July 1999. Prior to that time he was Vice President, Environmental/Health/Safety and New Technology Ventures of APS (October 1995-July 1999). Ms. Gomez was elected to her present position in August 1999. Prior to that time, she was Manager, Treasury Operations of APS (1997-1999). She was also elected Treasurer of APS in October 1999. Mr. Levine was elected Executive Vice President of APS in July 1999 and President of Pinnacle West Energy in January 2003. Prior to that time he was Senior Vice President, Nuclear Generation of APS (September 1996-July 1999). Ms. Loftin was elected Vice President and General Counsel in July 1999 and Secretary in October 2002. She was elected to the positions of Vice President and Chief Legal Counsel of APS in September 1996. She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002. Mr. Overbeck was elected to his present position in July 1999. Prior to that time he was Vice President, Nuclear Production of APS (September 1996 to July 1999) and Vice President, Nuclear Support of APS (July 1995 to September 1996). Mr. Shultz was elected to his current position in July 1999. Prior to that time he held the position of Director of Government Relations for APS (1988-July 1999). Mr. Wheeler was elected to his present position in October 2002. Prior to that time he was Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS (June 2001 - October 2002). Prior to that time he was a partner with Snell & Wilmer L.L.P. 29 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS Our common stock is publicly held and is traded on the New York and Pacific Stock Exchanges. At the close of business on March 26, 2003, our common stock was held of record by approximately 36,876 shareholders. See "Quarterly Stock Prices and Dividends Per Share" in Item 6 for a description of the common stock price ranges on the composite tape, as reported in the Wall Street Journal for 2002 and 2001, and the dividends declared during each of the four quarters for 2002 and 2001. 30 ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
2002 2001 2000 1999 1998 ------------ ------------ ------------ ------------ ------------ OPERATING RESULTS (dollars in thousands, except shares and per share amounts) Operating revenues: Regulated electricity segment $ 2,013,023 $ 2,562,089 $ 2,538,752 $ 1,915,108 $ 1,741,148 Marketing and trading segment 325,931 651,230 418,532 154,125 180,145 Real estate segment 236,388 168,908 158,365 130,169 124,188 Other revenues 61,937 11,771 3,873 439 -- Income from continuing operations $ 215,153 $ 327,367 $ 302,332 $ 269,772 $ 242,892 Discontinued operations (a) -- -- -- 38,000 -- Extraordinary charge - net of income taxes (b) -- -- -- (139,885) -- Cumulative effect of change in accounting-net of income taxes (c) (d) (65,745) (15,201) -- -- -- ------------ ------------ ------------ ------------ ------------ Net income $ 149,408 $ 312,166 $ 302,332 $ 167,887 $ 242,892 ============ ============ ============ ============ ============ COMMON STOCK DATA Book value per share - year-end $ 29.40 $ 29.46 $ 28.09 $ 26.00 $ 25.50 Earnings (loss) per weighted average common share outstanding: Continuing operations - basic $ 2.53 $ 3.86 $ 3.57 $ 3.18 $ 2.87 Discontinued operations -- -- -- 0.45 -- Extraordinary charge -- -- -- (1.65) -- Cumulative effect of change in accounting (0.77) (0.18) -- -- -- ------------ ------------ ------------ ------------ ------------ Net income - basic $ 1.76 $ 3.68 $ 3.57 $ 1.98 $ 2.87 ============ ============ ============ ============ ============ Continuing operations - diluted $ 2.53 $ 3.85 $ 3.56 $ 3.17 $ 2.85 Net income - diluted $ 1.76 $ 3.68 $ 3.56 $ 1.97 $ 2.85 Dividends declared per share $ 1.625 $ 1.525 $ 1.425 $ 1.325 $ 1.225 Indicated annual dividend rate per share - year-end $ 1.70 $ 1.60 $ 1.50 $ 1.40 $ 1.30 Weighted-average common shares outstanding - basic 84,902,946 84,717,649 84,732,544 84,717,135 84,774,218 Weighted-average common shares outstanding - diluted 84,963,921 84,930,140 84,935,282 85,008,527 85,345,946 BALANCE SHEET DATA Total assets $ 8,425,806 $ 7,939,399 $ 7,122,667 $ 6,571,023 $ 6,789,975 ============ ============ ============ ============ ============ Liabilities and equity: Long-term debt less current maturities $ 2,881,695 $ 2,673,078 $ 1,955,083 $ 2,206,052 $ 2,048,961 Other liabilities 2,857,958 2,766,998 2,784,870 2,159,238 2,482,422 ------------ ------------ ------------ ------------ ------------ Total liabilities 5,739,653 5,440,076 4,739,953 4,365,290 4,531,383 Minority interests: Non-redeemable preferred stock of APS -- -- -- -- 85,840 Redeemable preferred stock of APS -- -- -- -- 9,401 Common stock equity 2,686,153 2,499,323 2,382,714 2,205,733 2,163,351 ------------ ------------ ------------ ------------ ------------ Total liabilities and equity $ 8,425,806 $ 7,939,399 $ 7,122,667 $ 6,571,023 $ 6,789,975 ============ ============ ============ ============ ============
(a) Tax benefit stemming from the resolution of income tax matters related to a former subsidiary MeraBank, A Federal Savings Bank. (b) Charges associated with a regulatory disallowance. See "Regulatory Accounting" in Note 1. (c) Change in accounting standards related to derivatives in 2001. See Note 18. (d) Change in accounting standards related to trading activities in 2002. See Note 18. 31 REGULATED ELECTRICITY AND MARKETING AND TRADING SEGMENTS' REVENUES
2002 2001 2000 1999 1998 ----------- ----------- ----------- ----------- ----------- Regulated electricity segment: (dollars in thousands) Retail: Residential $ 906,069 $ 914,711 $ 880,468 $ 805,173 $ 766,378 Business 927,773 952,627 935,214 911,449 889,244 ----------- ----------- ----------- ----------- ----------- Total retail 1,833,842 1,867,338 1,815,682 1,716,622 1,655,622 Wholesale revenue on delivered electricity: Traditional contracts 8,616 73,305 120,618 60,486 58,184 Retail load hedge management (a) 122,630 577,784 560,493 108,153 -- Transmission for others 29,803 25,971 14,765 11,348 11,058 Other miscellaneous services 18,132 17,691 27,194 18,499 16,284 ----------- ----------- ----------- ----------- ----------- Total regulated electricity revenue 2,013,023 2,562,089 2,538,752 1,915,108 1,741,148 ----------- ----------- ----------- ----------- ----------- Marketing and trading segment: Delivered marketing and trading: Generation sales other than Native Load (a) 50,364 148,316 115,476 29,551 -- Realized margin on electricity trading 47,897 62,067 55,910 8,565 2,157 Other delivered electricity (a) 207,810 328,972 244,183 112,551 170,796 ----------- ----------- ----------- ----------- ----------- Total delivered marketing and trading 306,071 539,355 415,569 150,667 172,953 ----------- ----------- ----------- ----------- ----------- Other marketing and trading: Realized margins on delivered commodities other than electricity 7,771 (13,646) (8,789) 2,483 7,192 Prior period mark-to- market gains on contracts delivered during current period (40,072) (1,059) (2,079) -- -- Change in mark-to- market for future period deliveries 52,161 126,580 13,831 975 -- ----------- ----------- ----------- ----------- ----------- Total other marketing and trading 19,860 111,875 2,963 3,458 7,192 ----------- ----------- ----------- ----------- ----------- Total marketing and trading revenue 325,931 651,230 418,532 154,125 180,145 ----------- ----------- ----------- ----------- ----------- Total regulated electricity and marketing and trading segments' revenues $ 2,338,954 $ 3,213,319 $ 2,957,284 $ 2,069,233 $ 1,921,293 =========== =========== =========== =========== ===========
(a) The breakout of retail load hedge management and generation sales other than Native Load is not available for 1998. These amounts are included in other delivered electricity in the marketing and trading segment for 1998. 32
2002 2001 2000 1999 1998 ---------- ---------- ---------- ---------- ---------- ELECTRIC SALES (MWH) Regulated electricity segment: Retail: Residential 10,443,820 10,334,860 9,780,680 8,774,822 8,310,689 Business 12,917,935 13,064,152 12,753,844 12,299,748 12,152,394 ---------- ---------- ---------- ---------- ---------- Total retail 23,361,755 23,399,012 22,534,524 21,074,570 20,463,083 Wholesale electricity delivered: Traditional contracts 473,699 1,213,704 1,610,032 1,421,522 1,410,392 Retail load hedge management (a) 2,641,714 3,039,905 6,673,658 630,945 -- ---------- ---------- ---------- ---------- ---------- Total regulated electricity 26,477,168 27,652,621 30,818,214 23,127,037 21,873,475 ---------- ---------- ---------- ---------- ---------- Delivered marketing and trading: Generation sales other than Native Load (a) 1,791,319 1,387,860 1,494,299 1,267,349 -- Electricity trading 16,924,509 12,031,055 9,259,054 5,679,023 846,864 Other delivered electricity (a) 4,138,055 2,581,942 2,960,314 6,694,995 8,060,135 ---------- ---------- ---------- ---------- ---------- Total delivered marketing and trading 22,853,883 16,000,857 13,713,667 13,641,367 8,906,999 ---------- ---------- ---------- ---------- ---------- Total regulated electricity and marketing and trading sales 49,331,051 43,653,478 44,531,881 36,768,404 30,780,474 ========== ========== ========== ========== ========== ELECTRIC CUSTOMERS - AVERAGE Retail: Residential 801,801 776,339 749,285 719,774 689,871 Business 100,228 98,198 94,128 90,496 87,831 ---------- ---------- ---------- ---------- ---------- Total retail 902,029 874,537 843,413 810,270 777,702 Wholesale 67 66 67 69 60 ---------- ---------- ---------- ---------- ---------- Total average electric customers 902,096 874,603 843,480 810,339 777,762 ========== ========== ========== ========== ==========
(a) The breakout of retail load hedge management and generation sales other than Native Load is not available for 1998. These amounts are included in other delivered electricity in the marketing and trading segment for 1998. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of certain information in the tables above. 33 QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE STOCK SYMBOL: PNW Dividends Per 2002 High Low Close Share - ----------- ------ ------ ------ ------ 1st Quarter $45.60 $39.36 $45.35 $0.400 2nd Quarter 46.68 37.08 39.50 0.400 3rd Quarter 39.72 25.82 27.76 0.400 4th Quarter 34.36 21.70 34.09 0.425 Dividends Per 2001 High Low Close Share - ----------- ------ ------ ------ ------ 1st Quarter $47.96 $39.06 $45.87 $0.375 2nd Quarter 50.70 45.20 47.40 0.375 3rd Quarter 49.93 37.65 39.70 0.375 4th Quarter 43.50 38.00 41.85 0.400 34 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION In this Item, we explain the results of operations, general financial condition and outlook for Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado, 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 Consolidated Financial Statements in Item 8 of this report. These Notes add further details to the discussion. BUSINESS OVERVIEW The Company owns all of the outstanding common stock of APS. APS is 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 one-half of the Phoenix metropolitan area. Electricity is delivered through a distribution system owned by APS. APS also generates, sells and delivers electricity to wholesale customers in the western United States. The marketing and trading division sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS' Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. APS does not distribute any products. Our other major subsidiaries are: * Pinnacle West Energy, through which we conduct our competitive electricity generation operations; * APS Energy Services, which provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States; * SunCor, a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah; and 35 * El Dorado, which owns a majority interest in NAC (specializing in spent nuclear fuel technology) and holds miscellaneous small investments, including interests in Arizona community-based ventures. 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: * APS' $500 million financing application, which the ACC approved on March 27, 2003; * the implementation of the ACC-mandated process by which APS must competitively procure energy; and * APS' 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." EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT We have three principal business segments (determined by products, 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; * our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services' commodity-related energy services; and * our real estate segment, which consists of SunCor's real estate development and investment activities. The following tables summarize net income and segment details for the years ended December 31, 2002, 2001 and 2000 for Pinnacle West and each of our subsidiaries (dollars in millions): 36
REGULATED MARKETING AND TOTAL ELECTRICITY TRADING REAL ESTATE OTHER (a) --------- ----------- ------------- ----------- --------- 2002 - ---- APS (b) $ 199 $ 198 $ 1 $ -- $ -- Pinnacle West Energy (b) (19) (21) 2 -- -- APS Energy Services (c) 28 -- 23 -- 5 SunCor 19 -- -- 19 -- El Dorado (principally NAC) (c) (55) -- -- -- (55) Parent company (c) 43 (7) 32 -- 18 --------- --------- --------- --------- --------- Income (loss) before accounting change 215 170 58 19 (32) Cumulative effect of change in accounting - net of income taxes (d) (66) -- (66) -- -- --------- --------- --------- --------- --------- Net income (loss) $ 149 $ 170 $ (8) $ 19 $ (32) ========= ========= ========= ========= ========= REGULATED MARKETING AND TOTAL ELECTRICITY TRADING REAL ESTATE OTHER --------- ----------- ------------- ----------- --------- 2001 - ---- APS (b) $ 281 $ 139 $ 142 $ -- $ -- Pinnacle West Energy (b) 18 18 -- -- -- APS Energy Services (c) (10) -- (11) -- 1 SunCor 3 -- -- 3 -- El Dorado -- -- -- -- -- Parent company 35 (5) 40 -- -- --------- --------- --------- --------- --------- Income before accounting change 327 152 171 3 1 Cumulative effect of change in accounting - net of income taxes (e) (15) (15) -- -- -- --------- --------- --------- --------- --------- Net income $ 312 $ 137 $ 171 $ 3 $ 1 ========= ========= ========= ========= ========= REGULATED MARKETING AND TOTAL ELECTRICITY TRADING REAL ESTATE OTHER --------- ----------- ------------- ----------- --------- 2000 - ---- APS $ 307 $ 228 $ 79 $ -- $ -- Pinnacle West Energy (2) (2) -- -- -- APS Energy Services (c) (13) -- (16) -- 3 SunCor 11 -- -- 11 -- El Dorado 2 -- -- -- 2 Parent company (3) (5) 2 -- -- --------- --------- --------- --------- --------- Net income $ 302 $ 221 $ 65 $ 11 $ 5 ========= ========= ========= ========= =========
37 (a) Primarily includes activities related to El Dorado, principally NAC. See Note 22. (b) Consistent with APS' October 2001 ACC filing, APS entered into agreements with its affiliates to buy power. The agreements reflected a price based on the fully-dispatchable dedication of the Pinnacle West Energy generating assets to APS' Native Load customers. In 2002, Pinnacle West Energy recorded a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4. (c) APS Energy Services' and El Dorado's net income is primarily reported before income taxes. The income tax expense or benefit for these subsidiaries is recorded at the parent company. (d) We recorded a $66 million after-tax charge in 2002 for the cumulative effect of a change in accounting for trading activities, for the early adoption of EITF 02-3," Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," as of October 1, 2002. See Note 18. (e) APS 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 18. See Note 17 for additional financial information regarding our business segments. 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. Our real estate segment gross margin refers to real estate revenues less real estate operations costs of SunCor. Other gross margin refers to other operating revenues less other operating expenses, which includes El Dorado's investment in NAC, which we began consolidating in our financial statements in July 2002 (see Note 22). Other gross margin also includes amounts related to APS Energy Services' energy consulting services. 2002 COMPARED WITH 2001 Our consolidated net income for the year ended December 31, 2002 was $149 million compared with $312 million for the prior year. We recognized a $66 million after-tax charge in 2002 for the cumulative effect of a change in accounting for trading activities for the early adoption of EITF 02-3 on October 1, 2002 (see Note 18). 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 18). Our income before accounting change for the year ended December 31, 2002 was $215 million compared with $327 million for the prior year. The period-to-period comparison was lower due to: 38 * lower earnings contributions from our marketing and trading activities, reflecting lower liquidity and lower price volatility in the wholesale power markets in the western United States; * pretax losses of $59 million related to our investment in NAC; * a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4, of which $47 million was recorded in operations and maintenance expense and $2 million was recorded in capitalized interest; and * severance costs of approximately $36 million pretax recorded in the second half of 2002 relating to a voluntary workforce reduction. The above 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, 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; and * increased earnings contributions from real estate operations, primarily as a result of increased sales activities. For additional details, see the following discussion. 39 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 (9) 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) Miscellaneous factors, net (2) -------- Net increase in regulated electricity segment gross margin 112 -------- 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 (66) Lower realized wholesale margins net of related mark-to-market reversals due to lower prices and volumes (91) Higher competitive retail sales in California by APS Energy Services 32 2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates 8 Lower mark-to-market reversals due to the adoption of EITF 02-3 8 Lower mark-to-market gains for future delivery due to lower market liquidity and lower price volatility (76) -------- Net decrease in marketing and trading segment gross margin (185) -------- Net decrease in regulated electricity and marketing and trading segments' gross margins (73) Higher real estate segment gross margin primarily due to increased sales activities 16 Lower other gross margin primarily related to NAC losses (44) Higher operations and maintenance expense related to a $47 million write-off of Redhawk Units 3 and 4 and 2002 severance costs of approximately $36 million, partially offset by lower generation reliability costs (54) Higher taxes other than income taxes (7) Lower other income primarily due to a 2001 insurance recovery of environmental remediation costs (11) Higher net interest expense primarily due to higher debt balances and lower capitalized interest (16) Miscellaneous factors, net 2 -------- Net decrease in income before income taxes (187) Lower income taxes primarily due to lower income 75 -------- Net decrease in income before accounting change $ (112) ========
40 REGULATED ELECTRICITY SEGMENT GROSS MARGIN Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $549 million lower in the year ended December 31, 2002, compared with the prior year as a result of: * 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 ($455 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 ($11 million net decrease). Regulated electricity segment purchased power and fuel costs were $661 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 ($460 million); * increased costs related to higher prices for hedged natural gas and purchased power, net of mark-to-market reversals ($14 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 * miscellaneous factors ($9 million net decrease). MARKETING AND TRADING SEGMENT GROSS MARGIN Marketing and trading segment revenues were $325 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 ($98 million); * lower realized wholesale revenues net of related mark-to-market reversals primarily due to lower prices partially offset by higher volumes ($273 million); * increased revenues from higher competitive retail sales in California by APS Energy Services ($105 million); * 2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates ($8 million increase); * higher revenues related to the adoption of EITF 02-3 ($8 million); and 41 * lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and lower price volatility, resulting in lower volumes ($75 million). Marketing and trading segment purchased power and fuel costs were $140 million lower in the year ended December 31, 2002, compared to 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 ($32 million); * decreased purchased power costs related to other realized marketing activities in the current period primarily due to lower prices partially offset by higher volumes ($182 million); * increased purchased power costs related to higher competitive retail sales in California by APS Energy Services ($73 million); and * change in mark-to-market fuel costs for future delivery ($1 million increase). OTHER INCOME STATEMENT ITEMS The increase in real estate segment gross margin of $16 million was primarily due to increased sales activities. The decrease in other gross margin of $44 million was primarily due to losses on El Dorado's investment in NAC (see further discussion in Note 22). These losses for 2002 totaled approximately $59 million on a pretax basis and were primarily related to NAC contracts with two customers ($51 million was recorded in other gross margin and $8 million was recorded in other expense). We believe we have reserved our exposure with respect to these contracts in all material respects and, as a result, we consider these charges to be non-recurring. The increase in operations and maintenance expense of $54 million was due to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4, severance costs of $36 million related to a 2002 voluntary workforce reduction and other costs of $9 million, partially offset by lower costs related to generation reliability, plant outages and maintenance costs of $38 million. 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 $11 million primarily due to an insurance recovery recorded in 2001 related to environmental remediation costs and other costs (see Note 19). Other expense was comparable with the prior year primarily due to losses recorded related to El Dorado's investment in NAC of approximately $8 million (see further discussion in Note 22), offset by $8 million of lower miscellaneous non-operating costs (see Note 19). Net interest expense increased $16 million primarily because of higher debt balances related to our generation construction program and lower capitalized interest on our generation construction program due to completion of Redhawk Units 1 and 2 in mid-2002. 42 2001 COMPARED WITH 2000 Our consolidated net income for the year ended December 31, 2001 was $312 million compared with $302 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 18). Our income before accounting change for the year ended December 31, 2001 was $327 million compared with $302 million for the prior year. The period-to-period comparison benefited from: * strong marketing and trading results, including significant benefits recognized in the third quarter of 2001 from structured trading activities; and * retail customer growth. The above increases were partially offset by: * lower earnings contributions from our regulated electricity activities, reflecting higher purchased power and fuel costs, due in part to increased power plant maintenance, generation reliability measures and continuing retail electricity price decreases; and * 2001 charges related to Enron and its affiliates. For additional details, see the following discussion. 43 The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
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 (13)(a) Higher retail sales primarily related to customer growth 35 Miscellaneous revenues 3 -------- Net decrease in regulated electricity segment gross margin (72) -------- 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 61 Change in prior period mark-to-market value related to trading with Enron and its affiliates (8)(a) Increase in mark-to-market value related to future periods 113 -------- Net increase in marketing and trading segment gross margin 191 -------- Net increase in regulated electricity and marketing and trading segments' gross margins 119 Decrease in real estate segment contributions (8) Higher operations and maintenance expense related to 2001 generation reliability program (42) Higher operations and maintenance expense related primarily to employee benefits, plant outage and maintenance and other costs (38) Lower net interest expense primarily due to higher capitalized interest 17 Higher other net expense (4) -------- Net increase in income before income taxes 44 Higher income taxes primarily due to higher income (19) -------- Net increase in income before accounting change $ 25 ========
(a) We recorded charges totaling $21 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 to 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); 44 * increased retail revenues primarily related to higher sales volumes primarily due to customer growth ($78 million); and * decreased retail revenues related to reductions in retail electricity prices ($27 million). Regulated electricity segment purchased power and fuel costs were $95 million higher in the year ended December 31, 2001 compared to the prior year as a result of: * decreased costs related to other wholesale sales as a result of lower volumes ($31 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 costs related to retail sales volumes due to customer growth ($43 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 $233 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 ($96 million); * decreased prior period mark-to-market value related to trading with Enron and its affiliates ($8 million); and * increased mark-to-market value for future periods primarily as a result of more forward sales volumes ($113 million). Marketing and trading segment purchased power and fuel costs were $42 million higher in the year ended December 31, 2001 compared to 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 ($35 million). OTHER INCOME STATEMENT ITEMS The decrease in real estate segment profits of $8 million resulted primarily from reduced sales of land and homes by SunCor. The increase in operations and maintenance expenses of $80 million primarily related to the 2001 generation summer reliability program (the addition of generating capability to enhance reliability for the summer of 2001 ($42 million)) and increased employee benefit costs, plant outage and 45 maintenance and other costs ($38 million). The comparison reflects Pinnacle West's $10 million provision for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001. Net other expense increased $4 million primarily because of a change in the market value of El Dorado's investment in a technology-related venture capital partnership in 2000 and other nonoperating costs partially offset by an insurance recovery of environmental remediation costs (see Note 19). Interest expense decreased by $17 million primarily because of increased capitalized interest resulting from our generation construction plan partially offset with higher interest expense due to higher debt balances. See "Regulatory Matters - 1999 Settlement Agreement" in Note 3 for a discussion of the 1999 Settlement Agreement under which, among other things, APS 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 ---- ---- ---- ---- APS Delivery $369 $273 $275 $329 Generation (a) 132 123 99 164 Other (e) -- 5 5 5 ---- ---- ---- ---- Subtotal 501 401 379 498 Pinnacle West Energy (a) (b) 374 268 31 20 SunCor (c) 72 64 23 20 Other (d) 37 17 13 14 ---- ---- ---- ---- Total $984 $750 $446 $552 ==== ==== ==== ==== (a) As discussed below under "Factors Affecting Our Financial Outlook," as part of its 2003 general rate case, APS intends to seek rate base treatment of certain power plants in Arizona currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3). 46 (b) See Note 11 for further discussion of Pinnacle West Energy's generation construction program and "Capital Resources and Cash Requirements - Pinnacle West Energy" below. These amounts do not include an expected reimbursement in 2004 by SNWA of about $100 million, assuming SNWA exercises its option to purchase a 25% interest in the Silverhawk project at that time. (c) Consists primarily of capital expenditures for land development and retail and office building construction reflected in the "Change in real estate investments" in the Consolidated Statements of Cash Flows. (d) Primarily related to the parent company and APS Energy Services. (e) 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, APS began several major transmission projects in 2001. These projects are periodic in nature and are driven by strong regional customer growth. APS expects to spend about $105 million on major transmission projects during the 2003 to 2005 time frame, and these amounts are included in "APS-Delivery" in the table above. Generation capital expenditures are comprised of various improvements for APS' existing fossil and nuclear plants and the replacement of Palo Verde steam generators. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also 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 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): 47
Actual Estimated ------ --------------------------------------------------- There- 2002 2003 2004 2005 2006 2007 after ------ ------ ------ ------ ------ ------ ------ Long-term debt payments: APS $ 337 $ -- $ 205 $ 400 $ 84 $ -- $1,518 Pinnacle West -- 275 215 -- 300 -- -- SunCor 3 -- 126 -- 3 -- 15 El Dorado 13 1 1 1 -- -- -- ------ ------ ------ ------ ------ ------ ------ Total long-term debt payments 353 276 547 401 387 -- 1,533 Capital lease payments 1 5 5 4 3 3 6 Operating lease payments 69 70 66 64 63 63 478 Purchase power and fuel commitments 338 173 82 28 31 17 162 ------ ------ ------ ------ ------ ------ ------ Total contractual commitments $ 761 $ 524 $ 700 $ 497 $ 484 $ 83 $2,179 ====== ====== ====== ====== ====== ====== ======
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. In 1986, APS entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. See Note 9 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. APS is also exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2002, APS would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million. GUARANTEES We and certain of our subsidiaries have issued guarantees in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS 48 Energy Services. We have not recorded any liability on our Consolidated Balance Sheets with respect to these obligations. See Note 23 for additional information regarding guarantees. CREDIT RATINGS The ratings of securities of Pinnacle West and APS as of March 28, 2003 are shown below and are considered to be "investment-grade" ratings. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West's or APS' securities and serve to increase those companies' cost of and access to capital. Moody's Standard & Poor's Fitch ------- ----------------- ----- PINNACLE WEST Senior unsecured Baa2 BBB- BBB Commercial paper P-2 A-2 F-2 APS 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 the APS debt ratings in the above chart, but lowered Pinnacle West's senior unsecured debt rating from BBB to BBB- "because of the structural subordination of this debt as compared to the unsecured debt at APS." On that same date, Standard & Poor's lowered APS' corporate credit rating from BBB+ to BBB and affirmed the BBB corporate credit rating of Pinnacle West. Standard & Poor's assigned a stable outlook to the ratings. All of Pinnacle West's and APS' credit ratings remain investment grade. In December 2002, Fitch placed certain of our debt and that of APS on Ratings Watch Negative. The ratings watch affects our senior unsecured debt and commercial paper ratings. It also affects all of APS' debt ratings, with the exception of its commercial paper rating. On December 31, 2002, Moody's affirmed the ratings set forth above. DEBT PROVISIONS Pinnacle West's and APS' significant debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS are in compliance with such covenants and each anticipates it will continue to meet all the significant covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for both the Company and APS. At December 31, 2002, the ratios are approximately 54% and 48% for the parent company and APS, respectively. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for both the Company and APS. The coverages are approximately 4 times for the parent company, 5 times for the APS bank agreements and 15 times for the APS mortgage indenture. Failure to comply with 49 such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants. Neither Pinnacle West's nor APS' financing agreements contain "ratings triggers" that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements. All of Pinnacle West's bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other agreements. All of APS' bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under other agreements. Pinnacle West's and APS' credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects. PINNACLE WEST (PARENT COMPANY) Our primary cash needs are for dividends to our shareholders; equity infusions into our subsidiaries, primarily Pinnacle West Energy; and interest payments and optional and mandatory repayments of principal on our long-term debt (see the table above for our contractual requirements, including our debt repayment obligations, but excluding optional repayments). On October 23, 2002, our board of directors increased the common stock dividend to an indicated annual rate of $1.70 per share from $1.60 per share, effective with the December 1, 2002 dividend payment. The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions. Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2000 through 2002, total dividends from APS were $510 million and total distributions from SunCor were $33 million. For the year ended December 31, 2002, dividends from APS were approximately $170 million and distributions from SunCor were approximately $13 million. We expect SunCor to make cash distributions to the parent company of $80 million to $100 million annually in 2003 through 2005 due to anticipated accelerated asset sales activity. On December 23, 2002, we issued 6,555,000 shares of common stock, no par value, which resulted in net proceeds of $199 million. See Note 7. We have financed Pinnacle West Energy's generation construction program premised upon Pinnacle West Energy's receipt of APS' generation assets by the end of 2002. On November 22, 2002, the ACC approved APS' request (Interim Financing Application) to permit APS 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 this financing arrangement. 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 50 exceed $500 million in the aggregate. See "Factors Affecting our Financial Outlook - Regulatory Matters" and "ACC Applications" in Note 3 for additional information. In 2002, the parent company issued $215 million in long-term debt and had no repayments of long-term debt (see Note 6). The parent company's outstanding long and short-term debt was approximately $887 million at December 31, 2002. At December 31, 2002, our commitments totaled $475 million, which were available to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2002, we had about $24 million of commercial paper outstanding and $72 million of short-term borrowings. Our long-term debt including current maturities totaled $791 million at December 31, 2002. In mid-2003, we will need to refinance approximately $475 million of parent company indebtedness, including a total of $225 million we expect to borrow under an existing credit facility. We expect that this indebtedness will be repaid through funds borrowed by Pinnacle West Energy from APS under the $500 million financing arrangement recently approved by the ACC. As part of a multi-employer pension plan sponsored by Pinnacle West, we contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. We elected to contribute cash to our pension plan in each of the last five years; our minimum required contributions during each of those years was zero. Specifically, we contributed $27 million for 2002, $24 million for 2001, $44 million for 2000, $25 million for 1999 and $14 million for 1998. APS and other subsidiaries fund their share of the pension contribution, of which APS represents approximately 90% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. We currently forecast 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 an APS tax accounting method change on the 2001 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 our 2001 federal consolidated income tax return. APS APS' 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 APS and Pinnacle West Energy recently approved by the ACC. See "Pinnacle West (Parent Company)" above and Note 3 for discussion of a $125 million financing arrangement between APS and Pinnacle West. 51 APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid for its dividends to Pinnacle West with cash from operations. In 2002, APS 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, APS will redeem $33 million of its first mortgage bonds. APS' outstanding debt was approximately $2.2 billion at December 31, 2002. At December 31, 2002, APS 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, APS had no outstanding commercial paper or bank borrowings. Although provisions in APS' first mortgage bond indenture, articles of incorporation and ACC financing orders establish maximum amounts of additional first mortgage bonds, debt and preferred stock that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. PINNACLE WEST ENERGY The costs of Pinnacle West Energy's construction of generating capacity from 2000 through 2004 are expected to be about $1.4 billion. This does not reflect an expected reimbursement in 2004 by SNWA of about $100 million of Pinnacle West Energy's cumulative capital expenditures in the Silverhawk project, assuming SNWA exercises its option to purchase a 25% interest in the project. Pinnacle West Energy is currently funding its capital requirements through capital infusions from Pinnacle West, which finances those infusions through debt and equity financings and internally-generated cash. See the capital expenditures table above for actual capital expenditures in 2002 and projected capital expenditures for the next three years. See "Factors Affecting Our Financial Outlook - Regulatory Matters" below and Note 3 for discussion of the $500 million. OTHER SUBSIDIARIES During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor's capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures in 2002 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings. In 2002, SunCor issued $50 million in long-term debt, and redeemed, refinanced or repaid $53 million in long-term debt (see Note 6). SunCor's outstanding long and short-term debt was approximately $153 million as of December 31, 2002. As of December 31, 2002, SunCor had a $140 million line of credit, under which $126 million of borrowings were outstanding. SunCor's short-term debt was $6 million and other long-term debt, including current maturities, totaled $21 million at December 31, 2002. 52 We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2003 through 2005 due to anticipated accelerated asset sales activity. El Dorado funded its cash requirements during the past three years, primarily for NAC in 2002, with cash infused by the parent company and with cash from operations. El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments. El Dorado's long-term debt was approximately $3 million at December 31, 2002 and it had no long-term debt outstanding at December 31, 2001. El Dorado's long-term debt increased primarily due to its consolidation of NAC for financial reporting purposes (see Notes 6 and 22). APS Energy Services' cash requirements during the past three years were funded with cash infusions from the parent company. APS Energy Services' capital expenditures and other cash requirements are increasingly funded by operations, with some funding from cash infused by Pinnacle West. See the capital expenditures table above regarding APS Energy Services' actual capital expenditures for 2002 and projected capital expenditures for the next three years. 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 the 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. 53 * 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. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. 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 APS' 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 APS not to transfer its generation assets, as previously required by the 1999 Settlement Agreement (see "Track A Order" in Note 3). Accordingly, we now consider APS 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 consolidated 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 Consolidated Balance Sheets at December 31, 2002. See Notes 1 and 3 for more information. PENSIONS AND OTHER POSTRETIREMENT BENEFIT ACCOUNTING We sponsor a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for our employees and employees of our subsidiaries. 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 and other postretirement benefit costs. Pension and other postretirement benefit 54 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 projected benefit obligation, our 2002 reported pension liability on the Consolidated Balance Sheets and our 2002 reported annual pension expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions). Increase/(Decrease) ------------------------------------------------------------------- Impact on Projected Impact on Impact on 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. 55 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 accumulated other postretirement benefit obligation and our 2002 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on the Consolidated Statements of Income (dollars in millions). Increase/(Decrease) ---------------------------------------------------------------------- Impact on Accumulated Impact on Other Postretirement Benefit Postretirement Benefit Actuarial Assumption Obligation 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 pretax 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. 56 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 our 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 8 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 Consolidated 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 57 Activities" below for details on the change in accounting for energy trading contracts. See Note 18 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 Consolidated 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 18 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 marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales 58 transactions. To illustrate, as presented in the "Factors Affecting our Financial Outlook - Market Risks - Commodity Price Risk" section below, a 10% increase in the price of trading commodities would result in only a $2 million decrease in pretax income. Our practice is to hedge within timeframes established by the ERMC. 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. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. 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 Consolidated 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. 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. 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 Consolidated 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 18 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.) 59 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 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 $500,000 in stock option expense before income taxes in our Consolidated Statements of Income for 2002. See Notes 1 and 16 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 20 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 APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its 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, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its 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 APS not to transfer its generation assets to Pinnacle West Energy. 60 1999 SETTLEMENT AGREEMENT The 1999 Settlement Agreement has affected, and will affect, our results of operations. As part of the 1999 Settlement Agreement, APS 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 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. APS 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 Consolidated Statement of Income. As discussed under "APS General Rate Case" below, APS intends to seek recovery of this $234 million write-off in its next general rate case. Prior to the 1999 Settlement Agreement, the ACC accelerated the amortization of substantially all of APS' 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. APS FINANCING APPLICATION On September 16, 2002, APS filed an application with the ACC requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or a combination of both, not to exceed $500 million in the aggregate. In its application, APS stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS 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 we 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. 61 COMPETITIVE PROCUREMENT PROCESS 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. Under the ACC's Track B Order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS 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 APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' 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 APS' right to reject any bids that are unreasonable, uneconomical or unreliable. APS expects 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 APS' electricity requirements. See "Track B Order" in Note 3 for additional information. APS GENERAL RATE CASE As required by the 1999 Settlement Agreement, on or before June 30, 2003, APS will file a general rate case with the ACC. In this rate case, APS will update its cost of service and rate design. In addition, APS expects 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 APS as part of the 1999 Settlement Agreement ($140 million extraordinary charge recorded on the 1999 Consolidated Statement of Income); and * recovery of costs incurred by APS 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 we moved to APS 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 APS' transfer of generating assets to Pinnacle West Energy, focuses primarily on managing APS' purchased power and fuel risks in connection with its 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 our marketing and trading division were lower in 2002 compared to 2001 due to weak wholesale power market conditions in the western United States, which 62 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. GENERATION CONSTRUCTION See "Capital Needs and Resources - Pinnacle West Energy" above and Note 11 for information regarding Pinnacle West Energy's generation construction program. The planned additional generation is expected to increase revenues, fuel expenses, operating expenses and financing costs. 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. Competitive sales of energy and energy-related products and services are made by APS Energy Services in western states that have opened to competitive supply. CUSTOMER GROWTH Customer growth in APS' service territory averaged about 3.6% 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, new generating plants being placed in service 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 $36 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, changes in regulatory asset amortization and our generation construction program. West Phoenix Unit 4 was placed in service in June 2001. Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in 63 July 2002. West Phoenix Unit 5 is expected to be on line in mid-2003 and Silverhawk is expected to be in service in mid-2004 (see Note 11 for further details about our generation construction program). 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 for APS, which currently owns the majority of our property, was 9.7% of assessed value for 2002 and 9.3% for 2001. We expect property taxes to increase primarily due to our generation construction program and our additions to existing facilities. INTEREST EXPENSE Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally-generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop recording capitalized interest on a project when it is placed in commercial operation. As noted above, we have placed new power plants in commercial operation in 2001 and 2002 and we expect to bring additional plants on-line in 2003 and 2004. We are continuing to evaluate our generation construction program. Interest expense is affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company's future liquidity needs. RETAIL COMPETITION The regulatory developments and legal challenges to the Rules discussed in Note 3 have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. Although some very limited retail competition existed in APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory. SUBSIDIARIES In the case of SunCor, we are undertaking an aggressive effort to accelerate asset sales activities to approximately double SunCor's annual earnings in 2003 to 2005 compared to the $19 million in earnings recorded in 2002. A portion of these sales could be reported as discontinued operations on the Consolidated Statements of Income. The annual earnings contribution from APS Energy Services is expected to be positive over the next several years due primarily to a number of retail electricity contracts in California. APS Energy Services' had pretax earnings of $28 million in 2002. El Dorado's historical results are not necessarily indicative of future performance for El Dorado. El Dorado's strategies focus on prudently realizing the value of its existing investments. 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. 64 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 our 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 8) and nuclear decommissioning trust fund (see Note 12). 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 (APS only) 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 consolidated 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. 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 2.59% $ 102,183 2.68% $ 250,800 6.73% $ 30,223 2004 -- -- 3.76% 126,813 5.32% 424,697 2005 -- -- 3.39% 1,294 7.27% 403,931 2006 -- -- 10.10% 2,954 6.47% 387,018 2007 -- -- 8.00% 209 6.04% 2,738 Years thereafter -- -- 2.00% 390,537 6.08% 1,148,371 --------- --------- ----------- Total $ 102,183 $ 772,607 $ 2,396,978 ========= ========= =========== Fair value $ 102,183 $ 772,607 $ 2,501,073 ========= ========= ===========
65 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 4.01% $ 405,762 7.76% $ 207 8.10% $ 125,933 2003 -- -- 4.75% 292,912 6.87% 25,829 2004 -- -- 5.32% 85,601 6.08% 205,677 2005 -- -- 7.70% 294 7.59% 400,380 2006 -- -- 7.30% 3,018 6.48% 384,085 Years thereafter -- -- 2.63% 480,740 6.73% 799,808 --------- --------- ----------- Total $ 405,762 $ 862,772 $ 1,941,712 ========= ========= =========== Fair value $ 405,762 $ 862,772 $ 1,963,389 ========= ========= ===========
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 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 Consolidated 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 18 for details on the change in accounting for energy trading contracts and further discussion regarding derivative accounting. 66 Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Consolidated 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): 67 Marketing and System Trading ------ ------- Mark-to-market of net positions at December 31, 2001 $(107) $ 138 Cumulative effect adjustment due to adoption of EITF 02-3 -- (109) Change in mark-to-market gains for future period deliveries (13) 47 Changes in cash flow hedges recorded in OCI 57 16 Ineffective portion of changes in fair value recorded in earnings 11 -- Mark-to-market losses/(gains) realized during the year 3 (38) Change in valuation techniques -- 3 ----- ----- Mark-to-market of net positions at December 31, 2002 $ (49) $ 57 ===== ===== 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) 203 Changes in cash flow hedges recorded in OCI (166) -- Ineffective portion of changes in fair value recorded in earnings (6) -- Mark-to-market gains realized during the year (18) (77) Change in valuation techniques -- -- ----- ----- Mark-to-market of net positions at December 31, 2001 $(107) $ 138 ===== ===== The Company no longer reports non-derivative energy contracts or physical inventories at fair value. Since July 1, 2002, the Company has not recognized a dealer profit or unrealized gain or loss at the inception of a derivative unless the fair value of that instrument (in its entirety) is evidenced by quoted market prices or current market transactions. Prior to the change in our policy, we recorded net gains at inception of $10 million in 2002 and $3 million in 2001. These amounts included a reasonable marketing margin. The tables below show the maturities of our system and marketing and trading derivative positions at December 31, 2002 by the type of valuation that is performed to calculate the fair value of the contract (dollars in millions). See "Critical Accounting Policies - Mark-to-Market Accounting" above for more discussion on our valuation methods. 68 SYSTEM
Years Total Source of Fair Value 2003 2004 2005 2006 2007 thereafter fair value - -------------------- ---- ---- ---- ---- ---- ---------- ---------- Prices actively quoted $(23) $(10) $ -- $ -- $ -- $ -- $(33) Prices provided by other external sources (1) (12) -- -- -- -- (13) Prices based on models and other valuation methods (1) (2) -- -- -- -- (3) ---- ---- ---- ---- ---- ---- ---- Total by maturity $(25) $(24) $ -- $ -- $ -- $ -- $(49) ==== ==== ==== ==== ==== ==== ====
MARKETING AND TRADING
Years Total Source of Fair Value 2003 2004 2005 2006 2007 thereafter fair value - -------------------- ---- ---- ---- ---- ---- ---------- ---------- Prices actively quoted $ (1) $ 5 $ 6 $ 3 $ 3 $ 7 $ 23 Prices provided by other external sources 2 8 9 12 -- -- 31 Prices based on models and other valuation methods 6 3 (3) (4) 5 (4) 3 ---- ---- ---- ---- ---- ---- ---- Total by maturity $ 7 $ 16 $ 12 $ 11 $ 8 $ 3 $ 57 ==== ==== ==== ==== ==== ==== ====
The table below shows the impact hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in millions). 69
December 31, 2002 December 31, 2001 Gain (Loss) Gain (Loss) ----------------------------- ---------------------------- Commodity Price Up 10% Price Down 10% Price Up 10% Price Down 10% --------- ------------ -------------- ------------ -------------- Mark-to-market changes reported in earnings (a): Electricity $ (2) $ 3 $ (3) $ 3 Natural gas (4) 4 (1) 1 Other 1 -- -- 2 Mark-to-market changes reported in OCI (b): Electricity 32 (32) -- -- Natural gas 18 (16) 23 (23) ---- ---- ---- ---- Total $ 45 $(41) $ 19 $(17) ==== ==== ==== ====
(a) These contracts are structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. (b) These contracts are hedges of our forecasted purchases of natural gas and electricity. 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. CREDIT RISK We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 33% of our $181 million of risk management and trading assets as of December 31, 2002. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities 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. 70 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 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; the successful completion of our generation construction program; regulatory issues associated with generation construction, such as permitting and licensing; 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; the strength of the real estate market in SunCor's market areas, which include Arizona, New Mexico and Utah; and other uncertainties, all of which are difficult to predict and many of which are beyond our control. 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. 71 [THIS PAGE INTENTIONALLY LEFT BLANK.] 72 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE Independent Auditors' Report................................................. 74 Consolidated Statements of Income for 2002, 2001 and 2000.................... 75 Consolidated Balance Sheets as of December 31, 2002 and 2001................. 76 Consolidated Statements of Cash Flows for 2002, 2001 and 2000................ 78 Consolidated Statements of Changes in Common Stock Equity for 2002, 2001 and 2000.................................................... 79 Notes to Consolidated Financial Statements................................... 80 Financial Statement Schedule for 2002, 2001 and 2000 Schedule II - Valuation and Qualifying Accounts for 2002, 2001 and 2000...................................................................138 See Note 13 for the selected quarterly financial data required to be presented in this Item. 73 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of Pinnacle West Capital Corporation Phoenix, Arizona We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries ("the Corporation") as of December 31, 2002 and 2001 and the related consolidated 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 financial statement schedule are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the 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 consolidated financial statements present fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries at December 31, 2002 and 2001 and the results of their operations and their 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 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 18 to the consolidated financial statements, in 2002 Pinnacle West Capital Corporation changed its method of accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." As discussed in Note 18 to the consolidated financial statements, in 2001 Pinnacle West Capital Corporation 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 4, 14, 26 and 27, 2003 as to Note 24) 74 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF INCOME (dollars and shares in thousands, except per share amounts)
Year Ended December 31, --------------------------------------------- 2002 2001 2000 ----------- ----------- ----------- OPERATING REVENUES Regulated electricity segment $ 2,013,023 $ 2,562,089 $ 2,538,752 Marketing and trading segment 325,931 651,230 418,532 Real estate segment 236,388 168,908 158,365 Other revenues 61,937 11,771 3,873 ----------- ----------- ----------- Total 2,637,279 3,393,998 3,119,522 ----------- ----------- ----------- OPERATING EXPENSES Regulated electricity segment purchased power and fuel 499,543 1,160,863 1,065,597 Marketing and trading segment purchased power and fuel 194,039 334,209 292,669 Operations and maintenance 584,538 530,095 450,205 Real estate operations segment 205,315 153,462 134,422 Depreciation and amortization 424,886 427,903 431,229 Taxes other than income taxes 107,952 101,068 99,780 Other expenses 104,959 10,375 782 ----------- ----------- ----------- Total 2,121,232 2,717,975 2,474,684 ----------- ----------- ----------- OPERATING INCOME 516,047 676,023 644,838 ----------- ----------- ----------- OTHER Other income 15,104 26,416 21,832 Other expenses (33,655) (33,577) (25,329) ----------- ----------- ----------- Total (18,551) (7,161) (3,497) ----------- ----------- ----------- INTEREST EXPENSE Interest charges 188,353 175,822 166,447 Capitalized interest (44,110) (47,862) (21,638) ----------- ----------- ----------- Total 144,243 127,960 144,809 ----------- ----------- ----------- INCOME BEFORE INCOME TAXES 353,253 540,902 496,532 INCOME TAXES 138,100 213,535 194,200 ----------- ----------- ----------- INCOME BEFORE ACCOUNTING CHANGE 215,153 327,367 302,332 Cumulative effect of a change in accounting for derivatives - net of income taxes of $9,892 -- (15,201) -- Cumulative effect of a change in accounting for trading activities - net of income taxes of $43,123 (65,745) -- -- ----------- ----------- ----------- NET INCOME $ 149,408 $ 312,166 $ 302,332 =========== =========== =========== WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC 84,903 84,718 84,733 WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED 84,964 84,930 84,935 EARNINGS PER WEIGHTED - AVERAGE COMMON SHARE OUTSTANDING Income before accounting change - basic $ 2.53 $ 3.86 $ 3.57 Net income - basic 1.76 3.68 3.57 Income before accounting change - diluted 2.53 3.85 3.56 Net income - diluted 1.76 3.68 3.56 DIVIDENDS DECLARED PER SHARE $ 1.625 $ 1.525 $ 1.425
See Notes to Consolidated Financial Statements. 75 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands)
December 31, ------------------------- 2002 2001 ---------- ---------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 77,707 $ 28,619 Customer and other receivables - net 374,995 367,241 Accrued utility revenues 72,915 76,131 Materials and supplies (at average cost) 91,652 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 (Note 18) 59,162 66,973 Other current assets 103,978 80,203 ---------- ---------- Total current assets 812,688 727,405 ---------- ---------- INVESTMENTS AND OTHER ASSETS Real estate investments - net (Notes 1 and 6) 425,331 418,673 Assets from risk management and trading activities - long term (Note 18) 122,336 200,351 Other assets 229,891 304,453 ---------- ---------- Total investments and other assets 777,558 923,477 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10) Plant in service and held for future use 9,058,900 8,030,847 Less accumulated depreciation and amortization 3,474,325 3,290,097 ---------- ---------- Total 5,584,575 4,740,750 Construction work in progress 777,542 1,047,072 Intangible assets, net of accumulated amortization (Note 21) 109,815 86,782 Nuclear fuel, net of accumulated amortization of $102,821 and $99,185 7,466 6,933 ---------- ---------- Net property, plant and equipment 6,479,398 5,881,537 ---------- ---------- DEFERRED DEBITS Regulatory assets (Notes 1, 3 and 4) 241,045 342,383 Other deferred debits 115,117 64,597 ---------- ---------- Total deferred debits 356,162 406,980 ---------- ---------- TOTAL ASSETS $8,425,806 $7,939,399 ========== ==========
See Notes to Consolidated Financial Statements. 76 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands)
December 31, ---------------------------- 2002 2001 ----------- ----------- LIABILITIES AND EQUITY CURRENT LIABILITIES Accounts payable $ 356,305 $ 269,124 Accrued taxes 71,109 96,729 Accrued interest 53,018 48,806 Short-term borrowings (Note 5) 102,183 405,762 Current maturities of long-term debt (Note 6) 281,023 126,140 Customer deposits 55,838 30,232 Deferred income taxes (Note 4) -- 3,244 Liabilities from risk management and trading activities (Note 18) 70,667 35,994 Other current liabilities 64,972 69,475 ----------- ----------- Total current liabilities 1,055,115 1,085,506 ----------- ----------- LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6) 2,881,695 2,673,078 ----------- ----------- DEFERRED CREDITS AND OTHER Liabilities from risk management and trading activities-long term (Note 18) 75,642 207,576 Deferred income taxes (Note 4) 1,209,074 1,064,993 Unamortized gain - sale of utility plant (Note 9) 59,484 64,060 Pension liability (Note 8) 183,880 49,032 Other 274,763 295,831 ----------- ----------- Total deferred credits and other 1,802,843 1,681,492 ----------- ----------- COMMITMENTS AND CONTINGENCIES (NOTES 3, 11 AND 12) COMMON STOCK EQUITY (Note 7) Common stock, no par value; authorized 150,000,000 shares; issued 91,379,947 at end of 2002 and 84,824,947 at end of 2001 1,737,258 1,536,924 Treasury stock; 124,830 shares at end of 2002 and 101,307 shares at end of 2001 (4,358) (5,886) ----------- ----------- Total common stock 1,732,900 1,531,038 ----------- ----------- Accumulated other comprehensive loss: Minimum pension liability adjustment (71,264) (966) Derivative instruments (20,020) (63,599) ----------- ----------- Total accumulated other comprehensive loss (91,284) (64,565) ----------- ----------- Retained earnings 1,044,537 1,032,850 ----------- ----------- Total common stock equity 2,686,153 2,499,323 ----------- ----------- TOTAL LIABILITIES AND EQUITY $ 8,425,806 $ 7,939,399 =========== ===========
See Notes to Consolidated Financial Statements. 77 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands)
Year Ended December 31, --------------------------------------------- 2002 2001 2000 ----------- ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES Income before accounting change $ 215,153 $ 327,367 $ 302,332 Items not requiring cash: Depreciation and amortization 424,886 427,903 431,229 Nuclear fuel amortization 31,185 28,362 30,083 Deferred income taxes 196,324 (17,203) (37,885) Change in mark-to-market (18,146) (133,573) (11,752) Redhawk Units 3 and 4 cancellation 49,192 -- -- Changes in current assets and liabilities: Customer and other receivables 18,615 146,581 (269,223) Materials, supplies and fossil fuel (11,599) (16,867) 475 Other current assets (9,784) (1,276) (39,083) Accounts payable 74,833 (127,782) 193,502 Accrued taxes (36,039) 7,483 18,736 Accrued interest 4,212 5,852 9,701 Other current liabilities 17,489 5,260 98,493 Change in real estate investments (6,112) (44,173) (25,937) Increase in regulatory assets (11,029) (17,516) (14,138) Change in risk management and trading - assets (11,700) (51,894) -- Change in risk management and trading - liabilities (22,783) 45,330 13,834 Change in customer advances (23,780) 28,599 2,544 Change in pension liability (1,571) (28,347) (16,575) Change in long-term assets (16,918) 13,874 54,829 Change in long-term liabilities 8,346 (26,937) (27,771) ----------- ----------- ----------- Net cash flow provided by operating activities 870,774 571,043 713,394 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (895,522) (1,055,574) (658,608) Capitalized interest (44,110) (47,862) (21,638) Other 36,635 (16,481) (55,595) ----------- ----------- ----------- Net cash flow used for investing activities (902,997) (1,119,917) (735,841) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 725,419 995,447 651,000 Short-term borrowings and payments - net (303,579) 322,987 44,475 Dividends paid on common stock (137,721) (129,199) (120,733) Repayment of long-term debt (404,670) (621,057) (558,019) Common stock equity issuance 199,238 -- -- Other 2,624 (1,048) (4,618) ----------- ----------- ----------- Net cash flow provided by financing activities 81,311 567,130 12,105 ----------- ----------- ----------- NET CASH FLOW 49,088 18,256 (10,342) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 28,619 10,363 20,705 ----------- ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 77,707 $ 28,619 $ 10,363 =========== =========== =========== Supplemental disclosure of cash flow information Cash paid during the period for: Income taxes paid/(refunded) (Note 4) $ (17,918) $ 223,037 $ 219,411 Interest paid, net of amounts capitalized $ 126,322 $ 115,276 $ 132,434
See Notes to Consolidated Financial Statements. 78 PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED 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 (Note 7) Balance at beginning of year $ 1,536,924 $ 1,537,920 $ 1,540,197 Issuance of common stock 199,238 -- -- Other 1,096 (996) (2,277) ----------- ----------- ----------- Balance at end of year 1,737,258 1,536,924 1,537,920 ----------- ----------- ----------- TREASURY STOCK (Note 7) Balance at beginning of year (5,886) (5,089) (2,748) Purchase of treasury stock (5,971) (16,393) (12,968) Reissuance of treasury stock used for stock compensation, net 7,499 15,596 10,627 ----------- ----------- ----------- Balance at end of year (4,358) (5,886) (5,089) ----------- ----------- ----------- RETAINED EARNINGS Balance at beginning of year 1,032,850 849,883 668,284 Net income 149,408 312,166 302,332 Common stock dividends (137,721) (129,199) (120,733) ----------- ----------- ----------- Balance at end of year 1,044,537 1,032,850 849,883 ----------- ----------- ----------- ACCUMULATED OTHER COMPREHENSIVE LOSS Balance at beginning of year (64,565) -- -- Minimum pension liability adjustment, net of tax of $46,109 and $634 (70,298) (966) -- Cumulative effect of a change in accounting for derivatives, net of tax of $47,404 -- 72,274 -- Unrealized gain/(loss) on derivative instruments, net of tax of $28,820 and $71,720 43,939 (109,346) -- Reclassification of realized gain to income, net of tax of $237 and $17,399 (360) (26,527) -- ----------- ----------- ----------- Balance at end of year (91,284) (64,565) -- ----------- ----------- ----------- TOTAL COMMON STOCK EQUITY $ 2,686,153 $ 2,499,323 $ 2,382,714 =========== =========== =========== COMPREHENSIVE INCOME Net income $ 149,408 $ 312,166 $ 302,332 Other comprehensive loss (26,719) (64,565) -- ----------- ----------- ----------- Comprehensive income $ 122,689 $ 247,601 $ 302,332 =========== =========== ===========
See Notes to Consolidated Financial Statements. 79 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CONSOLIDATION AND NATURE OF OPERATIONS The consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). Significant intercompany accounts and transactions between the consolidated companies have been eliminated. APS is 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 APS. APS also generates, sells and delivers electricity to wholesale customers in the western United States. In early 2003, the marketing and trading division of Pinnacle West was moved to APS 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 APS' generating assets to Pinnacle West Energy. See Note 3 for a discussion of the Track A Order. Pinnacle West Energy, which was formed in 1999, is the subsidiary through which we conduct our competitive generation operations. APS Energy Services was formed in 1998 and provides competitive commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico and Utah. El Dorado is an investment firm, and its principal investment is in NAC, which is a company specializing in spent nuclear fuel technology. 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. 80 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 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 Consolidated 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 18 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 Consolidated 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. 81 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 Note 18 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 marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC. REGULATORY ACCOUNTING APS is 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 APS' generation operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a discussion of the 1999 Settlement Agreement. 82 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 Consolidated Statement of Income. In 2002, the ACC directed APS not to transfer its generation assets, as previously required by the 1999 Settlement Agreement (see "Track A Order" in Note 3). Accordingly, we now consider APS 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 consolidated 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 APS' 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 Consolidated 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 11) 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). 83 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Regulatory liabilities are included in deferred credits and other on the Consolidated 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 ==== ==== 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 Consolidated 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 - 22 years; * Nuclear plant - 22 years; * Transmission - 34 years; * Distribution - 28 years; and * Other utility property - 9 years. 84 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 and 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. EL DORADO INVESTMENTS El Dorado accounts for its investments using the consolidated (if controlled), equity (if significant influence) and cost (less than 20% ownership) methods. Beginning in the third quarter of 2002, El Dorado began consolidating the operations of NAC. See Note 22 for further details on El Dorado's investment in NAC. 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 earnings. The rate used to calculate capitalized interest was a composite rate of 4.80% for 2002, 6.13% 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 Consolidated 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 Consolidated Statements of Income on a net basis. SUNCOR SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed. A single method of recognizing income is applied to all sales transactions within an entire home, land or commercial development project. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. 85 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS PERCENTAGE OF COMPLETION - NAC Certain NAC contract revenues are accounted for under the percentage-of-completion method. Revenues are recognized based upon total costs incurred to date compared to total costs expected to be incurred for each contract. Revisions in contract revenue and cost estimates are reflected in the accounting period when known. Provisions are made for the full amounts of anticipated losses in the periods in which they are first determined. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and income, and are recognized in the period in which revisions are determined. Profit incentives are included in revenues when their realization is reasonably assured. Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs and depreciation costs. General and administrative costs are charged to expense as incurred. CASH AND CASH EQUIVALENTS For purposes of the Consolidated 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 APS charges 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. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense. APS also charges 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 APS $0.001 per kWh of nuclear generation. See Note 11 for information about spent nuclear fuel disposal and Note 12 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." We file our federal income tax return on a consolidated basis and we file our 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 each subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between the aforementioned allocations and the consolidated (and unitary) income tax liability is attributed to the parent company. 86 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS REACQUIRED DEBT COSTS For debt related to the regulated portion of APS' business, APS amortizes those gains and losses incurred upon early retirement over the original remaining life of the debt. In accordance with the 1999 Settlement Agreement, APS is 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 Consolidated Statements of Income. REAL ESTATE INVESTMENTS Real estate investments primarily include SunCor's land, home inventory and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. STOCK-BASED COMPENSATION 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, stock compensation expense and earnings per share 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, except per share amounts): 87 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2002 2001 2000 --------- --------- --------- Net Income: As reported $ 149,408 $ 312,166 $ 302,332 Pro forma (fair value method) 148,013 309,874 301,102 Stock compensation expense (net of tax): As reported 300 -- -- Pro forma (fair value method) 1,395 2,292 1,230 Earnings per share - basic: As reported $ 1.76 $ 3.68 $ 3.57 Pro forma (fair value method) $ 1.74 $ 3.66 $ 3.55 Earnings per share - diluted: As reported $ 1.76 $ 3.68 $ 3.56 Pro forma (fair value method) $ 1.74 $ 3.65 $ 3.55 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 16 for further discussion about our stock compensation plans. 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 88 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. For each of the years 2002, 2001 and 2000, items requiring discontinued operations reporting were immaterial. 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. 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: 89 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS * Notes 1 and 16 for a new accounting standard (SFAS No. 148) related to stock-based compensation; * Note 18 for a new EITF issue (EITF 02-3) related to accounting for energy trading contracts; * Note 20 for a new interpretation (FIN No. 46) related to VIEs; * Note 21 for a new standard (SFAS No. 142) related to goodwill and intangible assets; and * Note 23 for a new interpretation (FIN No. 45) on guarantees. 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 APS and various parties related to the implementation of retail electric competition in Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its 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, APS had been addressing the legal and regulatory requirements necessary to complete the transfer of its 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 APS not to transfer its generation assets to Pinnacle West Energy. See "Track A Order" below. On September 16, 2002, APS filed an application with the ACC requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or to the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company's debt; or a combination of both, not to exceed $500 million in the aggregate. In its application, APS stated that the ACC's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS 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 the Company 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" below. 90 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS COMPETITIVE PROCUREMENT PROCESS 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. Under the order, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS 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 APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' 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 APS' right to reject any bids that are unreasonable, uneconomical or unreliable. APS expects 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 APS' 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: * APS has 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 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 APS 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 91 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS limited circumstances. Neither the ACC nor APS 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 APS' cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. * APS 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. * APS' 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. APS opened its 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 APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory. * Prior to the 1999 Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). APS will not be allowed to recover $183 million net present value (in 1999 dollars) of the above amounts. The 1999 Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition 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. * APS will form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its 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. APS will be allowed to defer and later collect, beginning July 1, 2004, 67% of its 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 APS from transferring its generation assets. 92 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 APS. * Effective January 1, 2001, retail access became available to all APS 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, APS received a waiver to allow transfer of its 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 APS to transfer its generation assets. Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement. On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling 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 APS' property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have 93 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, APS is 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 APS 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 APS' 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 APS' current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS 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 APS' 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 hearings would begin on June 17, 2002 on various issues, including APS' 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 APS to transfer its 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 APS' transfer of its generating assets, and directed APS to cancel its activities to transfer its generation assets to Pinnacle West Energy. 94 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Provisions related to the wholesale competitive energy procurement process (Track B issues): * The ACC stayed indefinitely the requirement of the Rules that APS acquire 100% of its energy needs for its standard offer customers from the competitive market, with at least 50% obtained through a competitive bid process; * the ACC established a requirement that APS competitively procure, at a minimum, any required power that it cannot produce from its 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 the existing APS assets and the Pinnacle West Energy assets. On November 15, 2002, APS filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals. ARIZONA PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, CV 2002-0222 32. ARIZONA PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, 1CA CC 02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for resolving certain issues raised by APS in its appeals of the Track A Order. APS and the ACC 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 APS' upcoming general rate case, anticipated to be filed before June 30, 2003: * the generating assets to be included in APS' 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 APS' rate base; * the appropriate treatment of the $234 million pretax asset write-off agreed to by APS as part of a 1999 settlement agreement approved by the ACC among APS and various parties related to the implementation of retail competition in Arizona; and * the appropriate treatment of costs incurred by APS 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, APS' 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. 95 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS On February 21, 2003, a Notice of Claim was filed with the ACC and the Arizona Attorney General on behalf of APS, Pinnacle West and Pinnacle West Energy 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, APS will be required to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, APS 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 APS' total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS' retail load and APS' 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 APS' 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 APS and any affiliate of APS that may participate in the competitive solicitation, requires that APS treat bidders in a non-discriminatory manner and requires APS 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 confidential APS bidding information that is not available to other bidders. The order directs APS 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, APS will prepare a report evaluating environmental issues relating to the procurement and a series of workshops on environmental risk management will be commenced thereafter. APS expects 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 APS' electricity requirements. 96 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ACC APPLICATIONS On September 16, 2002, APS filed a Financing Application requesting the ACC to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle West Energy or the Company; to guarantee up to $500 million of Pinnacle West Energy's or the Company'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: * APS noted that its 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 APS generation assets under a common financial and regulatory regime. APS 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 APS' 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. * APS stated that it did not intend or desire to foreclose the possibility that it would acquire all or part of the Pinnacle West Energy Assets or that it may propose that the Pinnacle West Energy Assets be included in APS' rate base or afforded cost-of-service regulatory treatment to the extent the Pinnacle West Energy Assets are used by APS customers. APS stated that these issues would be appropriate topics in APS' 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. * APS stated that the Track A Order's reversal of the generation asset transfer requirement and the resulting bifurcation of generation assets between APS 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 the Company to fund the construction of the Pinnacle West Energy Assets or from effectively competing in the wholesale markets. APS noted that Pinnacle West Energy had previously received investment-grade credit ratings contingent upon its receipt of APS generation assets and that the Company'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 the Company's senior unsecured debt rating from "BBB" to "BBB-." * APS stated that the amount of the requested loan and/or guarantee is APS' present estimate of the amount of credit support necessary through APS to restore Pinnacle West Energy and the Company to their credit status prior to the ACC's issuance of the Track A Order. APS further stated that if the requested amount proves to be inadequate, APS reserves the right to submit a second financing application seeking additional credit support. 97 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS On March 27, 2003, the ACC approved the Financing Application, subject to the following principal conditions: * any debt issued by APS pursuant to the order must be unsecured; * APS 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 APS 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 APS' cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases; * APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its common equity ratio below that threshold, unless otherwise waived by the ACC. 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 98 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 SNWA if SNWA 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, the Company will need to refinance approximately $475 million of parent company indebtedness. We expect that this indebtedness will be repaid through funds borrowed by Pinnacle West Energy from APS under the APS Loan. On November 22, 2002, the ACC approved APS' request to permit APS 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 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 APS' service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment. 99 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. INCOME TAXES 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. APS has recorded a regulatory asset related to income taxes on its 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. APS amortizes this amount as the differences reverse. In accordance with ACC settlement agreements, APS is 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 our Consolidated Statements of Income. As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction has resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return. The components of income tax expense for income before accounting change are (dollars in thousands): Year Ended December 31, ----------------------------------------- 2002 2001 2000 --------- --------- --------- Current: Federal $ (43,492) $ 184,893 $ 189,779 State (14,732) 45,845 42,306 --------- --------- --------- Total current (58,224) 230,738 232,085 Deferred 196,324 (17,203) (37,885) --------- --------- --------- Total income tax expense $ 138,100 $ 213,535 $ 194,200 ========= ========= ========= The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): 100 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Year Ended December 31, ---------------------------------- 2002 2001 2000 --------- --------- --------- Federal income tax expense at 35% statutory rate $ 123,639 $ 189,316 $ 173,786 Increases (reductions) in tax expense resulting from: State income tax net of federal income tax benefit 16,478 23,353 19,848 Other (2,017) 866 566 --------- --------- --------- Income tax expense $ 138,100 $ 213,535 $ 194,200 ========= ========= ========= The following table sets forth the net deferred income tax liability recognized on the Consolidated 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 (1,209,074) (1,064,993) ----------- ----------- Accumulated deferred income taxes - net $(1,204,980) $(1,068,237) =========== =========== The components of the net deferred income tax liability were as follows (dollars in thousands): December 31, ------------------------- 2002 2001 ----------- ----------- DEFERRED TAX ASSETS Pension liability $ 72,835 $ 19,422 Risk management and trading activities 43,542 73,043 Deferred gain on Palo Verde Unit 2 sale-leaseback 23,562 25,374 Other 99,054 90,580 ----------- ----------- Total deferred tax assets 238,993 208,419 ----------- ----------- 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 (46,702) (85,692) ----------- ----------- Total deferred tax liabilities (1,443,973) (1,276,656) ----------- ----------- Accumulated deferred income taxes - net $(1,204,980) $(1,068,237) =========== =========== 5. LINES OF CREDIT AND SHORT-TERM BORROWINGS APS 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 101 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS mature in June 2003. The commitment fees at December 31, 2002 and 2001 for these lines of credit were 0.09% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2002 and 2001. APS 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, APS' short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC. Pinnacle West had committed lines of credit of $475 million at December 31, 2002 and $250 million at December 31, 2001, which were available either to support the issuance of commercial paper or to be used for bank borrowings. Outstanding amounts at December 31, 2002 were $72 million, and there were no short-term bank borrowings outstanding at December 31, 2001. The commitment fees ranged from 0.10% to 0.15% in 2002 and 2001. Pinnacle West commercial paper borrowings outstanding were $24 million at December 31, 2002 and $235 million at December 31, 2001. The weighted average interest rate on commercial paper borrowings was 2.06% for the year ended December 31, 2002 and 3.50% for the year ended December 31, 2001. On July 31, 2002, Pinnacle West completed a $300 million bank credit facility, which was subsequently reduced to $225 million by applying $75 million of the proceeds from the equity offering in December 2002 (see Note 7). The borrowings are LIBOR-based, can be drawn upon as needed and are expected to be used primarily to fund Pinnacle West Energy capital requirements. The facility matures in July 2003. The majority of these borrowings were used to fund Pinnacle West Energy capital expenditures. At December 31, 2002, Pinnacle West had borrowed $67 million under the credit facility. On November 22, 2002, the ACC approved APS' request to permit APS 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. SunCor had revolving lines of credit totaling $140 million at December 31, 2002 and 2001. The commitment fees were 0.125% in 2002 and 2001. SunCor had $126 million outstanding at December 31, 2002 and $128 million outstanding at December 31, 2001. The balance is included in long-term debt on the Consolidated Balance Sheets (see Note 6). SunCor had short-term loans in the amount of $6 million at December 31, 2002 and no short-term loans outstanding at December 31, 2001. 102 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. LONG-TERM DEBT Borrowings under the APS mortgage bond indenture are secured by substantially all utility plant. APS also has unsecured debt. SunCor's debt is collateralized by interests in certain real property and Pinnacle West's debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2002 and 2001 (dollars in thousands): 103 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, Maturity Interest ---------------------------- Dates (a) Rates 2002 2001 --------- ----- ----------- ----------- APS 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 ----------- ----------- Subtotal 2,220,843 2,074,525 ----------- ----------- SUNCOR Revolving credit 2003-2004 (h) 125,500 128,000 Notes payable 2003-2008 (i) 7,646 7,912 Bonds payable 2024 5.95% 5,090 5,215 Bonds payable 2026 6.75% 7,500 7,500 Capitalized lease obligations 2003-2007 8.91% 1,299 -- ----------- ----------- Subtotal 147,035 148,627 ----------- ----------- PINNACLE WEST Senior notes 2003-2006 (j) 540,000 325,000 Unamortized discount and premium (530) -- Floating rate notes 2003 (k) 250,000 250,000 Capitalized lease obligations 2004-2007 5.48% 1,999 1,066 ----------- ----------- Subtotal 791,469 576,066 ----------- ----------- EL DORADO Construction loan 2005 1.77% 2,600 -- Capitalized lease obligations 2004-2005 7.04% 771 -- ----------- ----------- Subtotal 3,371 -- ----------- ----------- Total long-term debt 3,162,718 2,799,218 Less current maturities 281,023 126,140 ----------- ----------- TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES $ 2,881,695 $ 2,673,078 =========== ===========
104 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (a) This schedule does not reflect the timing of redemptions that may occur prior to maturity. (b) On March 15, 2002, APS redeemed at maturity $125 million of its First Mortgage Bonds, 8.125% Series due 2002. (c) On April 15, 2002, APS redeemed $122 million of its 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 APS 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. (g) APS currently has 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. APS' payments of principal, premium and/or interest on the senior notes satisfy its 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 APS repays all of its 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. (h) The weighted-average rate was 3.75% at December 31, 2002 and was 5.31% at December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 2% or prime plus 0.5%. (i) Multiple notes primarily with variable interest rates based mostly on the lenders' prime plus 1.75% and lenders' prime plus .25%. (j) Includes three series of notes: $25 million at 6.87% due in 2003, $300 million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of December 31, 2002. (k) The weighted average rate was 2.85% at December 31, 2002 and was 4.65% at December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 0.98%. Pinnacle West's and APS' significant debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS are in compliance with such covenants and each anticipates it 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. Neither Pinnacle West's nor APS' financing agreements contain "ratings triggers" that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements. 105 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All of Pinnacle West's bank agreements contain "cross-default" provisions under which a default by it or APS in a specified amount under another agreement would result in a default and the potential acceleration of payment under the agreements. All of APS' bank agreements contain cross-default provisions under which a default by APS in a specified amount under another agreement would result in a default and the potential acceleration of payment under the agreements. Pinnacle West's and APS' credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's financial condition or financial prospects. The following is a list of payments due on total long-term debt and capitalized lease requirements through 2007: * $281 million in 2003; * $552 million in 2004; * $405 million in 2005; * $390 million in 2006; * $3 million in 2007; and * $1,539 million, thereafter. APS' 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. APS may pay dividends on its 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 APS to pay approximately $3 billion of dividends compared to APS' current annual common stock dividends of $170 million. 7. COMMON STOCK AND TREASURY STOCK Our common stock and treasury stock activity during each of the three years 2002, 2001 and 2000 is as follows (dollars in thousands, except shares): 106 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COMMON STOCK TREASURY STOCK ------------------------- ------------------------- SHARES AMOUNT SHARES AMOUNT ---------- ----------- ---------- ----------- Balance at December 31, 1999 84,824,947 $ 1,540,197 (74,844) $ (2,748) Purchase of treasury stock (300,800) (12,968) Reissuance of treasury stock for stock compensation (net) 266,006 10,627 Other (2,277) ---------- ----------- ---------- ----------- Balance at December 31, 2000 84,824,947 1,537,920 (109,638) (5,089) Purchase of treasury stock (334,600) (16,393) Reissuance of treasury stock for stock compensation (net) 342,931 15,596 Other (996) ---------- ----------- ---------- ----------- Balance at December 31, 2001 84,824,947 1,536,924 (101,307) (5,886) Common stock issuance - December 23, 2002 6,555,000 199,238 Purchase of treasury stock (150,500) (5,971) Reissuance of treasury stock for stock compensation (net) 126,977 7,499 Other 1,096 ---------- ----------- ---------- ----------- Balance at December 31, 2002 91,379,947 $ 1,737,258 (124,830) $ (4,358) ========== =========== ========== ===========
8. 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 our 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. 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 the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay. We fund 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. Total pension expense, including administrative costs and after consideration of amounts capitalized or billed to electric plant participants, was: * $14 million in 2002; * $11 million in 2001; and 107 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS * $6 million in 2000. The following table shows the components of 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):
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 the Consolidated Balance Sheets as of 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 the 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 the qualified defined benefit pension plans' change in the fair value of plan assets for the plan years 2002 and 2001 (dollars in thousands): 108 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED 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 the defined benefit pension plans' amounts recognized in the 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 the 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 our subsidiaries. In a defined contribution savings plan, the benefits a participant will receive result from regular contributions they make to a participant account. Under this plan, we make matching contributions in Pinnacle West stock to participant accounts. After a five-year vesting period, participants have a choice to change the employer 109 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 $5 million for 2002 and 2001 and $4 million for 2000. OTHER POSTRETIREMENT BENEFITS Pinnacle West sponsors other postretirement benefits for the employees of Pinnacle West and our subsidiaries. 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 other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, was: * $12 million for 2002; * $6 million for 2001; and * $3 million for 2000. The following table shows the components of 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 the Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in thousands): 110 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED 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 the 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. The following table sets forth the 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 ========= ========= 111 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 on 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)
SEVERANCE CHARGES In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $36 million before taxes in voluntary severance costs in 2002. No further charges are expected. 9. LEASES In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale-leaseback transactions. APS accounts 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 20 for a discussion of VIEs, including the SPEs involved in the Palo Verde sale-leaseback transactions. 112 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 Consolidated Statements of Income was $62 million in 2002, $56 million in 2001 and $58 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, APS is 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 Consolidated 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 as follows (dollars in millions): Year ------------------ 2003 $ 70 2004 66 2005 64 2006 63 2007 63 Thereafter 478 ----- Total future lease commitments $ 804 ===== 10. JOINTLY-OWNED FACILITIES APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS' interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2002. APS' share of operating and maintaining these facilities is included in the Consolidated Statements of Income in operations and maintenance expense. 113 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 9) 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 APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned. (b) Weighted average of interests. 11. COMMITMENTS AND CONTINGENCIES ENRON We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. This amount is comprised of a $15 million reserve for the Company's net exposure to Enron and its affiliates and additional expenses of $6 million primarily related to 2002 power contracts with Enron that were canceled. These charges take into consideration our rights of set-off with respect to the Enron related contractual obligations. The APS portion of the write-off was $13 million. 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 APS 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 written-off from the balances of the related assets and liabilities from risk management and trading activities on the Consolidated 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 114 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE's delay, a number of utilities 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. APS has existing fuel storage pools at Palo Verde and is 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, APS believes 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, APS is currently shipping low-level waste to off-site facilities. APS currently believes 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. APS currently estimates it will incur $115 million (in 2002 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2002, APS had spent $2 million and 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, APS 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 million per incident. Based on APS' interest in the three Palo Verde units, APS' maximum potential assessment per incident for all three units is approximately $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. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of 115 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 APS and Pinnacle West are parties 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 $173 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 APS has for the supply of its 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 APS 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 Consolidated Balance Sheets. 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, APS is 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 Consolidated 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 116 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. On December 12, 2002, the 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. APS does not anticipate material changes in its exposure and still believes, subject to the finalization of the revised proxy prices, that it will be entitled to a net refund. 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. 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. 117 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 operations 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. We are closely monitoring developments in the California energy market and the potential impact of these developments on us and our subsidiaries. Based on our evaluations, we previously reserved $10 million before income taxes for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001. Our evaluations took into consideration our range of exposure of approximately zero to $38 million before income taxes and review of likely recovery rates in bankruptcy situations. In the second quarter of 2002, PG&E filed its Modified Second Amended Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization. Both plans generally indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstanding, undisputed debts. As a result of these developments, the probable range of our total exposure now is approximately zero to $27 million before income taxes, and our best estimate of the probable loss is now approximately $6 million before income taxes. Consequently, we reversed $4 million of the $10 million reserve in the second quarter of 2002. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us, our subsidiaries or the regional energy market in general. 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 APS, attempting 118 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit. APS was also named in a lawsuit regarding wholesale contracts in California. 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 APS and numerous other PX participants. CAL PX V. THE STATE OF CALIFORNIA Superior Court in and for the County of Sacramento, JCCP No. 4203. Various 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 us, 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 APS 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 APS that it believes APS overcharged Citizens by over $50 million under a power service agreement. APS believes its 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, based on its review, "if Citizens filed a complaint with FERC, it probably would lose the central issue in the contract interpretation dispute." APS and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, the Company and Citizens entered into a power sale agreement under which the Company 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. CONSTRUCTION PROGRAM Consolidated capital expenditures in 2003 are estimated to be (dollars in millions): APS $ 401 Pinnacle West Energy 268 SunCor 64 Other (primarily APS Energy Services and Pinnacle West) 17 ----- Total $ 750 ===== 119 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS PINNACLE WEST ENERGY'S GENERATION CONSTRUCTION Pinnacle West Energy's generation construction plan is as follows: * A 650 MW combined cycle expansion of the West Phoenix Power Plant in Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation in June 2001. Construction has begun on the 530 MW West Phoenix Unit 5, with commercial operation expected to begin in mid-2003. * The Redhawk Power Plant, two 530 MW combined cycle units, near Palo Verde. Commercial operation began in July 2002. Based on an analysis of the financial situation of the Company and the market as a whole, among other things, Pinnacle West has cancelled plans to construct the additional two 530 MW combined cycle units, Redhawk Units 3 and 4. As a result we recorded a pretax charge of approximately $49 million in December 2002. * The construction of an 80 MW simple-cycle power plant at Saguaro in Southern Arizona. Commercial operation began in July 2002. * Development of the 570 MW Silverhawk combined-cycle plant 20 miles north of Las Vegas, Nevada. Construction of the plant began in August 2002, with an expected commercial operation date of mid-2004. Pinnacle West Energy has signed an agreement with Las Vegas-based SNWA under which SNWA has an option to purchase a 25% interest in the project for approximately $100 million. * A Pinnacle West Energy affiliate is exploring the possibility of creating an underground natural gas storage facility on Company-owned land west of Phoenix. An analysis to determine the feasibility of the project is in progress. 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 consolidated financial statements, results of operations or liquidity. 12. NUCLEAR DECOMMISSIONING COSTS APS recorded $11 million for nuclear decommissioning expense in each of the years 2002, 2001 and 2000. APS estimates it will cost approximately $1.8 billion ($528 million in 2002 dollars) to decommission its 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. APS charges decommissioning costs to expense over each unit's operating license term and APS includes them in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are recovered in rates. 120 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS APS' 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. APS is required by the ACC to update the study every three years. To fund the costs APS expects to incur to decommission the plant, APS established external decommissioning trusts in accordance with NRC regulations and ACC orders. APS invests the trust funds primarily in fixed income securities and domestic stock and classifies 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 Consolidated Balance Sheets at December 31, 2002 and 2001 (dollars in millions): 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. 121 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 13. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) Consolidated quarterly financial information for 2002 and 2001 is as follows:
(dollars in thousands, except per share amounts) 2002 ------------------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 (a) -------- ------- ------------ --------------- Operating revenues (b) Regulated electricity segment $ 380,241 $ 496,837 $ 719,361 $ 416,584 Marketing and trading segment 75,815 49,503 87,258 113,355 Real estate segment 41,185 69,152 45,108 80,943 Other revenues (c) 4,277 2,881 21,224 33,555 Operating income $ 119,438 $ 166,706 $ 213,025 $ 16,878 Income (loss) before accounting change $ 53,757 $ 75,365 $ 100,916 $ (14,885) Cumulative effect of change in accounting - net of income tax -- -- -- (65,745) --------- --------- --------- --------- Net income (loss) $ 53,757 $ 75,365 $ 100,916 $ (80,630) ========= ========= ========= ========= Earnings (loss) per weighted average common share outstanding - basic: Income before accounting change $ 0.63 $ 0.89 $ 1.19 $ (0.18) Cumulative effect of change in accounting -- -- -- (0.77) --------- --------- --------- --------- Earnings per weighted average common share outstanding - basic $ 0.63 $ 0.89 $ 1.19 $ (0.95) ========= ========= ========= ========= Earnings (loss) per weighted average common share outstanding - diluted: Income before accounting change $ 0.63 $ 0.89 $ 1.19 $ (0.18) Cumulative effect of change in accounting -- -- -- (0.77) --------- --------- --------- --------- Earnings per weighted average common share outstanding - diluted $ 0.63 $ 0.89 $ 1.19 $ (0.95) ========= ========= ========= ========= Dividends declared per share $ 0.40 $ 0.40 $ 0.40 $ 0.425
122 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(dollars in thousands, except per share amounts) 2001 ---------------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 -------- ------- ------------ ------------ Operating revenues (b) Regulated electricity segment $ 412,807 $ 739,317 $ 973,398 $ 436,569 Marketing and trading segment 258,296 233,841 141,674 17,419 Real estate segment 32,335 32,454 43,024 61,095 Other revenues 1,543 1,653 2,682 5,893 Operating income $ 136,646 $ 140,010 $ 298,752 $ 100,615 Income before accounting change $ 62,205 $ 66,857 $ 162,499 $ 35,806 Cumulative effect of change in accounting - net of income tax (2,755) -- (12,446) -- --------- --------- --------- --------- Net income $ 59,450 $ 66,857 $ 150,053 $ 35,806 ========= ========= ========= ========= Earnings (loss) per weighted average common share outstanding - basic: Income before accounting change $ 0.73 $ 0.79 $ 1.92 $ 0.42 Cumulative effect of change in accounting (0.03) -- (0.15) -- --------- --------- --------- --------- Earnings per weighted average common share outstanding - basic $ 0.70 $ 0.79 $ 1.77 $ 0.42 ========= ========= ========= ========= Earnings (loss) per weighted average common share outstanding - diluted: Income before accounting change $ 0.73 $ 0.79 $ 1.91 $ 0.42 Cumulative effect of change in accounting (0.03) -- (0.14) -- --------- --------- --------- --------- Earnings per weighted average common share outstanding - diluted $ 0.70 $ 0.79 $ 1.77 $ 0.42 ========= ========= ========= ========= Dividends declared per share $ 0.375 $ 0.375 $ 0.375 $ 0.40
(a) The fourth quarter of 2002 included pretax losses of $38 million related to our investment in NAC (see Note 22), a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of approximately $11 million. 123 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (b) Electric revenues are 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 18). (c) NAC financial statements were fully consolidated starting in third quarter 2002 (see Note 22). 14. 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 $3.15 billion, with an estimated fair value of $3.25 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $2.80 billion on December 31, 2001, with an estimated fair value of $2.82 billion. The fair value estimates are based on quoted market prices of the same or similar issues. 15. EARNINGS PER SHARE The following table presents earnings per weighted average common share outstanding for the years ended December 31, 2002, 2001 and 2000: 2002 2001 2000 -------- -------- -------- Basic earnings per share: Income before accounting change $ 2.53 $ 3.86 $ 3.57 Cumulative effect of change in accounting (0.77) (0.18) -- -------- -------- -------- Earnings per share-basic $ 1.76 $ 3.68 $ 3.57 ======== ======== ======== Diluted earnings per share: Income before accounting change $ 2.53 $ 3.85 $ 3.56 Cumulative effect of change in accounting (0.77) (0.17) -- -------- -------- -------- Earnings per share-diluted $ 1.76 $ 3.68 $ 3.56 ======== ======== ======== Dilutive stock options increased average common shares outstanding by 60,975 shares in 2002, 212,491 shares in 2001 and 202,738 shares in 2000. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 84,963,921 shares in 2002, 84,930,140 shares in 2001 and 84,935,282 shares in 2000. 124 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Options to purchase 1,629,958 shares of common stock were outstanding at December 31, 2002 but were not included in the computation of diluted earnings per share because the options' exercise price was greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 212,562 at December 31, 2001 and 517,614 at December 31, 2000. 16. STOCK-BASED COMPENSATION Pinnacle West offers stock-based compensation plans for officers and key employees of our company and our subsidiaries. In May 2002, 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. The Company 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 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 $500,000 in stock option expense before income taxes in our Consolidated 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. 125 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Total stock-based compensation expense, including stock option expense, was $5 million in 2002, $3 million in 2001 and $2 million in 2000. The following table is a summary of the status of our stock option plans as of December 31, 2002, 2001 and 2000 and changes during the years ending on those dates:
2002 2001 2000 Weighted Weighted Weighted Average Average Average 2002 Exercise 2001 Exercise 2000 Exercise Shares Price Shares Price Shares Price ---------- -------- ---------- -------- ---------- -------- Outstanding at beginning of year 1,832,725 $39.52 1,569,171 $37.55 1,441,124 $33.45 Granted 603,900 (a) 38.37 444,200 42.55 451,450 43.28 Exercised (163,381) 28.25 (162,229) 28.53 (283,819) 20.90 Forfeited (88,115) 41.54 (18,417) 41.67 (39,584) 39.86 ---------- ---------- ---------- Outstanding at end of year 2,185,129 39.96 1,832,725 39.52 1,569,171 37.55 ========== ========== ========== Options exercisable at year-end 1,155,357 39.66 926,315 37.41 831,537 34.37 ========== ========== ========== Weighted average fair value of options granted during the year 6.16 8.84 11.81
(a) Beginning 2002, we recorded compensation expense related to stock options under SFAS No. 123 (see above discussion). The following table summarizes information about our stock options at December 31, 2002:
Weighted Weighted Average Weighted Average Remaining Average Exercise Options Exercise Contract Options Exercise Prices Per Share Outstanding Price Life (Years) Exercisable Price - ---------------- ----------- ----- ------------ ----------- ----- $18.71 - 23.39 50,584 $ 20.73 1.3 50,584 $ 20.73 23.39 - 28.07 48,417 27.40 3.4 41,750 27.44 28.07 - 32.75 46,000 31.44 3.9 46,000 31.44 32.75 - 37.42 235,160 34.70 6.7 235,160 34.70 37.42 - 42.10 779,700 38.85 8.3 181,900 40.01 42.10 - 46.78 1,025,268 43.95 7.7 599,963 44.59 ---------- ---------- 2,185,129 1,155,357 ========== ==========
126 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2002, 2001 and 2000:
2002 2001 2000 Weighted Weighted Weighted Average Average Average 2002 Grant-Date 2001 Grant-Date 2000 Grant-Date Shares Fair Value Shares Fair Value Shares Fair Value ------ ---------- ------ ---------- ------ ---------- Restricted stock 6,000 $38.84 95,450 $42.84 86,426 $44.03 Performance share awards 115,975 38.37 -- -- -- -- Stock ownership incentive awards (a) 9,650 38.37 -- -- -- --
(a) Shares are based on estimated ownership of Pinnacle West common stock. 17. BUSINESS SEGMENTS We have three principal business segments (determined by products, 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; * our marketing and trading segment, which consists of our competitive business activities, including wholesale marketing and trading and APS Energy Services' commodity-related energy services; and * our real estate segment, which consists of SunCor's real estate development and investment activities. The amounts in our other segment include activity principally related to NAC in 2002 (see Note 22), as well as the parent company and other subsidiaries. Financial data for the years ended December 31, 2002, 2001 and 2000 by business segments is provided as follows (dollars in millions): 127 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Business Segments for the Year Ended December 31, 2002 ------------------------------------------------------------- Marketing Other Regulated and (principally Electricity Trading Real Estate NAC) Total ----------- ------- ----------- ------- ------- Operating revenues $ 2,013 $ 326 $ 236 $ 62 $ 2,637 Purchased power and fuel costs 500 194 -- -- 694 Other operating expenses 659 34 205 105 1,003 ------- ------- ------- ------- ------- Operating margin 854 98 31 (43) 940 Depreciation and amortization 416 2 5 2 425 Interest and other expense 160 -- (5) 8 163 ------- ------- ------- ------- ------- Pretax margin 278 96 31 (53) 352 Income taxes 108 38 12 (21) 137 ------- ------- ------- ------- ------- Income (loss) before accounting change 170 58 19 (32) 215 Cumulative effect of change in accounting for trading activities - net of income taxes of $43 -- (66) -- -- (66) ------- ------- ------- ------- ------- Net income(loss) $ 170 $ (8) $ 19 $ (32) $ 149 ======= ======= ======= ======= ======= Total assets $ 7,589 $ 301 $ 504 $ 32 $ 8,426 ======= ======= ======= ======= ======= Capital expenditures $ 893 $ 19 $ 72 $ -- $ 984 ======= ======= ======= ======= ======= Business Segments for the Year Ended December 31, 2001 ------------------------------------------------------------- Marketing Regulated and Electricity Trading Real Estate Other Total ----------- ------- ----------- ------- ------- Operating revenues $ 2,562 $ 651 $ 169 $ 12 $ 3,394 Purchased power and fuel costs 1,161 334 -- -- 1,495 Other operating expenses 598 33 154 11 796 ------- ------- ------- ------- ------- Operating margin 803 284 15 1 1,103 Depreciation and amortization 423 1 4 -- 428 Interest and other expense 129 -- 6 -- 135 ------- ------- ------- ------- ------- Pretax margin 251 283 5 1 540 Income taxes 99 112 2 -- 213 ------- ------- ------- ------- ------- Income before accounting change 152 171 3 1 327 Cumulative effect of change in accounting for derivatives - net of income taxes of $10 (15) -- -- -- (15) ------- ------- ------- ------- ------- Net income $ 137 $ 171 $ 3 $ 1 $ 312 ======= ======= ======= ======= ======= Total assets $ 6,862 $ 589 $ 477 $ 11 $ 7,939 ======= ======= ======= ======= ======= Capital expenditures $ 1,004 $ 23 $ 80 $ 22 $ 1,129 ======= ======= ======= ======= =======
128 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Business Segments for the Year Ended December 31, 2000 ------------------------------------------------------------- Marketing Regulated and Electricity Trading Real Estate Other Total ----------- ------- ----------- ------- ------- Operating revenues $ 2,539 $ 418 $ 158 $ 4 $ 3,119 Purchased power and fuel costs 1,066 292 -- -- 1,358 Other operating expenses 532 18 134 1 685 ------- ------- ------- ------- ------- Operating margin 941 108 24 3 1,076 Depreciation and amortization 426 1 5 -- 432 Interest and other expense 152 -- -- (4) 148 ------- ------- ------- ------- ------- Pretax margin 363 107 19 7 496 Income taxes 142 42 8 2 194 ------- ------- ------- ------- ------- Net income $ 221 $ 65 $ 11 $ 5 $ 302 ======= ======= ======= ======= ======= Total assets $ 6,213 $ 459 $ 429 $ 22 $ 7,123 ======= ======= ======= ======= ======= Capital expenditures $ 665 $ -- $ 50 $ -- $ 715 ======= ======= ======= ======= =======
18. 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 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. 129 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. 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 Consolidated 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. Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Consolidated 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 in 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 Consolidated 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. 130 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 changes in derivative fair value included in the Consolidated 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) $ 11,198 $ (6,056) Losses from the discontinuance of cash flow hedges (8,820) (4,683) Losses from non-hedge derivatives (4,324) (7,157) Prior period mark-to-market losses realized upon delivery of commodities 8,005 25,948 -------- -------- Total pretax gain $ 6,059 $ 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 seven years. During the twelve months ending December 31, 2003, we estimate that a net loss of $26 million before income 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. The following table summarizes our assets and liabilities from risk management and trading activities related to system and marketing and trading at December 31, 2002 and 2001 (dollars in thousands): 131 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002 Current Current Other Net Asset/ Assets Investments Liabilities Liabilities (Liability) --------- --------- --------- --------- --------- Mark-to- market: Marketing and Trading $ 17,640 $ 51,771 $ (9,848) $ (2,583) $ 56,980 System 41,522 6,971 (60,819) (36,678) (49,004) Emission allowances - at cost -- 58,067 -- (14,328) 43,739 Collateral provided (held) -- 5,527 -- (22,053) (16,526) --------- --------- --------- --------- --------- Total $ 59,162 $ 122,336 $ (70,667) $ (75,642) $ 35,189 ========= ========= ========= ========= ========= December 31, 2001 Current Current Other Net Asset/ Assets Investments Liabilities Liabilities (Liability) --------- --------- --------- --------- --------- Mark-to- market: Marketing and Trading $ 56,876 $ 148,457 $ (14,154) $ (53,253) $ 137,926 System 10,097 -- (21,840) (95,159) (106,902) Emission allowances - at cost -- (3,216) -- (59,164) (62,380) Collateral provided -- 55,110 -- -- 55,110 --------- --------- --------- --------- --------- Total $ 66,973 $ 200,351 $ (35,994) $(207,576) $ 23,754 ========= ========= ========= ========= =========
CREDIT RISK We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 33% of our $181 million of risk management and trading assets as of December 31, 2002. We use a risk management process to assess and monitor the financial exposure of those and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities 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 132 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. 19. 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 -- -- 6,882 Interest income 4,410 6,763 8,291 SunCor joint venture earnings 7,471 3,687 3,208 Miscellaneous 3,223 3,617 3,451 -------- -------- -------- Total other income $ 15,104 $ 26,416 $ 21,832 ======== ======== ======== Other expense: Equity losses - net (a) $(10,439) $ (5,126) $ -- Non-operating costs - SunCor -- (7,000) -- Non-operating costs (b) (19,430) (16,807) (16,044) Miscellaneous (3,786) (4,644) (9,285) -------- -------- -------- Total other expense $(33,655) $(33,577) $(25,329) ======== ======== ======== (a) Primarily related to El Dorado's investment losses in NAC prior to consolidation in the third quarter of 2002 (see Note 22). (b) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and environmental compliance). 20. 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, APS entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. See Note 9 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 133 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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. APS is also exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2002, APS would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million. 21. 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 Consolidated 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 $214 million at December 31, 2002 and $175 million at December 31, 2001. The related accumulated amortization was $104 million at December 31, 2002 and $88 million at December 31, 2001. Amortization expense was $21 million in 2002, $22 million in 2001 and $20 million in 2000. Estimated amortization expense on existing intangible assets over the next five years is $25 million in 2003, $24 million in 2004, $23 million in 2005, $21 million in 2006 and $15 million in 2007. 22. EL DORADO'S INVESTMENT IN NAC Through our unregulated wholly-owned subsidiary, El Dorado, we own a majority interest in NAC, a company that develops, markets and contracts for the manufacture of cask designs for spent nuclear fuel storage and transportation. Prior to the third quarter of 2002, our investment in NAC was accounted for under the equity method and our share of NAC's earnings and losses was recorded in other income or expense in our Consolidated Statements of Income. Beginning in the third quarter of 2002, we fully consolidated NAC's financial statements after acquiring a controlling interest in NAC as a result of increased voting representation on NAC's Board of Directors. During the second and third quarters of 2002, we recorded cumulative losses of approximately $21 million before tax ($13 million after tax, $0.15 per share) related to NAC, primarily as a result of expected losses under contracts with two customers, including a contract between NAC and Maine Yankee Atomic Power Company (Maine Yankee). On January 15, 2003, Maine Yankee notified NAC of its intention to terminate its contract with NAC. We recorded additional NAC losses of approximately $38 million before tax ($23 million after tax, or $0.27 per share) in the fourth quarter of 2002, the substantial majority of which relate to the termination of the Maine Yankee contract. As a result, in 2002, we recorded NAC losses of approximately $59 million before tax ($35 million after tax, or $0.42 per share). 134 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NAC LITIGATION On March 4, 2003, Maine Yankee Atomic Power Co. filed suit against Pinnacle West, NAC and a surety company in federal court in Portland, Maine. MAINE YANKEE ATOMIC POWER COMPANY V. UNITED STATES FIRE INSURANCE COMPANY, Civil Action Docket No. 03-58-PC, United States District Court, District of Maine. The lawsuit alleges that NAC failed to meet its contractual obligations with respect to certain of NAC's activities relating to the decommissioning of the Maine Yankee nuclear power plant. The lawsuit was filed a few weeks after NAC initiated arbitration against Maine Yankee with respect to matters relating to the same contract. The lawsuit seeks recovery under a parental guarantee signed by Pinnacle West relating to certain of NAC's contractual obligations and under performance and payment bonds issued by the surety which are guaranteed (at least in part) by Pinnacle West. Maine Yankee also alleges damages in excess of $1 million. We are currently evaluating the allegations of the lawsuit and expect to vigorously defend our position. 23. GUARANTEES On January 1, 2003 we adopted FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure provisions are effective for the year ended December 31, 2002. The initial recognition and measurement provisions of FIN No. 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction program, transmission service guarantees for West Phoenix Units 4 and 5 and long-term service agreement guarantees for new power plants. Our credit support instruments enable APS Energy Services to provide commodity energy and energy-related products and enable El Dorado to support the activities of NAC. SunCor has a debt guarantee on behalf of an affiliated joint venture. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West's guarantees on behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2002 are as follows (dollars in millions): 135 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Guarantees Surety Bonds Letters of Credit ------------------- ---------------------- ----------------------- Term Term Term Amount (in years) Amount (in years) Amount (in years) ------ ---------- ------ ---------- ------ ---------- Parental: Pinnacle West Energy $126 1 to 2 $ -- -- $ 42 1 to 2 APS Energy Services 82 less than 2 43 less than 1 -- -- El Dorado (all NAC) 43 1 to 3 -- -- -- -- SunCor guarantees 33 1 -- -- -- -- ---- ---- ---- Total $284 $ 43 $ 42 ==== ==== ====
At December 31, 2002, we had entered into approximately $42 million of letters of credit which support various construction agreements. These letters of credit expire in 2003 and 2004. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required. APS has entered into various agreements that require letters of credit for financial assurance purposes. At 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 of such debt obligations. These letters of credit have expiration dates in 2003. APS has 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, APS has 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. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required. 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. APS has 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. 136 PINNACLE WEST CAPITAL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 24. 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 APS 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 APS must competitively procure energy. See "California Energy Issues and Refunds in the Pacific Northwest" in Note 11 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. See Note 22 for information related to the March 4, 2003 NAC litigation. 137 PINNACLE WEST CAPITAL CORPORATION SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Column A Column B Column C Column D Column E Additions --------------------- Balance at Charged to Charged Balance beginning cost and to other at end of Description of period expenses accounts Deductions Period ----------- --------- -------- -------- ---------- ------ (dollars in thousands) YEAR ENDED DECEMBER 31, 2002 Real Estate Valuation Reserves $ 2,000 $ -- $ -- $ 339(a) $ 1,661 YEAR ENDED DECEMBER 31, 2001 Real Estate Valuation Reserves $ 2,000 $ -- $ -- $ --(a) $ 2,000 YEAR ENDED DECEMBER 31, 2000 Real Estate Valuation Reserves $ 8,000 $ -- $ -- $ 6,000(a) $ 2,000 YEAR ENDED DECEMBER 31, 2002 Reserve for uncollectibles $ 14,334 $ (21) $ -- $ 4,705 $ 9,608 YEAR ENDED DECEMBER 31, 2001 Reserve for uncollectibles $ 7,580 $ 13,394 $ -- $ 6,640 $ 14,334 YEAR ENDED DECEMBER 31, 2000 Reserve for uncollectibles $ 1,538 $ 10,638 $ -- $ 4,596 $ 7,580 YEAR ENDED DECEMBER 31, 2002 Reserve for contract losses $ -- $ 13,000(b) $ -- $ -- $ 13,000
(a) Represents pro-rata allocations for sale of land. (b) Contract losses related to NAC. 138 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 Reference is hereby made to "Election of Directors" and to "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 21, 2003 (the "2003 Proxy Statement") and to the Supplemental Item --- "Executive Officers of the Registrant" in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION Reference is hereby made to "The Board and its Committees - How are Directors Compensated?"; "Performance Graph"; and "Executive Compensation" in the 2003 Proxy Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Reference is hereby made to "Election of Directors - How many shares of Pinnacle West stock are owned by management and large shareholders?" in the 2003 Proxy Statement. SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS The following table sets forth information as of December 31, 2002 with respect to our compensation plans and individual compensation arrangements under which our equity securities were authorized for issuance to directors, officers, employees, consultants and certain other persons and entities in exchange for the provision to us of goods or services. 139
NUMBER OF SECURITIES REMAINING AVAILABLE FOR NUMBER OF SECURITIES TO WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER EQUITY BE ISSUED UPON EXERCISE EXERCISE PRICE OF COMPENSATION PLANS (EXCLUDING OF OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, SECURITIES REFLECTED IN PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS COLUMN (a)) (a) (b) (c) - ---------------------------- ----------------------- -------------------- ----------------------------- Equity compensation plans approved by security holders 2,185,129 $ 39.96 5,317,145 Equity compensation plans not approved by security holders -- $ -- 172,100 ---------- ---------- Total 2,185,129 $ 39.96 5,489,245 ========== ==========
EQUITY COMPENSATION PLANS APPROVED BY SECURITY HOLDERS The Company has four equity compensation plans that were approved by its shareholders: the Pinnacle West Capital Corporation Stock Option and Incentive Plan, under which no new options may be granted; the Pinnacle West Capital Corporation Directors Stock Option Plan under which no new options may be granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan; and the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan. See Note 16 for additional information regarding these plans. EQUITY COMPENSATION PLANS NOT APPROVED BY SECURITY HOLDERS The Company has one equity compensation plan, the Pinnacle West Capital Corporation 2000 Director Equity Plan (the "2000 Plan"), for which the approval of shareholders was not required. NUMBER OF SHARES SUBJECT TO THE 2000 PLAN. The total number of shares of the Company's common stock granted under the 2000 Plan may not exceed 200,000. In the case of a significant corporate event, such as a reorganization, merger or consolidation, the 2000 Plan provides for adjustment of the above limit, the number of shares to be awarded automatically to eligible non-employee directors, the number of shares of the Company's common stock non-employee directors are required to own to receive an annual grant of common stock and options granted under the 2000 Plan. ELIGIBILITY FOR PARTICIPATION. Only non-employee directors may participate in the 2000 Plan. A non-employee director is an individual who is a director of the Company but who is not also an employee of the Company or any of its subsidiaries. TERMS OF AWARDS. The 2000 Plan provides for: (1) annual grants of common stock to eligible non-employee directors, (2) discretionary grants of common stock to eligible non-employee directors and (3) grants of nonqualified stock options to eligible non-employee directors. 140 ANNUAL GRANTS OF STOCK Each individual who is a non-employee director as of July 1 of a calendar year, and who meets requirements of ownership of the Company's common stock set forth below, will receive 900 shares of the Company's common stock for such calendar year. In the first calendar year in which a non-employee director is eligible to participate in the 2000 Plan, he or she must own at least 900 shares of the Company's common stock as of December 31 of the same calendar year to receive a grant of 900 shares of the Company's common stock. If the non-employee director owns 900 shares of common stock as of June 30, he or she will receive a grant of 900 shares of common stock as of July 1 of the same calendar year. If the non-employee director does not own 900 shares of the Company's common stock as of June 30, but acquires the necessary shares on or before December 31 of the same year, he or she will receive a grant of 900 shares of common stock within a reasonable time after the Company verifies that the requisite number of shares has been acquired. In each subsequent year, the number of shares of the Company's common stock the non-employee director must own to receive a grant of 900 shares of common stock will increase by 900 shares, until reaching a maximum of 4,500 shares. In each of the subsequent years, the non-employee director must own the requisite number of shares of the Company's common stock as of June 30 of the relevant calendar year. DISCRETIONARY GRANTS OF STOCK The Human Resources Committee of the Board of Directors, excluding those members who are not "Non-Employee Directors" under SEC Rule 16b-3(b)(3) (the Committee) administers the 2000 Plan and may grant shares of the Company's common stock to non-employee directors in its discretion. No discretionary grants of common stock have been made under the 2000 Plan. GRANTS OF NONQUALIFIED STOCK OPTIONS The Committee can grant nonqualified stock options under the 2000 Plan. The terms and the conditions of the option grant, including the exercise price per share, which may not be less than fair market value on the date of grant, will be set by the Committee in a written award agreement. The Committee will determine the time or times at which any such options may be exercised in whole or in part. The Committee will also determine the performance or other conditions, if any, that must be satisfied before all or part of an option may be exercised. Any such options granted to a participant will expire on the tenth anniversary date of the date of grant, unless the option is earlier terminated, forfeited or surrendered pursuant to a provision of the 2000 Plan or the applicable award agreement. Notwithstanding the foregoing, if a participant ceases to be a Company director for any reason, including death or disability, any such options held by that participant will expire on the second anniversary of the date on which the participant ceased to be a Company director, unless otherwise provided in the applicable award agreement. Unless the Committee provides otherwise, no such options may be sold, transferred, pledged, assigned or otherwise alienated, other than by will, the laws of descent and distribution, or under any other circumstances allowed by the Committee. No options have been granted under the 2000 Plan. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is hereby made to "Executive Compensation - Human Resources Committee Interlocks and Insider Participation" and "- Employment and Severance Arrangements" in the 2003 Proxy Statement. 141 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. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES See the Index to Consolidated Financial Statements and Financial Statement Schedule in Part II, Item 8. EXHIBITS FILED EXHIBIT NO. DESCRIPTION - ----------- ----------- 4.1 -- Fifty-sixth Supplemental Indenture to the Mortgage dated as of March 1, 2003 4.2 -- Fifty-seventh Supplemental Indenture to the Mortgage dated as of April 1, 2003 10.1(a) -- 2003 Officer Variable Incentive Plan 10.2(a) -- 2003 CEO Variable Incentive Plan 10.3(a) -- Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended 10.4(a) -- Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler 10.5(a) -- Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan 12.1 -- Ratio of Earnings to Fixed Charges 21.1 -- Subsidiaries of the Company 23.1 -- Consent of Deloitte & Touche LLP 142 99.1 -- Certification of William J. Post, 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 Articles of Incorporation, 19.1 to the Company's September 1-8962 11-14-88 restated as of July 29, 1988 1988 Form 10-Q Report 3.2 Bylaws, amended as of 3.2 to September 2002 Form 10-Q 1-8962 11-14-02 September 18, 2002 Report 4.3 Mortgage and Deed of Trust 4.1 to APS' September 1992 Form 1-4473 11-9-92 Relating to APS' First 10-Q Report Mortgage Bonds, together with forty-eight indentures supplemental thereto 4.4 Forty-ninth Supplemental 4.1 to APS' 1992 Form 10-K Report 1-4473 3-30-93 Indenture 4.5 Fiftieth Supplemental 4.2 to APS' 1993 Form 10-K Report 1-4473 3-30-94 Indenture 4.6 Fifty-first Supplemental 4.1 to APS' August 1, 1993 Form 1-4473 9-27-93 Indenture 8-K Report 4.7 Fifty-second Supplemental 4.1 to APS' September 30, 1993 1-4473 11-15-93 Indenture Form 10-Q Report
143
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 4.8 Fifty-third Supplemental 4.5 to APS' Registration 1-4473 3-1-94 Indenture Statement No. 33-61228 by means of February 23, 1994 Form 8-K Report 4.9 Fifty-fourth Supplemental 4.1 to APS' 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 4.10 Fifty-fifth Supplemental 4.8 to APS' 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 4.11 Agreement, dated March 21, 4.1 to APS' 1993 Form 10-K Report 1-4473 3-30-94 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS' total assets 4.12 Indenture dated as of January 4.6 to APS' Registration 1-4473 1-11-95 1, 1995 among APS and The Statement Nos. 33-61228 and Bank of New York, as Trustee 33-55473 by means of January 1, 1995 Form 8-K Report 4.13 First Supplemental Indenture 4.4 to APS' 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 APS' Registration 1-4473 11-22-96 November 15, 1996 among APS Statements Nos. 33-61228, and The Bank of New York, as 33-55473, 33-64455 and 333- 15379 Trustee by means of November 19, 1996 Form 8-K Report
144
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 4.15 First Supplemental Indenture 4.6 to APS' 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 Indenture 4.10 to APS' Registration 1-4473 4-9-97 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 4.1 to the Company's Registration 1-8962 1-25-01 December 1, 2000 between the Statement No. 333-53150 Company and The Bank of New York, as Trustee, relating to Senior Debt Securities 4.18 First Supplemental Indenture 4.2 to the Company's Registration 1-8962 3-26-01 dated as of March 15, 2001 Statement No. 333-52476 4.19 Indenture dated as of 4.2 to the Company's Registration 1-8962 1-25-01 December 1, 2000 between the Statement No. 333-53150 Company and The Bank of New York, as Trustee, relating to subordinated Debt Securities 4.20 Specimen Certificate of 4.2 to the Company's 1988 Form 1-8962 3-31-89 Pinnacle West Capital 10-K Report Corporation Common Stock, no par value 4.21 Agreement, dated March 29, 4.1 to the Company's 1987 Form 1-8962 3-30-88 1988, relating to the filing 10-K Report of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company's total assets
145
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 4.22 Indenture dated as of January 4.10 to APS' Registration The 1-4473 1-16-98 15, 1998 among APS and Chase Statement Nos. 333-15379 and Manhattan Bank, as Trustee 333-27551 by means of January 13, 1998 Form 8-K Report 4.23 First Supplemental Indenture 4.3 to APS' 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 4.24 Second Supplemental Indenture 4.3 to APS' Registration 1-4473 2-22-99 dated as of February 15, 1999 Statement Nos. 333-27551 and 333-58445 by means of February 18, 1999 Form 8-K Report 4.25 Third Supplemental Indenture 4.5 to APS' Registration 1-4473 11-5-99 dated as of November 1, 1999 Statement Nos. 333-58445 by means of November 2, 1999 Form 8-K Report 4.26 Fourth Supplemental Indenture 4.1 to Registration Statement No. 1-4473 8-4-00 dated as of August 1, 2000 333-58445 and 333-94277 by means of August 2, 2000 Form 8-K Report 4.27 Fifth Supplemental Indenture 4.1 to APS' September 2001 Form 1-4473 11-6-01 dated as of October 1, 2001 10-Q 4.28 Sixth Supplemental Indenture 4.1 to APS' Registration 1-4473 2-28-01 dated as of March 1, 2002 Statement Nos. 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report
146
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 4.29 Amended and Restated Rights 4.1 to the Company's March 22, 1-8962 4-19-99 Agreement, dated as of March 1999 Form 8-K Report 26, 1999, between Pinnacle West Capital Corporation and BankBoston, N.A., as Rights Agent, including (i) as Exhibit A thereto the form of Amended Certificate of Designation of Series A Participating Preferred Stock of Pinnacle West Capital Corporation, (ii) as Exhibit B thereto the form of Rights Certificate and (iii) as Exhibit C thereto the Summary of Right to Purchase Preferred Shares 4.30 Amendment to Rights 4.1 to March 2002 Form 10-Q Report 1-8962 5-15-02 Agreement, effective as of January 1, 2002 10.6 Two separate Decommissioning 10.2 to APS' September 1991 Form 1-4473 11-14-91 Trust Agreements (relating 10-Q Report to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee 10.7 Amendment No. 1 to 10.1 to APS' 1994 Form 10- K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 1), dated as of December 1, 1994
147
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.8 Amendment No. 1 to 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 3), dated as of December 1, 1994 10.9 Amendment No. 2 to APS 10.4 to APS' 1996 Form 10-K 1-4473 3-28-97 Decommissioning Trust Report Agreement (PVNGS Unit 1) dated as of July 1, 1991 10.10 Amendment No. 2 to APS 10.6 to APS' 1996 Form 10-K 1-4473 3-28-97 Decommissioning Trust Report Agreement (PVNGS Unit 3) dated as of July 1, 1991 10.11 Amended and Restated 10.1 to the Company's 1991 Form 1-8962 3-26-92 Decommissioning Trust 10-K Report Agreement (PVNGS Unit 2) dated as of January 31, 1992, among APS, 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
148
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.12 First Amendment to Amended 10.2 to APS' 1992 Form 10-K 1-4473 3-30-93 and Restated Decommissioning Report Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992 10.13 Amendment No. 2 to Amended 10.2 to APS' 1994 Form 10-K 1-4473 3-30-95 and Restated Decommissioning Report Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994 10.14 Amendment No. 3 to Amended 10.1 to APS' June 1996 Form 10-Q 1-4473 8-9-96 and Restated Decommissioning Report Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994 10.15 Amendment No. 4 to Amended APS 10.5 to APS' 1996 Form 10-K 1-4473 3-28-97 and Restated Decommissioning Report Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 10.16 Amendment No. 5 to the 10.1 to Pinnacle West's March 1-8962 5-15-02 Amended and Restated 2002 Form 10-Q Report Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000 10.17 Amendment No. 3 to the 10.2 to Pinnacle West's March 1-8962 5-15-02 Decommissioning Trust 2002 Form 10-Q Report Agreement (PVNGS Unit 1), dated as of March 18, 2002
149
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.18 Amendment No. 6 to the 10.3 to Pinnacle West's March 1-8962 5-15-02 Amended and Restated 2002 Form 10-Q Report Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002 10.19 Amendment No. 3 to the 10.4 to Pinnacle West's March 1-8962 5-15-02 Decommissioning Trust 2002 Form 10-Q Report Agreement (PVNGS Unit 3), dated as of March 18, 2002 10.20 Asset Purchase and Power 10.1 to APS' June 1991 Form 10-Q 1-4473 8-8-91 Exchange Agreement dated Report September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991 10.21 Long-Term Power Transaction 10.2 to APS' June 1991 Form 10-Q 1-4473 8-8-91 Agreement dated September 21, Report 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991 10.22 Amendment No. 1 dated April 10.3 to APS' 1995 Form 10-K 1-4473 3-29-96 5, 1995 to the Long-Term Report Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS 10.23 Restated Transmission 10.4 to APS' 1995 Form 10-K 1-4473 3-29-96 Agreement between PacifiCorp Report and APS dated April 5, 1995
150
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.24 Contract among PacifiCorp, 10.5 to APS' 1995 Form 10-K 1-4473 3-29-96 APS and United States Report Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995 10.25 Reciprocal Transmission 10.6 to APS' 1995 Form 10-K 1-4473 3-29-96 Service Agreement between APS Report and PacifiCorp dated as of March 2, 1994 10.26 Contract, dated July 21, 10.31 to the Company's Form S-14 2-96386 3-13-85 1984, with DOE providing for Registration Statement the disposal of nuclear fuel and/or high-level radioactive waste, ANPP 10.27 Indenture of Lease with 5.01 to APS' Form S-7 2-59644 9-1-77 Navajo Tribe of Indians, Four Registration Statement Corners Plant 10.28 Supplemental and Additional 5.02 to APS' 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 10.29 Amendment and Supplement No. 10.36 to the Company's 1-8962 7-25-85 1 to Supplemental and Registration Statement on Form Additional Indenture of Lease 8-B Report Four Corners, dated April 25, 1985
151
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.30 Application and Grant of 5.04 to APS' Form S-7 2-59644 9-1-77 multi-party rights-of-way and Registration Statement easements, Four Corners Plant Site 10.31 Application and Amendment No. 10.37 to the Company's 1-8962 7-25-85 1 to Grant of multi-party Registration Statement on Form rights-of-way and easements, 8-B Four Corners Power Plant Site dated April 25, 1985 10.32 Application and Grant of 5.05 to APS' Form S-7 2-59644 9-1-77 Arizona Public Service Registration Statement Company rights-of-way and easements, Four Corners Plant Site 10.33 Four Corners Project 10.7 to the Company's 2000 Form 1-8962 3-14-01 Co-Tenancy Agreement 10-K Report Amendment No. 6 10.34 Application and Amendment No. 10.38 to the Company's 1-8962 7-25-85 1 to Grant of Arizona Public Registration Statement on Form Service Company 8-B rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985 10.35 Indenture of Lease, Navajo 5(g) to APS' Form S-7 2-36505 3-23-70 Units 1, 2, and 3 Registration Statement 10.36 Application of Grant of 5(h) to APS Form S-7 Registration 2-36505 3-23-70 rights-of-way and easements, Statement Navajo Plant 10.37 Water Service Contract 5(l) to APS' Form S-7 2-394442 3-16-71 Assignment with the United Registration Statement States Department of Interior, Bureau of Reclamation, Navajo Plant
152
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.38 Arizona Nuclear Power Project 10.1 to APS' 1988 Form 10-K 1-4473 3-8-89 Participation Agreement, dated August 23, 1973, among APS 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 10.39 Amendment No. 13, dated as 10.1 to APS' March 1991 Form 10-Q 1-4473 5-15-91 of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, 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
153
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.40 Amendment No. 14 to Arizona 99.1 to the Company's June 2000 1-8962 8-14-00 Nuclear Power Project Form 10-Q Report Participation Agreement, dated August 23, 1973, among APS, 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 10.41(c) Facility Lease, dated as of 4.3 to APS' Form S-3 Registration 33-9480 10-24-86 August 1, 1986, between State Statement Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee 10.42(c) Amendment No. 1, dated as of 10.5 to APS' September 1986 Form 1-4473 12-4-86 November 1, 1986, to Facility 10-Q Report by means of Lease, dated as of August 1, Amendment No. on December 3, 1986, between State Street 1986 Form 8 Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee
154
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.43(c) Amendment No. 2 dated as of 10.3 to APS' 1988 Form 10-K 1-4473 3-8-89 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 10.44(c) Amendment No. 3, dated as of 10.3 to APS' 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, 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 10.45 Facility Lease, dated as of 10.1 to APS' 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 APS, as Lessee 10.46 Amendment No. 1, dated as of 4.13 to APS' Form S-3 1-4473 8-24-87 August 1, 1987, to Facility Registration Statement No. Lease, dated as of December 33-9480 by means of August 1, 15, 1986, between State 1987 Form 8-K Report Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee
155
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.47 Amendment No. 2, dated as of 10.4 to APS' 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to 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 Lessor, and APS, as Lessee 10.48(a) Pinnacle West Capital 10.13 to the Company's 1999 Form 1-8962 3-30-00 Corporation Supplemental 10-K Report Excess Benefit Retirement Plan, as amended and restated, dated December 7, 1999 10.49(a) First Amendment to the 10.4 to Pinnacle West's 2001 Form 1-8962 3-27-02 Pinnacle West Capital 10-K Report Corporation Supplemental Excess Benefit Retirement Plan 10.50(a) Second Amendment to the 10.5 to Pinnacle West's 2001 Form 1-8962 3-27-02 Pinnacle West Capital 10-K Report Corporation Supplemental Excess Benefit Retirement Plan 10.51(a) Trust for the Pinnacle West 10.14 to the Company's 1999 Form 1-8962 3-30-00 Capital Corporation, Arizona 10-K Report Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996
156
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.52(a) First Amendment dated 10.15 to the Company's 1999 Form 1-8962 3-30-00 December 7, 1999 to the Trust 10-K Report for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans 10.53(a) Directors' Deferred 10.1 to APS' June 1986 Form 10-Q 1-4473 8-13-86 Compensation Plan, as Report restated, effective January 1, 1986 10.54(a) Second Amendment to the 10.2 to APS' 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Deferred Compensation Plan, effective as of January 1, 1993 10.55(a) Third Amendment to the 10.1 to APS' September 1994 Form 1-4473 11-10-94 Arizona Public Service 10-Q Company Directors' Deferred Compensation Plan, effective as of May 1, 1993 10.56(a) Fourth Amendment dated 10.8 to the Company's 1999 Form 1-8962 3-30-00 December 28, 1999 to the 10-K Report Arizona Public Service Company Directors Deferred Compensation Plan 10.57(a) Arizona Public Service 10.4 to APS' 1988 Form 10-K 1-4473 3-8-89 Company Deferred Compensation Report Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987 respectively
157
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.58(a) Third Amendment to the 10.3 to APS' 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Deferred Compensation Plan, effective as of January 1, 1993 10.59(a) Fourth Amendment to the 10.2 to APS' September 1994 Form 1-4473 11-10-94 Arizona Public Service 10-Q Report Company Deferred Compensation Plan effective as of May 1, 1993 10.60(a) Fifth Amendment to the 10.3 to APS' 1996 Form 10-K 1-4473 3-28-97 Arizona Public Service Report Company Deferred Compensation Plan 10.61(a) Sixth Amendment to Arizona 10.8 to the Company's 2000 Form 1-8962 3-14-01 Public Service Company 10-K Report Deferred Compensation Plan 10.62(a) First Amendment effective as 10.7 to the Company's 1999 Form 1-8962 3-30-00 of January 1, 1999, to the 10-K Report Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan
158
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.63(a) Second Amendment effective 10.10 to the Company's 1999 Form 1-8962 3-30-00 January 1, 2000 to the 10-K Report Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan 10.64(a) Pinnacle West Capital 10.10 to APS' 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 10.65(a) Pinnacle West Capital 10.7 to APS' 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 10.66(a) Letter Agreement dated July 10.16 to the Company's 1999 Form 1-8962 3-30-00 28, 1995 between Arizona 10-K Report Public Service Company and Armando B. Flores 10.67(a) Letter Agreement dated as of 10.8 to APS' 1995 Form 10-K 1-4473 3-29-96 January 1, 1996 between APS Report and Robert G. Matlock & Associates, Inc. for consulting services
159
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.68(a) Letter Agreement dated 10.7 to APS' 1994 Form 10-K Report 1-4473 3-30-96 December 21, 1993, between APS and William L. Stewart 10.69(a) Letter Agreement dated 10.8 to APS' 1996 Form 10-K 1-4473 3-28-97 August 16, 1996 between APS Report and William L. Stewart 10.70(a) Letter Agreement between APS 10.2 to APS' September 1997 Form 1-4473 11-12-97 and William L. Stewart 10-Q Report 10.71(a) Letter Agreement dated 10.9 to 1999 Form 10-K Report 1-8962 3-30-00 December 13, 1999 between APS and William L. Stewart 10.72(a) Amendment to Letter 10.1 to June 2002 Form 1-8962 8-13-02 Agreement, effective as of 10-Q Report January 1, 2002, between APS and William L. Stewart 10.73(a) Letter Agreement dated 10.17 to the Company's 1999 Form 1-8962 3-30-00 October 3, 1997 between 10-K Report Arizona Public Service Company and James M. Levine 10.74(a) Summary of James M. 10.2 to March 2002 Form 10-Q 1-8962 5-15-02 Levine Retirement Benefits Report 10.75(a) Employment Agreement, 10.1 to November 2002 Form 10-Q 1-8962 11-14-02 effective as of October 1, Report 2002, between APS and James M. Levine
160
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.76(ad) Key Executive Employment and 10.1 to June 1999 Form 1-8962 8-16-99 Severance Agreement between 10-Q Report Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries 10.77(a) Pinnacle West Capital 10.1 to APS' 1992 Form 10-K 1-4473 3-30-93 Corporation Stock Option and Report Incentive Plan 10.78(a) First Amendment dated 10.11 to the Company's 1999 Form 1-8962 3-30-00 December 7, 1999 to the 10-K Report Pinnacle West Capital Corporation Stock Option and Incentive Plan 10.79(a) Pinnacle West Capital A to the Proxy Statement for the 1-8962 4-16-94 Corporation 1994 Long- Term Plan Report for the Company's Incentive Plan, effective as 1994 Annual Meeting of of March 23, 1994 Shareholders 10.80(a) First Amendment dated 10.12 to the Company's 1999 Form 1-8962 3-30-00 December 7, 1999 to the 10-K Report Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan 10.81(a) Pinnacle West Capital B to the Proxy Statement for the 1-8962 4-16-94 Corporation Director Equity Plan Report for the Company's Participation Plan 1994 Annual Meeting of Shareholders 10.82(a) Pinnacle West Capital 99.1 to the Company's 1-8962 7-3-00 Corporation 2000 Director Registration Statement on Form Equity Plan S-8 (No. 333-40796) 10.83(a) Pinnacle West Capital 99.2 to the Company's 1-8962 7-3-00 Corporation and Arizona Registration Statement on Form Public Service Company S-8 (No. 333-40796) Directors' Retirement Plan, as amended and restated on June 21, 2000
161
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.84 Agreement No. 13904 (Option 10.3 to APS' 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 10.85 Agreement for the Sale and 10.4 to APS' 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 10.86(a) APS Director Equity Plan 10.1 to September 1997 Form 10-Q 1-4473 11-12-97 Report 10.87 Territorial Agreement between 10.1 to APS' March 1998 Form 10-Q 1-4473 5-15-98 the Company and Salt River Report Project 10.88 Power Coordination Agreement 10.2 to APS' March 1998 Form 10-Q 1-4473 5-15-98 between the Company and Salt Report River Project 10.89 Memorandum of Agreement 10.3 to APS' March 1998 Form 10-Q 1-4473 5-15-98 between the Company and Salt Report River Project
162
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 10.90 Addendum to Memorandum of 10.2 to APS' May 19, 1998 Form 1-4473 6-26-98 Agreement between APS and 8-K Report Salt River Project dated as of May 19, 1998 99.4 Collateral Trust Indenture 4.2 to APS' 1992 Form 10 K Report 1-4473 3-30-93 among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee 99.5 Supplemental Indenture to 4.3 to APS' 1992 Form 10 K Report 1-4473 3-30-93 Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee
163
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.6(c) Participation Agreement, 28.1 to APS' September 1992 Form 1-4473 11-9-92 dated as of August 1, 1986, 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, APS, and the Equity Participant named therein 99.7(c) Amendment No. 1 dated as of 10.8 to APS' September 1986 Form 1-4473 12-4-86 November 1, 1986, to 10-Q Report by means of Participation Agreement, Amendment No. 1, on December 3, dated as of August 1, 1986, 1986 Form 8 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, APS, and the Equity Participant named therein
164
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.8(c) Amendment No. 2, dated as of 28.4 to APS' 1992 Form 10-K 1-4473 3-30-93 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, APS, and the Equity Participant named therein 99.9(c) Trust Indenture, Mortgage, 4.5 to APS' Form S-3 Registration 33-9480 10-24-86 Security Agreement and 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
165
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.10(c) Supplemental Indenture No. 1, 10.6 to APS' September 1986 Form 1-4473 12-4-86 dated as of November 1, 1986 10-Q Report by means of to Trust Indenture, Mortgage, Amendment No. 1 on December 3, Security Agreement and 1986 Form 8 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 99.11(c) Supplemental Indenture No. 2 28.14 to APS' 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 Lease Indenture Trustee 99.12(c) Assignment, Assumption and 28.3 to APS' Form S-3 33-9480 10-24-86 Further Agreement, dated as Registration Statement of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
166
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.13(c) Amendment No. 1, dated as of 10.10 to APS' September 1986 Form 1-4473 12-4-86 November 1, 1986, to 10-Q Report by means of Assignment, Assumption and Amendment No. l on December 3, Further Agreement, dated as 1986 Form 8 of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.14(c) Amendment No. 2, dated as of 28.6 to APS' 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Report Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.15 Participation Agreement, 28.2 to APS' September 1992 Form 1-4473 11-9-92 dated as of December 15, 10-Q Report 1986, among PVNGS Funding Report 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, APS, and the Owner Participant named therein
167
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.16 Amendment No. 1, dated as of 28.20 to APS' Form S-3 1-4473 8-10-87 August 1, 1987, to Registration Statement No. Participation Agreement, 33-9480 by means of a November dated as of December 15, 6, 1986 Form 8-K Report 1986, among PVNGS 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, APS, and the Owner Participant named therein 99.17 Amendment No. 2, dated as of 28.5 to APS' 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Report Participation Agreement, dated as of December 15, 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, APS, and the Owner Participant named therein
168
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.18 Trust Indenture, Mortgage 10.2 to APS' November 18, 1986 1-4473 1-20-87 Security Agreement and Form 10-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 99.19 Supplemental Indenture No. 1, 4.13 to APS' Form S-3 1-4473 8-24-87 dated as of August 1, 1987, Registration Statement No. to Trust Indenture, Mortgage, 33-9480 by means of August 1, Security Agreement and 1987 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
169
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.20 Supplemental Indenture No. 2 4.5 to APS' 1992 Form 10-K Report 1-4473 3-30-93 to Trust Indenture Mortgage, Security Agreement 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 Lease Indenture Trustee 99.21 Assignment, Assumption and 10.5 to APS' November 18, 1986 1-4473 1-20-87 Further Agreement, dated as Form 8-K Report of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.22 Amendment No. 1, dated as of 28.7 to APS' 1992 Form 10-K 1-4473 3-30-93 March 17, 1993, to Report Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.23(c) Indemnity Agreement dated as 28.3 to APS' 1992 Form 10-K Report 1-4473 3-30-93 of March 17, 1993 by APS
170
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.24 Extension Letter, dated as of 28.20 to APS' Form S-3 1-4473 8-10-87 August 13, 1987, from the Registration Statement No. signatories of the 33-9480 by means of a November Participation Agreement to 6, 1986 Form 8-K Report Chemical Bank 99.25 Rate Reduction Agreement 10.1 to APS' December 4, 1995 1-4473 12-14-95 dated December 4, 1995 8-K Report between APS and the ACC Staff 99.26 ACC Order dated April 24, 1996 10.1 to APS' March 1996 Form 10-Q 1-4473 5-14-96 Report 99.27 Arizona Corporation 99.1 to APS' 1996 Form 10-K 1-4473 3-28-97 Commission Order, Decision Report No. 59943, dated December 26, 1996, including the Rules regarding the introduction of retail competition in Arizona 99.28 Retail Electric Competition 10.1 to APS' June 1998 Form 10-Q 1-4473 8-14-98 Rules Report 99.29 Arizona Corporation 10.1 to APS' September 1999 10-Q 1-4473 11-15-99 Commission Order, Decision Report No. 61973, dated October 6, 1999, approving APS' Settlement Agreement 99.30 Addendum to Settlement 10.1 to the Company's September 1-8962 11-14-00 Agreement 2000 Form 10-Q Report 99.31 Arizona Corporation 10.2 to APS' September 1999 10-Q 1-4473 11-15-99 Commission Order, Decision Report No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules
171
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) DATE EFFECTIVE - ----------- ----------- ---------------------------- ----------- -------------- 99.32 Track 'A' Appeals Issues - 99.1 to the Company's November 1-8962 12-16-02 Principles for Resolution 15, 2002 Form 8-K 99.33 ACC Opinion and Order dated 99.1 to the Company's September 1-8962 9-17-02 September 10, 2002, Decision 10, 2002 Form 8-K Report No. 65154 (Track A Order) 99.34 Arizona Public Service 99.2 to the Company's September 1-8962 9-17-02 Company Application filed 10, 2002 Form 8-K Report with the Arizona Corporation Commission on September 16, 2002
- ---------- (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 and 1-8962 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 persons. 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. 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 September 30, 2002 containing exhibits comprised of financial information and earnings variance explanations. Report dated October 17, 2002 regarding the Company's earnings outlook and a slide presentation for use at an analyst conference. 172 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 21, 2002 regarding reclassifications of revenue from electricity trading activities to a net basis of reporting. 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 December 17, 2002 containing exhibits to Registration Statement Nos. 333-52476 and 333-101457. Report dated December 31, 2002 regarding an ACC staff report on Track B and containing exhibits comprised of financial information and earnings variance explanations. Report dated January 15, 2003 regarding NAC losses and earnings outlook. 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. 173 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. PINNACLE WEST CAPITAL CORPORATION (Registrant) Date: March 31, 2003 William J. Post ---------------------------------------- (William J. Post, Chairman of the Board of Directors 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 Principal Executive Officer March 31, 2003 - -------------------------------- and Director (William J. Post, Chairman of the Board of Directors and Chief Executive Officer) Jack E. Davis Principal Accounting March 31, 2003 - -------------------------------- Officer and Director (Jack E. Davis, President) Donald E. Brandt Principal Financial Officer March 31, 2003 - -------------------------------- (Donald E. Brandt, Senior Vice President and) Chief Financial Officer) Edward N. Basha, Jr. Director March 31, 2003 - -------------------------------- (Edward N. Basha, Jr.) Michael L. Gallagher Director March 31, 2003 - -------------------------------- (Michael L. Gallagher) 174 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) William L. Stewart Director March 31, 2003 - -------------------------------- (William L. Stewart) CERTIFICATIONS I, William J. Post, certify that: 1. I have reviewed this annual report on Form 10-K of Pinnacle West Capital Corporation; 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; 175 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; 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. William J. Post ---------------------------------------- William J. Post Chairman and Chief Executive Officer I, Donald E. Brandt, certify that: 1. I have reviewed this annual report on Form 10-K of Pinnacle West Capital Corporation; 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; 176 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; 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 177 EX-4.1 4 ex4-1.txt 56TH SUPPLEMENTAL INDENTURE Exhibit 4.1 ================================================================================ ARIZONA PUBLIC SERVICE COMPANY (formerly Central Arizona Light and Power Company) TO THE BANK OF NEW YORK AS TRUSTEE UNDER CENTRAL ARIZONA LIGHT AND POWER COMPANY'S MORTGAGE AND DEED OF TRUST, DATED AS OF JULY 1, 1946. --------------- Fifty-Sixth Supplemental Indenture --------------- DATED AS OF NOVEMBER 1, 2002 This Mortgage covers real property, personal property and chattels. This instrument and the above-mentioned Mortgage and Deed of Trust contain after-acquired property provisions. ================================================================================ FIFTY-SIXTH SUPPLEMENTAL INDENTURE --------------- INDENTURE, dated as of the 1st day of November, 2002, made and entered into by and between ARIZONA PUBLIC SERVICE COMPANY, a corporation of the State of Arizona, the principal place of business and mailing address of which is 400 North Fifth Street, Phoenix, Arizona 85004 (hereinafter sometimes called the Company), party of the first part, and THE BANK OF NEW YORK, a New York banking corporation, the mailing address of which is 385 Rifle Camp Road, 3rd Floor, West Paterson, New Jersey 07424 (hereinafter sometimes called the Trustee), party of the second part, as Trustee under the Mortgage and Deed of Trust, dated as of July 1, 1946 (hereinafter called the Mortgage), which Mortgage was executed and delivered by the Company under its former name, Central Arizona Light and Power Company, to secure the payment of bonds issued or to be issued under and in accordance with the provisions of the Mortgage, reference to which said Mortgage is hereby made, this Indenture (hereinafter called the Fifty-sixth Supplemental Indenture) being supplemental thereto; WHEREAS, said Mortgage was recorded and filed in Counties in the State of Arizona as follows:
FILED AND ABSTRACTED RECORDED AS REAL MORTGAGE AS CHATTEL MORTGAGE --------------------------- -------------------- CHATTEL DATE BOOK OR MORTGAGE COUNTY RECORDED DOCKET PAGE BOOK PAGE ------ -------- ------ ---- ---- ---- Apache........................... 7-28-50 16 1 9 154 Cochise.......................... 2-3-53 80 28 19 292 Coconino......................... 1-20-53 39 1 10 286 Gila............................. 1-17-53 32 84 17 -- Graham........................... 12-3-63 92 87 15 223 Maricopa......................... 8-6-46 408 163 92 204 Mohave........................... 11-13-57 28 68 12 13 Navajo........................... 10-14-49 31 483 16 521 Pima............................. 1-24-53 558 351 14 -- Pinal............................ 10-25-52 68 31 12 591 Yavapai.......................... 8-7-46 79 1 12 223 Yuma............................. 8-1-47 58 173 21 265 and in Counties in the State of New Mexico as follows: McKinley......................... 5-31-61 36 153 4 295 San Juan......................... 1-31-61 472 140 (No. 72441)
the copy recorded in Yuma County, Arizona also being effective for La Paz County, Arizona, formed on December 31, 1982; and copies of said Mortgage were filed with the office of the Bureau of Indian Affairs at Window Rock, Arizona, and with the Navajo Tribe of Indians at Window Rock, Arizona, and in the offices of the Secretary of State and the State Land Department of the State of Arizona (all the said counties and the said offices above referred to being herein referred to as "jurisdictions"); and 2 WHEREAS, by the Mortgage, the Company covenanted that it would execute and deliver such supplemental indenture or indentures and such further instruments and do such further acts as might be necessary or proper to carry out more effectually the purposes of the Mortgage and to make subject to the Lien of the Mortgage any property thereafter acquired, made or constructed and intended to be subject to the Lien thereof; and WHEREAS, the Company has executed and delivered to the Trustee fifty-five indentures supplemental to the Mortgage (hereinafter respectively called the First through the Fifty-fifth Supplemental Indentures) dated as of December 1, 1947, April 1, 1949, February 1, 1950, December 1, 1950, February 1, 1953, November 1, 1953, March 1, 1954, October 1, 1957, March 1, 1959, November 1, 1961, June 1, 1962, December 1, 1962, September 1, 1963, September 1, 1967, April 1, 1970, March 15, 1972, April 1, 1974, February 15, 1975, June 1, 1975, November 15, 1975, April 15, 1977, January 15, 1978, March 1, 1979, October 15, 1979, May 15, 1980, February 2, 1982, April 15, 1982, July 1, 1983, October 15, 1983, June 15, 1984, January 15, 1985, May 1, 1985, June 1, 1985, November 1, 1985, January 15, 1986, March 1, 1986, May 1, 1986, February 1, 1987, June 1, 1987, November 15, 1987, April 1, 1989, February 15, 1990, May 15, 1990, April 15, 1991, December 15, 1991, January 15, 1992, March 1, 1992, June 15, 1992, February 1, 1993, August 1, 1993, August 1, 1993, September 15, 1993, March 1, 1994, November 15, 1996, and April 1, 1997, each of which has been or will be recorded or filed in, or a recording or filing is or will be effective with respect to, each jurisdiction referred to above; and WHEREAS, in addition to the property described in the Mortgage, as heretofore supplemented and amended, the Company has acquired certain other property, rights and interests in property; and WHEREAS, the Company has heretofore issued, in accordance with the provisions of the Mortgage, as heretofore supplemented and amended, bonds of a series entitled and designated First Mortgage Bonds, 2-3/4% Series due 1976 (hereinafter called the bonds of the First Series), in the aggregate principal amount of Eight Million Five Hundred Thousand Dollars ($8,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3-1/8% Series due 1977 (hereinafter called the bonds of the Second Series), in the aggregate principal amount of Two Million Five Hundred Thousand Dollars ($2,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3% Series due 1979 (hereinafter called the bonds of the Third Series), in the aggregate principal amount of Four Million Dollars ($4,000,000); bonds of a series entitled and designated First Mortgage Bonds, 2-3/4% Series due 1980 (hereinafter called the bonds of the Fourth Series), in the aggregate principal amount of Five Million Dollars ($5,000,000); bonds of a series entitled and designated First Mortgage Bonds, 2-7/8% Series due 1980 (hereinafter called the bonds of the Fifth Series), in the aggregate principal amount of Six Million Dollars ($6,000,000); bonds of a series entitled and designated First Mortgage Bonds, 3-1/2% Series due 1983 (hereinafter called the bonds of the Sixth Series), in the aggregate principal amount of Fourteen Million Five Hundred Thousand Dollars ($14,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3 1/2% Series due November 1, 1983 (hereinafter called the bonds of the Seventh Series), in the aggregate principal amount of Five Million Seven Hundred Twenty-three Thousand Dollars ($5,723,000); bonds of a series entitled and designated First Mortgage Bonds, 3-1/4% Series due 1984 (hereinafter called the bonds of the Eighth Series), in the aggregate principal amount of Fifteen Million Dollars ($15,000,000); bonds of a series entitled and designated First Mortgage Bonds, 5-1/8% Series due 1987 (hereinafter called the bonds of the Ninth Series), in the aggregate principal amount of Fifteen Million Dollars ($15,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.70% Series due 1989 (hereinafter called the bonds of the Tenth Series), in the aggregate principal amount of Twenty Million Dollars ($20,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.80% Series due 1991 (hereinafter called the bonds of the Eleventh Series), in the aggregate principal amount of Thirty-five Million Dollars ($35,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.45% Series due 1992 (hereinafter called the bonds of the Twelfth Series), in the aggregate principal amount of 3 Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.40% Series due 1992 (hereinafter called the bonds of the Thirteenth Series), in the aggregate principal amount of Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.50% Series due 1993 (hereinafter called the bonds of the Fourteenth Series), in the aggregate principal amount of Fifteen Million Dollars ($15,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.25% Series due 1997 (hereinafter called the bonds of the Fifteenth Series), in the aggregate principal amount of Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and designated First Mortgage Bonds, 8.50% Series due 1975 (hereinafter called the bonds of the Sixteenth Series), in the aggregate principal amount of Thirty Million Dollars ($30,000,000); bonds of a series entitled and designated First Mortgage Bonds, 7.45% Series due 2002 (hereinafter called the bonds of the Seventeenth Series), in the aggregate principal amount of Sixty Million Dollars ($60,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.20% Series due 2004 (hereinafter called the bonds of the Eighteenth Series), in the aggregate principal amount of Fifty Million Dollars ($50,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9.50% Series due 1982 (hereinafter called the bonds of the Nineteenth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9.80% Series due 1980 (hereinafter called the bonds of the Twentieth Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10.625% Series due 2000 (hereinafter called the bonds of the Twenty-first Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.45% Series A due 2007 (hereinafter called the bonds of the Twenty-second Series), in the aggregate principal amount of Thirteen Million Dollars ($13,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.45% Series B due 2007 (hereinafter called the bonds of the Twenty-third Series), in the aggregate principal amount of Thirty Million Dollars ($30,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6% Series A due 2008 (hereinafter called the bonds of the Twenty-fourth Series), in the aggregate principal amount of Thirty-four Million Dollars ($34,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9.95% Series due 2004 (hereinafter called the bonds of the Twenty-fifth Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12-1/8% Series due 2009 (hereinafter called the bonds of the Twenty-sixth Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12-7/8% Series due 2000 (hereinafter called the bonds of the Twenty-seventh Series), in the aggregate principal amount of One Hundred Eighty-five Million Dollars ($185,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-3/8% Series due 1985 (hereinafter called the bonds of the Twenty-eighth Series), in the aggregate principal amount of Sixty Million Two Hundred Fifty Thousand Dollars ($60,250,000); bonds of a series entitled and designated First Mortgage Bonds, 16% Series due 1992 (hereinafter called the bonds of the Twenty-ninth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12-3/4% Series due 2013 (hereinafter called the bonds of the Thirtieth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 13-1/2% Series due 2013 (hereinafter called the bonds of the Thirty-first Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 15% Series due 1994 (hereinafter called the bonds of the Thirty-second Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12% Series due 1995 (hereinafter called the bonds of the Thirty-third Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 13-1/4% Series due 2007 (hereinafter called the bonds of the Thirty-fourth Series), in the aggregate principal amount of Fifty Million Dollars ($50,000,000); bonds of a series entitled and designated First Mortgage Bonds, 11-1/2% Series due 2015 (hereinafter called the bonds of the Thirty-fifth Series), in the aggregate principal amount of One Hundred Fifty Million Dollars 4 ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 11-1/2% Series due November 1, 2015 (hereinafter called the bonds of the Thirty-sixth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 11% Series due 2016 (hereinafter called the bonds of the Thirty-seventh Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9-1/4% Series due 1996 (hereinafter called the bonds of the Thirty-eighth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9% Series due 1996 (hereinafter called the bonds of the Thirty-ninth Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9% Series due 2017 (hereinafter called the bonds of the Fortieth Series), in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9-7/8% Series due 1997 (hereinafter called the bonds of the Forty-first Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-3/4% Series due 2017 (hereinafter called the bonds of the Forty-second Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-3/4% Series due 2019 (hereinafter called the bonds of the Forty-third Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-1/4% Series due 2000 (hereinafter called the bonds of the Forty-fourth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10 1/4% Series due 2020 (hereinafter called the bonds of the Forty-fifth Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9-1/2% Series due 2021 (hereinafter called the bonds of the Forty-sixth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9% Series due 2021 (hereinafter called the bonds of the Forty-seventh Series), in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 7-1/8% Series due 1997, in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000), and bonds of a series entitled and designated First Mortgage Bonds, 8-3/4% Series due 2024, in the aggregate principal amount of One Hundred Seventy-five Million Dollars ($175,000,000) (hereinafter collectively called the bonds of the Forty-eighth Series); bonds of a series entitled and designated First Mortgage Bonds, 7-5/8% Series due 1998, in the aggregate principal amount of One Hundred Million Dollars ($100,000,000), and bonds of a series entitled and designated First Mortgage Bonds, 8-1/8% Series due 2002, in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000) (hereinafter collectively called the bonds of the Forty-ninth Series); bonds of a series entitled and designated First Mortgage Bonds, 7-5/8% Series due 1999 (hereinafter called the bonds of the Fiftieth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 8% Series due 2025 (hereinafter called the bonds of the Fifty-first Series), in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 7-1/4% Series due 2023 (hereinafter called the bonds of the Fifty-second Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 5-7/8% Series due 2028 (hereinafter called bonds of the Fifty-third Series), in the aggregate principal amount of Twelve Million Eight Hundred Fifty Thousand Dollars ($12,850,000); bonds of a series entitled and designated First Mortgage Bonds, 5-7/8% Series due 2028 (hereinafter called bonds of the Fifty-fourth Series), in the aggregate principal amount of One Hundred Forty-one Million One Hundred Fifty Thousand Dollars ($141,150,000); bonds of a series entitled and designated First Mortgage Bonds, 5-1/2% Series due 2028 (hereinafter called bonds of the Fifty-fifth Series), in the aggregate principal amount of Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and designated First Mortgage Bonds, 5-3/4% Series due 2000 (hereinafter called 5 bonds of the Fifty-sixth Series) in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6-5/8% Series due 2004 (hereinafter called bonds of the Fifty-seventh Series) in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, Senior Note Series A (hereinafter called bonds of the Fifty-eighth Series) in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); and bonds of a series entitled and designated First Mortgage Bonds, Senior Note Series B (hereinafter called bonds of the Fifth-ninth Series) in the aggregate principal amount of Fifty Million Dollars ($50,000,000); and WHEREAS, said The Bank of New York, by an instrument in writing, effective on the opening of business on September 29, 1995, succeeded to Bank of America National Trust and Savings Association as Trustee under the Mortgage; and, pursuant to Section 104 of the Mortgage, The Bank of New York is the successor Trustee under the Mortgage; and WHEREAS, Section 8 of the Mortgage provides that the form of each series of bonds (other than bonds of the First Series) issued thereunder shall be established by Resolution of the Board of Directors of the Company and that the form of each series, as established by said Board of Directors, shall specify the descriptive title of the bonds and various other terms thereof, and may also contain such provisions not inconsistent with the provisions of the Mortgage as the Board of Directors may, in its discretion, cause to be inserted therein expressing or referring to the terms and conditions upon which such bonds are to be issued and/or secured under the Mortgage; and WHEREAS, Section 120 of the Mortgage provides, among other things, that any power, privilege or right expressly or impliedly reserved to or in any way conferred upon the Company by any provision of the Mortgage, whether such power, privilege or right is in any way restricted or is unrestricted, may be in whole or in part waived or surrendered or subjected to any restriction if at the time unrestricted or to additional restriction if already restricted, and the Company may enter into any further covenants, limitations or restrictions for the benefit of any one or more series of bonds issued thereunder, or the Company may cure any ambiguity contained therein, or in any supplemental indenture, or may establish the terms and provisions of any series of bonds other than said First Series, by an instrument in writing executed and acknowledged by the Company in such manner as would be necessary to entitle a conveyance of real estate to record in all of the states in which any property at the time subject to the Lien of the Mortgage shall be situated; and WHEREAS, the Company now desires to create a new series of bonds to be issued under and pursuant to the Mortgage in accordance with the provisions of Article VI thereof, and to add to its covenants and agreements contained in the Mortgage, as heretofore supplemented and amended, certain other covenants and agreements to be observed by it and to alter and amend in certain respects the covenants and provisions contained in the Mortgage, as heretofore supplemented and amended; and WHEREAS, the Company has entered into a Loan Agreement, dated as of November 1, 2002 (as amended from time to time, the "Loan Agreement") between the Company and Maricopa County, Arizona Pollution Control Corporation (the "Issuer"), and the Issuer has issued the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A in the aggregate principal amount of $90,000,000 (the "Series A Pollution Control Bonds") under that certain Indenture of Trust, dated as of November 1, 2002 (as amended from time to time, the "Maricopa Indenture") between the Issuer and The Bank of New York, as Trustee (together with its successors in such capacity, the "Maricopa Trustee"); WHEREAS, the Company has agreed to issue Ninety Million ($90,000,000) in aggregate principal amount of its 5.05% Senior Notes (Maricopa 2002 Series A) due 2029 (the "Series A Senior Notes") in support of the Series A Pollution 6 Control Bonds, pursuant to the provisions of the Indenture dated as of November 15, 1996 (the "Senior Note Indenture"), between the Company and The Bank of New York, as trustee (said trustee or any successor trustee under the Senior Note Indenture being hereinafter referred to as the "Senior Note Trustee"), as supplemented by the First Supplemental Indenture, dated as of November 15, 1996, the Second Supplemental Indenture dated as of April 1, 1997, and the Third Supplemental Indenture dated as of November 1, 2002, between the Company and the Senior Note Trustee; and WHEREAS, in order to secure the Company's obligation to pay principal and interest on the Series A Senior Notes prior to the Release Date (as hereinafter defined), the Company desires to provide for the issuance under the Mortgage to the Senior Note Trustee of a new series of bonds designated "First Mortgage Bonds, Senior Note Series C," having the same rate of interest, interest payment dates, maturity date and redemption provisions and in the same aggregate principal amount as the Series A Senior Notes; and WHEREAS, the execution and delivery by the Company of this Fifty-sixth Supplemental Indenture, and the terms of the bonds of the Sixtieth Series hereinafter referred to, have been duly authorized by the Board of Directors of the Company by appropriate Resolutions of said Board of Directors; NOW THEREFORE, THIS INDENTURE WITNESSETH: That Arizona Public Service Company, in consideration of the premises and of One Dollar to it duly paid by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, and in further evidence of assurance of the estate, title and rights of the Trustee and in order further to secure the payment of both the principal of and interest and premium, if any, on the bonds from time to time heretofore, herewith or hereafter issued under the Mortgage, according to their tenor and effect, and the performance of all the provisions of the Mortgage (including any instruments supplemental thereto and any modifications made as in the Mortgage provided) and of said bonds, hereby grants, bargains, sells, releases, conveys, assigns, transfers, mortgages, pledges, sets over and confirms (subject, however, to Excepted Encumbrances as defined in Section 6 of the Mortgage and to the liens permitted by Section 36 of the Mortgage) unto The Bank of New York, as Trustee under the Mortgage, and to its successor or successors in said trust, and to said Trustee and its successors and assigns forever, all the properties of the Company described in the Mortgage, as heretofore supplemented and amended (except any properties which have been released from the Lien of the Mortgage), and all the properties specifically described in Article V hereof. Also all other property, real, personal and mixed, of the kind or nature specifically mentioned in Article V hereof or of any other kind or nature (except any herein or in the Mortgage, as heretofore supplemented and amended, expressly excepted and except any which may not lawfully be mortgaged or pledged hereunder), now owned or, subject to the provisions of subsection (I) of Section 87 of the Mortgage, hereafter acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) and wheresoever situated, including (without in anywise limiting or impairing by the enumeration of the same the scope and intent of the foregoing or of any general description contained in this Fifty-sixth Supplemental Indenture) all lands, power sites, flowage rights, water rights, water locations, water appropriations, ditches, flumes, reservoirs, reservoir sites, canals, raceways, dams, dam sites, aqueducts, and all other rights or means for appropriating, conveying, storing and supplying water; all rights of way and roads; all plants for the generation of electricity by steam, water and/or other power; all power houses, gas plants, street lighting systems, standards and other equipment incidental thereto, telephone, radio and television systems, air-conditioning systems and equipment incidental thereto, water works, water systems, steam heat and hot water plants, substations, lines, service and supply systems, bridges, culverts, tracks, ice or refrigeration plants and equipment, offices, buildings and other structures and equipment thereof; all machinery, engines, boilers, dynamos, electric, gas and other machines, regulators, meters, transformers, 7 generators, motors, electrical, gas and mechanical appliances, conduits, cables, water, steam heat, gas or other pipes, gas mains and pipes, service pipes, fittings, valves and connections, pole and transmission lines, wires, cables, tools, implements, apparatus, furniture and chattels; all franchises, consents or permits; all lines for the transmission and distribution of electric current, gas, steam heat or water for any purpose including towers, poles, wires, cables, pipes, conduits, ducts and all apparatus for use in connection therewith; all real estate, lands, easements, servitudes, licenses, permits, franchises, privileges, rights of way and other rights in or relating to public or private property, real or personal, or the occupancy of such property and (except as herein or in the Mortgage, as heretofore supplemented and amended, expressly excepted) all the right, title and interest the Company may now have or hereafter acquire in and to any and all property of any kind or nature appertaining to and/or used and/or occupied and/or enjoyed in connection with any property hereinbefore or in the Mortgage, as heretofore supplemented and amended, described. TOGETHER WITH all and singular the tenements, hereditaments, prescriptions, servitudes and appurtenances belonging or in anywise appertaining to the aforementioned property or any part thereof, with the reversion and reversions, remainder and remainders and (subject to the provisions of Section 57 of the Mortgage) the tolls, rents, revenues, issues, earnings, income, product and profits thereof, and all the estate, right, title, interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforementioned property and franchises and every part and parcel thereof. IT IS HEREBY AGREED by the Company that, subject to the provisions of subsection (I) of Section 87 of the Mortgage and to the extent permitted by law, all the property, rights and franchises acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) after the date hereof, except any herein or in the Mortgage, as heretofore supplemented and amended, expressly excepted, shall be and are as fully granted and conveyed hereby and as fully embraced within the lien hereof and the Lien of the Mortgage as if such property, rights and franchises were now owned by the Company and were specifically described herein and conveyed hereby. PROVIDED that the following are not and are not intended to be now or hereafter granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed hereunder and are hereby expressly excepted from the lien and operation of this Fifty-sixth Supplemental Indenture and from the Lien and operation of the Mortgage, viz.: (1) cash, shares of stock, bonds, notes and other obligations and other securities not hereafter specifically pledged, paid, deposited, delivered or held under the Mortgage or covenanted so to be; (2) merchandise, equipment, apparatus, materials or supplies held for the purpose of sale or other disposition in the usual course of business; fuel, oil and similar materials and supplies consumable in the operation of any of the properties of the Company; construction equipment acquired for temporary use; all aircraft, tractors, rolling stock, trolley coaches, buses, motor coaches, automobiles, motor trucks and other vehicles and materials and supplies held for the purpose of repairing or replacing (in whole or part) any of the same; all timber, minerals, mineral rights and royalties and all Natural Gas and Oil Production Property, as defined in Section 4 of the Mortgage; (3) bills, notes and accounts receivable, judgments, demands and chooses in action, and all contracts, leases and operating agreements not specifically pledged under the Mortgage or covenanted so to be; (4) the last day of the term of any lease or leasehold which may be or become subject to the Lien of the Mortgage; (5) electric energy, gas, steam, ice and other materials or products generated, manufactured, produced, purchased or acquired by the Company for sale, distribution or use in the ordinary course of its business; and (6) the Company's franchise to be a corporation; PROVIDED, HOWEVER, that the property and rights expressly excepted from the Lien and operation of the Mortgage in the above subdivisions (2) and (3) shall (to the extent permitted by law) cease to be so excepted in the event and as of the date that the Trustee or a receiver or trustee shall enter upon and take possession of the Mortgaged and 8 Pledged Property in the manner provided in Article XIII of the Mortgage by reason of the occurrence of a Default as defined in Section 65 thereof. TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed by the Company as aforesaid, or intended so to be, unto The Bank of New York, the Trustee, and its successors and assigns forever. IN TRUST NEVERTHELESS, for the same purposes and upon the same terms, trusts and conditions and subject to and with the same provisos and covenants as are set forth in the Mortgage, as supplemented and amended. AND IT IS HEREBY COVENANTED by the Company that all the terms, conditions, provisos, covenants and provisions contained in the Mortgage, as supplemented and amended, shall affect and apply to the property hereinbefore described and conveyed and to the estate, rights, obligations and duties of the Company and the Trustee and the beneficiaries of the trust with respect to said property, and to the Trustee and its successors as Trustee of said property in the same manner and with the same effect as if the said property had been owned by the Company at the time of the execution of the Mortgage and had been specifically and at length described in and conveyed to said Trustee by the Mortgage as a part of the property therein stated to be conveyed. The Company further covenants and agrees to and with the Trustee and its successors in said trust under the Mortgage, as follows: ARTICLE I. SIXTIETH SERIES OF BONDS. SECTION 1. There shall be a series of bonds designated "First Mortgage Bonds, Senior Note Series C" (hereinafter sometimes referred to as the "Sixtieth Series" or the "Senior Note Series C Bonds"), limited to the aggregate principal amount of $90,000,000, each of which shall also bear the descriptive title First Mortgage Bond, and the form thereof, which shall be established by Resolution of the Board of Directors of the Company, shall contain suitable provisions with respect to the matters hereinafter specified in this Supplemental Indenture. Bonds of the Sixtieth Series shall be dated as provided in Section 10 of the Mortgage; shall mature, subject to the provisions for prior redemption hereinafter set forth, on May 1, 2029; shall be issued as a single fully registered bond, and shall be registered in the name of the Senior Note Trustee; and shall bear interest from November 1, 2002 or from the most recent Interest Payment Date (as defined below) to which interest has been paid at the rate of 5.05% per annum (calculated on the basis of a 360-day year of twelve 30-day months), payable on May 1 and November 1 of each year (each an "Interest Payment Date"), commencing May 1, 2003, to the holders thereof of record on the April 15 or October 15, as the case may be, next preceding such Interest Payment Date (subject to the provisions of Section 12 of the Mortgage concerning legal holidays and bank closings), and the principal of and interest on, or other amounts, if any, payable upon redemption of, each said bond to be payable at the office or agency of the Company in the Borough of Manhattan, The City of New York, New York, in such coin or currency of the United States of America as, at the time of payment, is legal tender for public and private debts. Notwithstanding the above, to the extent required in Section 4.2 of the Loan Agreement at any time, all payments of interest on an Interest Payment Date and of principal on the maturity date of the Senior Note Series C Bonds will be due and payable not less than two (2) Business Days (as defined in the Maricopa Indenture) prior to each such Interest Payment Date and such maturity date. 9 The Company shall have no obligation to make payments with respect to the principal and/or interest on the Senior Note Series C Bonds unless and until, and only to the extent that, payments shall be due and payable pursuant to the Series A Senior Notes, and the Company's obligation to make payments with respect to the principal and/or interest on the Senior Note Series C Bonds shall be fully or partially, as the case may be, satisfied and discharged to the extent that, at the time that any such payment shall be due, the corresponding amount of principal of and/or interest then due on the Series A Senior Notes shall have been fully or partially paid, as the case may be, or there shall have been deposited with the Senior Note Trustee pursuant to Section 501, Section 1103, or Section 1205 of the Senior Note Indenture trust funds sufficient under the provisions of said Sections to fully or partially pay, as the case may be, the corresponding amount of principal and/or interest then due on the Series A Senior Notes. SECTION 2. Upon payment of the principal of and interest due on the Series A Senior Notes, whether at maturity or prior to maturity by redemption or otherwise, or upon provision for the payment thereof having been made in accordance with Section 501 or Section 1402 of the Senior Note Indenture, Senior Note Series C Bonds in a principal amount equal to the principal amount of Series A Senior Notes so paid or for which such provision for payment has been made shall be deemed fully paid, satisfied and discharged and the obligations of the Company thereunder shall be terminated and such Senior Note Series C Bonds shall be surrendered to and cancelled by the Trustee. From and after such date as all bonds issued under the Mortgage (other than Senior Note First Mortgage Bonds, as such term is defined in the Senior Note Indenture) have been retired through payment, redemption, or otherwise at, before or after maturity thereof (the "Release Date"), the Senior Note Series C Bonds shall be deemed fully paid, satisfied and discharged and the obligation of the Company thereunder shall be terminated. On the Release Date, subject to the conditions of Section 407 of the Senior Note Indenture, the Senior Note Series C Bonds shall be surrendered to and cancelled by the Trustee. SECTION 3. Bonds of the Sixtieth Series shall be held by the Senior Note Trustee and shall not be transferable except to its permitted successors and assigns. The Senior Note Trustee, as the holder of the Senior Note Series C Bonds, shall attend meetings of bondholders under the Mortgage or deliver its proxy in connection therewith. Either at such meeting, or otherwise when the consent of the holders of the Senior Note Series C Bonds is sought without a meeting, the Senior Note Trustee shall vote as the holder of the Senior Note Series C Bonds, or shall consent with respect thereto; provided, however, that the Senior Note Trustee shall not vote in favor of, or consent to, any modification of the Mortgage which is correlative to a modification of the Maricopa Indenture or the Loan Agreement which would require the approval of owners of Series A Pollution Control Bonds without the approval of the owners of Series A Pollution Control Bonds which would be required for such correlative modification of such Maricopa Indenture or Loan Agreement. ARTICLE II. REDEMPTION OF SENIOR NOTE SERIES C BONDS AND OTHER PROVISIONS The Senior Note Series C Bonds shall be redeemed, in whole or in part, from time to time, on the date on which a corresponding principal amount of Series A Senior Notes is redeemed as provided in the Senior Note Indenture upon the Senior Note Trustee's notification of the Trustee of such redemption, at a redemption price equal to the redemption price of such Series A Senior Notes being so redeemed. Any such notice shall be received by the Trustee no later than 5 days prior to any redemption date fixed for the Senior Note Series C Bonds to be redeemed and shall specify the principal amount of such Senior Note Series C Bonds to be redeemed, the redemption date, and the amount of accrued interest to be paid thereon. The Company shall deposit in trust with the Trustee on the redemption date an amount of money sufficient to pay the principal amount plus accrued interest, if any, on the Senior Note Series C Bonds to be redeemed. Upon presentation to the Trustee of any Senior Note Series C Bonds by the Senior Note Trustee for payment under this Article II, such Senior Note Series C Bonds so presented shall be redeemed and paid in full to the extent so redeemed. 10 In the event the principal of all Series A Senior Notes is declared due and payable or becomes automatically due and payable pursuant to Section 602 of the Senior Note Indenture, upon the filing with the Trustee of a written demand for the acceleration of the payment of principal of all Senior Note Series C Bonds, the payment of principal on all Senior Note Series C Bonds shall become immediately due and payable and the Trustee shall provide to the Senior Note Trustee an irrevocable, valid and unconditional notice of acceleration of all Senior Note Series C Bonds. Redemption of the Senior Note Series C Bonds shall be effected, without further notice by the Company to the Trustee, by the payment by the Company of the applicable redemption price specified in this Article II at the place specified for payment of principal of and interest on such bonds. The Senior Note Series C Bonds will not be subject to prepayment or redemption prior to maturity except as provided herein, notwithstanding the provisions of Section 39 or Section 64 of the Mortgage, or with "Proceeds of Released Property," as defined in the Mortgage. The Senior Note Series C Bonds will not be subject to any sinking fund. The Company covenants and agrees that, prior to Release Date, it will not take any action (except as required by this Article II hereof) that would cause the outstanding principal amount of the Senior Note Series C Bonds to be less than the then outstanding principal amount of the Series A Senior Notes. ARTICLE III. REPLACEMENT FUND PROVISIONS -- OTHER RELATED PROVISIONS OF THE MORTGAGE -- DIVIDEND COVENANT -- RECORD DATES -- AUTHENTICATING AGENT. SECTION 4. The Company covenants that the provisions of Section 39 of the Mortgage, which were to remain in effect so long as any bonds of the First Series remained Outstanding, shall remain in full force and effect so long as any bonds of the Sixtieth Series are Outstanding. Clause (d) of subsection (II) of Section 4 of the Mortgage, as heretofore amended, clause (6) and clause (e) of Section 5 of the Mortgage, as heretofore amended, and Section 29 of the Mortgage, as heretofore amended, are hereby further amended by inserting therein the words "and Sixtieth Series" after the words "bonds of the First Series and Second Series and Third Series and Fourth Series and Fifth Series and Sixth Series and Seventh Series and Eighth Series and Ninth Series and Tenth Series and Eleventh Series and Twelfth Series and Thirteenth Series and Fourteenth Series and Fifteenth Series and Sixteenth Series and Seventeenth Series and Eighteenth Series and Nineteenth Series and Twentieth Series and Twenty-first Series and Twenty-second Series and Twenty-third Series and Twenty-fourth Series and Twenty-fifth Series and Twenty-sixth Series and Twenty-seventh Series and Twenty-eighth Series and Twenty-ninth Series and Thirtieth Series and Thirty-first Series and Thirty-second Series and Thirty-third Series and Thirty-fourth Series and Thirty-fifth Series and Thirty-sixth Series and Thirty-seventh Series and Thirty-eighth Series and Thirty-ninth Series and Fortieth Series and Forty-first Series and Forty-second Series and Forty-third Series and Forty-fourth Series and Forty-fifth Series and Forty-sixth Series and Forty-seventh Series and Forty-eighth Series and Forty-ninth Series and Fiftieth Series and Fifty-first Series and Fifty-second Series and Fifty-third Series and Fifty-fourth Series and Fifty-fifth Series and Fifty-sixth Series, and Fifty-seventh Series and Fifty-eighth Series and Fifty-ninth" each time such words occur therein. 11 Clause (e) of subsection (II) of Section 4 of the Mortgage, as heretofore amended, is hereby further amended by the insertion therein after the words "and Fifty-ninth" the words "and Sixtieth." The last paragraph of Section 12 of the Mortgage, as heretofore amended, the last paragraph of Section 17 of the Mortgage, as heretofore amended, and the last paragraph of Section 110 of the Mortgage, as heretofore amended, are hereby amended by inserting therein the words "or the Sixtieth Series" after the words "Fifty-ninth Series" each time such words occur therein. ARTICLE IV. MISCELLANEOUS PROVISIONS. SECTION 5. The terms defined in the Mortgage, as supplemented and amended, shall, for all purposes of this Fifty-sixth Supplemental Indenture, have the meanings specified therein, except that the term "Mortgage" shall mean only the original Mortgage and Deed of Trust, dated as of July 1, 1946; the term "Mortgage, as heretofore supplemented and amended" shall mean the Mortgage, as supplemented and amended by the First through Fifty-fifth Supplemental Indentures hereinabove referred to; and the term "Mortgage, as supplemented and amended," shall mean the Mortgage, as supplemented and amended by the First through Fifty-fifth Supplemental Indentures hereinabove referred to and as supplemented and amended by this Fifty-sixth Supplemental Indenture and any future supplemental indentures. SECTION 6. The Trustee hereby accepts the trusts herein declared, provided, created, supplemented or amended and agrees to perform the same upon the terms and conditions herein and in the Mortgage, as heretofore supplemented and amended, set forth and upon the following terms and conditions: The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Fifty-sixth Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general, each and every term and condition contained in Article XVII of the Mortgage shall apply to and form part of this Fifty-sixth Supplemental Indenture with the same force and effect as if the same were herein set forth in full with such omissions, variations and insertions, if any, as may be appropriate to make the same conform to the provisions of this Fifty-sixth Supplemental Indenture. SECTION 7. Whenever in this Fifty-sixth Supplemental Indenture either of the parties hereto is named or referred to, this shall, subject to the provisions of Articles XVI and XVII of the Mortgage, be deemed to include the successors and assigns of such party, and all the covenants and agreements in this Fifty-sixth Supplemental Indenture contained by or on behalf of the Company or by or on behalf of the Trustee shall, subject as aforesaid, bind and inure to the respective benefits of the respective successors and assigns of such parties, whether so expressed or not. SECTION 8. Nothing in this Fifty-sixth Supplemental Indenture, expressed or implied, is intended or shall be construed to confer upon, or to give to, any person, firm or corporation, other than the parties hereto and the holders of the bonds Outstanding under the Mortgage, any right, remedy or claim under or by reason of this Fifty-sixth Supplemental Indenture or any covenant, condition, stipulation, promise or agreement hereof, and all the covenants, conditions, stipulations, promises and agreements in this Fifty-sixth Supplemental Indenture contained by or on behalf of the Company shall be for the sole and exclusive benefit of the parties hereto and of the holders of the bonds Outstanding under the Mortgage. 12 SECTION 9. This Fifty-sixth Supplemental Indenture may be executed simultaneously in several counterparts, each of which shall be an original and all of which shall constitute but one and the same instrument. ARTICLE V. SPECIFIC DESCRIPTION OF PROPERTY. SECTION 10. CERTAIN REAL PROPERTY LOCATED IN: APACHE COUNTY EAST HOLBROOK SUBSTATION PARCEL NO. 1: That certain parcel of land situated in the Southwest quarter of Section 20, Township 19 North, Range 24 East of the Gila and Salt River Base and Meridian, Apache County, Arizona, being more particularly described as follows: COMMENCING at the axle that marks the Southwest corner of Section 20, from whence the axle that marks the West quarter corner of Section 20 bears North 00 degrees 18 minutes 08 seconds West, a distance of 2639.33 feet; thence North 00 degrees 08 minutes 18 seconds West along the West line of said Section 20, a distance of 2087.82 feet; thence departing the West Section line on a bearing of South 89 degrees 34 minutes 38 seconds East, a distance of 328.67 feet to the TRUE POINT OF BEGINNING; thence continuing on a bearing of South 89 degrees 34 minutes 38 seconds East, a distance of 250.00 feet; thence South 00 degrees 25 minutes 22 seconds West, a distance of 250.00 feet; thence North 89 degrees 34 minutes 38 seconds West, a distance of 250.00 feet; thence North 00 degrees 25 minutes 22 seconds East, a distance of 250.00 feet to the TRUE POINT OF BEGINNING. COCONINO COUNTY RED LAKE SUBSTATION The following described land situate in Coconino County, Arizona, being a portion of the Southwest Quarter of Section 15, Township 23 North, Range 2 East of the Gila and Salt River Base and Meridian, more particularly described as follows: COMMENCING at the "P-K" nail in a concrete fence corner footing, locally accepted as the Southwest corner of said Section 15, from whence the 1" pipe in a stone circle that marks the South Quarter corner of said Section bears South 87(degree)59'34" East, 2574.88 feet distant; 13 THENCE North 36(degree)17'16" East, a distance of 602.19 feet to the TRUE POINT OF BEGINNING; THENCE North 01(degree)09'03" East, a distance of 291.53 feet; THENCE South 88(degree)50'58" East, a distance of 300.00 feet; THENCE South 01(degree)09'03" West, a distance of 300.00 feet; THENCE North 88(degree)50'58" West, a distance of 249.94 feet; THENCE North 79(degree)14'50" West, a distance of 50.77 feet to the TRUE POINT OF BEGINNING. TOGETHER WITH a release, transfer and quit-claim of all right, title, privilege and claim of Grantor in and to all minerals (surface and subsurface) which may be owned by him and which are appurtenant to the aforedescribed lands. TOGETHER with all improvements thereon located. MARICOPA COUNTY ALEXANDER SUBSTATION A portion of the South half of Section 25, Township 3 North, Range 2 East, Gila and Salt River Meridian, Maricopa County, Arizona, lying south of the Arizona Canal more particularly described as follows: Commencing at the South Quarter corner of said Section 25, said point being a brass cap in handhole, thence coincident with the mid-section line, North 00(degree) 29' 36" East 1666.94 feet to the True Point of Beginning of the parcel herein described. Thence leaving said mid-section line South 55(degree) 53'23" West 8.36' to an iron bar with SRP cap stamped LS15925, Thence North 38(degree) 36' 25" West 231.40 feet to the North line of a parcel of land described in Docket 265, Page 90 Maricopa County records and an iron bar with SRP cap stamped LS 15925, Thence coincident with the North line of said Docket 265, Page 90, North 510 15'14" East 125.27 feet to an iron bar with SRP cap stamped LS 15925 and the beginning of an non tangent curve, concave to the South having a radius of 380.00 feet and to which beginning a radial line bears North 27(degree) 42' 18" West; Thence easterly 81.70 feet along said curve through a central angle of 12(degree) 19' 08" to an iron bar with SRP cap stamped LS 15925 Thence South.10(degree)44' 49" East 37.36 feet to an iron bar with SRP cap stamped LS15925, Thence North 81(degree)46' 03" East 70.88 feet to an iron bar with SRP cap stamped LS 15925, Thence North 13(degree) 21' 24" West 39.83 feet to an iron bar with SRP cap stamped LS 15925 and the beginning of a non tangent curve, concave to the south having a radius of 380 feet and to which beginning a radial line bears North 04(degree) 58' 04" West; 14 Thence easterly 149.84 feet along said curve through a central angle of 22(degree) 35' 34" to an iron bar with SRP cap stamped LS15925, Thence South 72(degree)22' 30" East 274.22 feet to an iron bar with SRP cap stamped LS 15925, Thence South 53(degree)04'37" East 8.00 feet to an iron bar with SRP cap stamped LS15925, Thence South 72(degree)35' 22" East 119.70 feet to an iron bar with SRP cap stamped LS 15925, Thence South 61(degree)24' 41" West 52.21 feet to an iron bar with SRP cap stamped LS15925, Thence North 78(degree)18' 39" West 75.52 feet to an iron bar with SRP cap stamped LS15925, Thence South 61(degree)24' 41" West 542.37 feet to an iron bar with SRP cap stamped LS15925, Thence North 00(degree)29' 36" East 129.40 feet to an iron bar with SRP cap stamped LS15925, Thence South 56(degree) 15' 21" West 30.24 feet to the true point of beginning. ARROWHEAD SUBSTATION PARCEL NO. 1: That part of the Southeast quarter of Section 23, Township 4 North, Range 1 East of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly described as follows: COMMENCING at the South quarter corner of said Section 23; THENCE South 89 degrees 53 minutes 33 seconds East, along the South line of the Southeast quarter of said Section 23, a distance of 740.00 feet; THENCE North 00 degrees 05 minutes 41 seconds East, departing said South line, a distance of 70.00 feet to the Southwest corner of a 20.00 foot wide Electric Utility Easement, recorded in Document No. 94-0809353, Maricopa County Records; THENCE North 89 degrees 53 minutes 33 seconds West, a distance of 120.00 feet the True Point of Beginning; THENCE continuing North 89 degrees 53 minutes 33 seconds West, a distance of 250.00 feet; THENCE North 00 degrees 05 minutes 41 seconds East, a distance of 250.00 feet; THENCE South 89 degrees 53 minutes 33 seconds East, a distance of 250.00 feet; THENCE South 00 degrees 05 minutes 41 seconds West, a distance of 250.00 feet to the True Point of Beginning. PARCEL NO. 2: A 20.00 foot Electric Utility Easement (Extension) over the following described property: 15 That part of the Southeast quarter of Section 23, Township 4 North, Range 1 East of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly described as follows: COMMENCING at the South quarter corner of said Section 23; THENCE south 89 degrees 53 minutes 33 seconds East, along the South line of the Southeast quarter of said Section 23, a distance of 740.00 feet; THENCE North 00 degrees 05 minutes 41 seconds East, departing said South line, a distance of 70.00 feet to the Southwest corner of a 20.00 foot wide Electric Utility Easement, recorded in Document No. 94-0809353, Maricopa County Records, said point being the True Point of Beginning; THENCE North 89 degrees 53 minutes 33 seconds West, a distance of 120.00 feet to the Southeast corner of the proposed boundary of an Arizona Public Service Sub-station site; THENCE North 00 degrees 05 minutes 41 seconds East, along the East boundary of said Sub-station site, a distance of 20.00 feet; THENCE South 89 degrees 53 minutes 33 seconds East, departing said proposed boundary, a distance of 120.00 feet to the Northwest corner of said Electric Utility Easement; THENCE South 00 degrees 05 minutes 41 seconds West, along the West boundary of said Electric Utility Easement, a distance of 20.00 feet to the True Point of Beginning. PARCEL NO. 3: A 20.00 foot Ingress and Egress Easement over the following described property; That part of the Southeast quarter of Section 23, Township 4 North, Range 1 East of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly described as follows: A 20.00 foot easement being 10.00 feet each side of the following described centerline; COMMENCING at the Southeast corner of said Section 23; THENCE North 00 degrees 18 minutes 23 seconds East, along the East line of the Southeast quarter of said Section 23, a distance of 1,571.94 feet; THENCE North 89 degrees 41 minutes 37 seconds West, a distance of 55.00 feet to a point on the Westerly right of way of "75th Avenue," said point being the True Point of Beginning; THENCE continuing North 89 degrees 41 minutes 37 seconds West, departing said Westerly right-of-way, a distance of 168.09 feet to the beginning of a tangent curve of 50.00 foot radius, concave Southeasterly; THENCE Southwesterly, along said curve, through a central angle of 103 degrees 43 minutes 28 seconds, a distance of 90.52 feet to the beginning of a tangent compound curve of 1,682.00 foot radius, concave Northeasterly; THENCE Southeasterly, along said curve, through a central angle of 05 degrees 51 minutes 26 seconds, a distance of 171.94 feet to the beginning of a tangent reverse curve of 604.00 foot radius, concave Northwesterly; 16 THENCE Southwesterly, along said curve, through a central angle of 125 degrees 23 minutes 38 seconds, a distance of 1,321.88 feet to the beginning of a tangent reverse curve of 1,650.00 foot radius, concave Southwesterly; THENCE Northwesterly, along said curve, through a central angle of 31 degrees 26 minutes 46 seconds, a distance of 905.58 feet to the beginning of a tangent reverse curve of 285.00 foot radius, concave Northeasterly; THENCE Northwesterly, along said curve, through a central angle of 44 degrees 14 minutes 21 seconds, a distance of 220.05 feet to the beginning of a tangent reverse curve of 95.00 foot radius, concave Southeasterly; THENCE Southwesterly, along said curve, through a central angle of 76 degrees 39 minutes 20 seconds, a distance of 127.10 feet; THENCE South 43 degrees 15 minutes 22 seconds West, a distance of 74.02 feet to the beginning of a tangent curve of 62.50 foot radius, concave Southeasterly; THENCE Southwesterly, along said curve, through a central angle of 42 degrees 15 minutes 22 seconds, a distance of 46.09 feet; THENCE South 00 degrees 00 minutes 00 seconds East, a distance of 158.20 feet to a point on the proposed North boundary of an Arizona Public Service Sub-station site, said point being the terminus of said easement. BISCUIT FLATS SUBSTATION That portion of the South half of Section 26, Township 5 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, described as follows: Commencing at a point on the North-South mid-section line of said Section 26 that lies North 00 degrees 01 minutes 41 seconds East record (North 00 degrees 01 minutes 31 seconds East measured), a distance of 1671.16 record (1671.14 measured) feet from the South quarter corner of said Section 26; thence departing said mid-section line South 89 degrees 39 minutes 32 seconds West and parallel to the South line of the Southwest quarter of said Section 26, a distance of 869.84 record (868.38 measured) feet to the Southerly line of Tract No. GR-10-6 in the Central Arizona Project Canal Right-of-Way as described in Docket 11522, page 436, records of said county; thence North 44 degrees 27 minutes 45 seconds East record (North 44 degrees 27 minutes 48 seconds East measured) along said Southerly line 203.94 feet to the True Point of Beginning; thence continuing North 44 degrees 27 minutes 45 seconds East record (North 44 degrees 27 minutes 48 seconds East measured) along said Southerly line 89.91 feet to the beginning of a curve concave to the Southeast having a radius of 1282.14 feet; thence Northeasterly along said curve and said Southerly line through a central angle of 14 degrees 48 minutes 56 seconds record (14 degrees 49 minutes 17 seconds measured), an arc distance of 331.54 record (331.67 measured) feet; 17 thence departing said Southerly line North 80 degrees 04 minutes 45 seconds record (North 80 degrees 04 minutes 28 seconds East measured), along said Southerly boundary of Tract No. GR-10-6A of the Central Arizona Project Canal Right-of-Way as described in Docket 11827, page 1263, records of said county 670.13 record (668.89 measured) feet, more or less, to a point on the Westerly right-of-way of Interstate 17 according to Book 542 of Deeds, page 471, records of said county; thence South 09 degrees 55 minutes 45 seconds East record (South 09 degrees 55 minutes 32 seconds East measured), along said right-of-way a distance of 278.16 feet; thence departing said right-of-way South 83 degrees 55 minutes 20 seconds West, a distance of 1035.80 feet to the True Point of Beginning. BUCKEYE SUBSTATION That portion of the Southeast quarter of the Southeast quarter of Section 7, Township 1 North, Range 3 West of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, lying South of the following described line: BEGINNING at a point on the East line of said Section 7, which point bears North 0 degrees 31 minutes 52 seconds East, 690 feet from the Southeast corner thereof; thence North 82 degrees 35 minutes 18 seconds West 2317.38 feet to the Point of Ending; EXCEPT the following described part of said Section 7: BEGINNING at a point on the South line of the Southeast quarter 430.8 feet West of the Southeast corner; thence Northerly, parallel to the East line of the Southeast quarter 315.5 feet; thence Easterly, parallel to the South line of the Southeast quarter, 160 feet; thence Northerly, parallel to the East line, 400 feet; thence Westerly, parallel to the South line, 400 feet; thence Southerly parallel to the East line, 400 feet; thence Easterly, parallel to the South line, 140 feet; thence Southerly, parallel to the East line, 315.5 feet; thence Easterly, along the South line, 100 feet to the Point of Beginning. COLTER SUBSTATION PARCEL NO. 1: That part of the Southwest quarter of the Southwest quarter of Section 24, Township 2 North, Range 1 West of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, described as follows: COMMENCING at the Southwest corner of said Section 24; 18 Thence North 00 degrees 12 minutes 23 seconds West along the West line of said Section 24, a distance of 950.24 feet to the North line of the South 950.00 feet of said Southwest quarter of the Southwest quarter of Section 24; Thence South 88 degrees 55 minutes 39 seconds East along said North line, a distance of 55.01 feet to a point on a line which is parallel with and 55.00 feet East of the said West line of Section 24, said point being the TRUE POINT OF BEGINNING; Thence North 00 degrees 12 minutes 23 seconds West along said parallel line, 273.78 feet; Thence South 89 degrees 03 minutes 57 seconds East, 26.19 feet; Thence North 00 degrees 12 minutes 23 seconds West, 18.13 feet to a point on a line that is parallel with and 60.00 feet South of the North line of said Southwest quarter of the Southwest quarter of Section 24; Thence South 89 degrees 03 minutes 57 seconds East along said parallel line, 343.88 feet to the East line of the West 425.00 feet of said Southwest quarter of the Southwest quarter of Section 24; Thence South 00 degrees 12 minutes 23 seconds East along said East line, 292.80 feet to the said North line of the South 950.00 feet of the Southwest quarter of the Southwest quarter of Section 24; Thence North 88 degrees 55 minutes 39 seconds West along said line, 370.09 feet to the TRUE POINT OF BEGINNING. PARCEL NO. 2: An easement for ingress and egress as set forth in instruments recorded in Document No. 89222578 and in Document No. 92545550 records of Maricopa County, Arizona, over the following described property: That part of the Southwest quarter of the Southwest quarter of Section 24, Township 2 North, Range 1 West of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, more particularly described as follows: COMMENCING at the Southwest corner of said Section 24; Thence North 00 degrees 12 minutes 23 seconds West, along the West line of said Section, 1302.02 feet to a point on the North line of said Southwest quarter of the Southwest quarter of Section 24; Thence South 89 degrees 03 minutes 57 seconds East along said North line, 55.01 feet to a point on a line which is parallel with and 55.00 feet East of the said West line of said Section 24, said point being the TRUE POINT OF BEGINNING; Thence South 89 degrees 03 minutes 57 seconds East, along said North line, 370.08 feet; Thence South 00 degrees 12 minutes 23 seconds East, 60.01 feet, said point being on a line that is parallel with and 60.00 feet South of the North line of said Southwest quarter of the Southwest quarter of Section 24; Thence North 89 degrees 03 minutes 57 seconds West, along said parallel line 370.08 feet, to a point being on a line that is parallel with and 55.00 feet East of the West line of said Section 24; 19 Thence North 00 degrees 12 minutes 23 seconds West along said parallel line a distance of 60.01 feet to the TRUE POINT OF BEGINNING. DOWNING SUBSTATION A portion of Tract 21 of State Plat No. 16, core South, recorded in Book 324, Page 50 of Maps, Maricopa County Recorders Office in Section 36, Township 4 North, Range 4 East, Gila and Salt River Meridian, Maricopa County, Arizona, and being more particularly described as follows: Commencing at the East quarter corner of said Section 36, from whence the Northeast corner of said Section 36 bears N00(degree)01'37"W, (basis of bearings), a distance of 2640.50 ft; thence N00(degree)01'37"W, along the east line of said Section 36, a distance of 847.91 ft; thence N36(degree)08'59"W, a distance of 728.73 ft to the true point of beginning; thence continuing N36 '08'59"W, a distance of 400.00 ft; thence S53(degree)51'01 "W, a distance of 300.00 ft; thence S36(degree)08'59"E, a distance of 400.00 ft; thence N53(degree)51'01 "E, a distance of 300.00 ft to the true point of beginning. Total 2.75 acres more or less. FLYING E SUBSTATION A portion of the Southwest quarter of Section 9, Township 7 North, Range 5 West of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly described as follows: Commencing at the Center of Section 9-(2 inch aluminum cap RLS 24514); THENCE North 89 degrees 54 minutes 33 seconds West along the North line of the Southwest quarter of said Section 9 a distance of 880.72 feet to the True Point of Beginning of said Parcel; THENCE continuing North 89 degrees 54 minutes 33 second West along the North line of the Southwest quarter of said Section 9 a distance of 400.00 feet; THENCE South 00 degrees 03 minutes 56 seconds West a distance of 278.70 feet to a point on the Northerly Right of Way of U.S. Highway 60; THENCE South 89 degrees 15 minutes 50 seconds East along the Northerly Right of Way. of U.S. Highway 60 a distance of 400.00 feet; THENCE North 00 degrees 04 minutes 16 seconds East a distance of 283.21 feet to the True Point Beginning. HATFIELD SUBSTATION The South 330 feet of the West half of the Southwest quarter of the Northwest quarter of the Northeast quarter of Section 8, Township 4 North, Range 1 East of the Gila and Salt River Base and Meridian, Maricopa County, AZ. HEDGEPATH HILLS SUBSTATION The North half of Lot 2, Section 7, Township 4 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; EXCEPT that part lying North of the following described line: 20 BEGINNING at a point on the West line of said Lot 2 which bears South 00 degrees 10 minutes East a distance of 446.24 feet from the Northwest corner thereof; thence North 86 degrees 04 minutes East a distance of 1026.53 feet to a point on the East line of said Lot 2 which bears South 00 degrees 11 minutes East, a distance of 383.93 feet from the Northeast corner thereof. MISTY WILLOW SUBSTATION The South 290 feet of the East 290 feet of the Northwest quarter of Section 8, Township 4 North, Range 3 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; Except the East 40 feet; and Except the South 40 feet; and Except an undivided 1/16 of all oil, gases, and other hydrocarbon substances, coal, stone, metals, minerals, fossils and fertilizer of every name and description and except all uranium, thorium, or any other material which is or may be determined by the laws of the State of Arizona, the United States of America, or decisions of courts to be peculiarly essential to the production of fissionable materials, whether or not of commercial value, as reserved in Section 37-231 Arizona Revised Statutes NEW RIVER SUBSTATION The South 120 feet of the North half of Lot 4, of Section 26, Township 7 North, Range 2 East, of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; EXCEPT all coal, oil, gas, and other mineral deposits as reserved unto the United States of America in the Patent of said land. STOUT SUBSTATION Being a portion of the South three quarters of the West half of the West half of the Southwest quarter of the Northeast quarter of Section 12, Township 4 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, being more particularly described as follows: COMMENCING at the Northwest corner of said Southwest quarter; Thence South 00 degrees 07 minutes 32 seconds East along the West line of said West half 331.46 feet to a point on the North line of said South three quarters; Thence South 89 degrees 42 minutes 22 seconds East along said North line 30.00 feet to the POINT OF BEGINNING; Thence continuing South 89 degrees 42 minutes 22 seconds East along said North line 304.59 feet to a point on the East line of said West half; Thence South 00 degrees 08 minutes 09 seconds East along said East line 286.01 feet; Thence North 89 degrees 42 minutes 22 seconds West along a line parallel with the North line of said South three quarters 304.64 feet to a point on a line 30.00 feet East of and parallel with the West line of said West half; 21 Thence North 00 degrees 07 minutes 32 seconds West along said parallel line 286.01 feet to the POINT OF BEGINNING. WATSON SUBSTATION A parcel of land situate in a portion of the Southeast quarter of Section 10, Township 1 North, Range 3 West of the Gila and Salt River Base and Meridian, Maricopa County, Arizona more particularly described as follows: Commencing at the Southeast corner of said Section 10 from which the South quarter corner of said Section 10 bears South 89 degrees 27 minutes 57 seconds West, a distance of 2626.67 feet; Thence South 89 degrees 27 minutes 57 seconds West, along the Southerly line of the Southeast quarter of said Section 10, a distance of 912.51 feet; Thence North 00 degrees 33 minutes 32 seconds West, a distance of 65.00 feet to the true point of beginning; Thence South 89 degrees 27 minutes 57 seconds West, along a line 65.00 feet northerly of and parallel with said southerly line, a distance of 209.34 feet; Thence North 00 degrees 33 minutes 32 seconds West, a distance of 220.00 feet; Thence North 89 degrees 27 minutes 57 seconds East, along a line 285.00 feet northerly of and parallel with said southerly line, a distance of 209.34 feet; Thence South 00 degrees 33 minutes 32 seconds East, a distance of 220.00 feet to the true point of beginning. WILDFLOWER SUBSTATION The South 704.51 feet of the South half of the West 330 feet of the East half of the East half of the Southwest quarter of Section 6, Township 1 North, Range 1 West of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; EXCEPT that portion, if any, lying within the West 660 feet of the East half of the Southwest quarter of Section 6; and EXCEPT that portion, if any, lying within the East half of the East half of the East half of the Southwest quarter of Section 6. WEST PHOENIX POWER PLANT All real and personal property that are part of the West Phoenix Power Plant, including all such property repurchased by the Company at the end of the term of that certain Lease and other documents relating to the "Combined Cycle Transactions" described in the Twenty-first Supplemental Indenture dated as of April 15, 1997 to the Mortgage, and as further described in that certain Deed, Bill of Sale and Assignment as recorded on December 15, 2000 in the records of Maricopa County, Arizona as Instrument No. 2002-0957462, and further including the following described real property: 22 PARCEL NO. 1: The Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; EXCEPT the East 20 feet; and EXCEPT the West 10 feet; and EXCEPT the South 33 feet for roadway; and EXCEPT the North 20 feet for railroad; and EXCEPT BEGINNING at a point 811 feet South and 695 feet West of the East quarter corner of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian; Thence South 453 feet; Thence West 95 feet; Thence North 453 feet; Thence East 95 feet, to the POINT OF BEGINNING; and EXCEPT all that portion of the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, more particularly bounded and described as follows: BEGINNING at a point from which the East quarter corner of said Section 9, bears North 29 degrees 57 minutes 45 seconds East a distance of 686.8 feet; Thence South 669.0 feet; Thence West 352.0 feet; Thence North 453.0 feet; Thence West 95.0 feet; Thence North 102.0 feet; Thence East 30.0 feet; Thence North 114.0 feet; Thence East 417.0 feet to the Place of Beginning; and EXCEPT that portion of land situated in the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, more particularly described as follows: BEGINNING at the South quarter corner of Section 9; 23 Thence on a bearing North 00 degrees 18 minutes 40 seconds West along the midsection line of Section 9, a distance of 1161.30 feet to a point; Thence North 89 degrees 22 minutes 30 seconds East a distance of 505.41 feet to a point being corner number Sixteen, of the Combined Cycle Plant Site, and TRUE POINT OF BEGINNING of the parcel herein described; Thence continue North 89 degrees 22 minutes 30 seconds East a distance of 1094.88 feet to a point being corner number One; Thence North 00 degrees 38 minutes 30 seconds West a distance of 207.88 feet to a point being corner number Two; Thence South 89 degrees 22 minutes 30 seconds West a distance of 340.00 feet to a point being corner number Three; Thence South 0 degrees 38 minutes 30 seconds East a distance of 187.88 feet to a point being corner number Four; Thence South 89 degrees 22 minutes 30 seconds West a distance of 45.00 feet to a point being corner number Five; Thence North 0 degrees 38 minutes 30 seconds West a distance of 823.72 feet to a point being corner number Six; Thence South 89 degrees 21 minutes 30 seconds West a distance of 279.44 feet to a point being corner number Seven; Thence North 0 degrees 38 minutes 30 seconds West a distance of 40.0 feet to a point being corner number Eight; Thence South 89 degrees 21 minutes 30 seconds West a distance of 93.0 feet to a point being corner number Nine; Thence South 0 degrees 38 minutes 30 seconds East a distance of 40.0 feet to a point being corner number Ten; Thence South 89 degrees 21 minutes 30 seconds West a distance of 255.0 feet to a point being corner number Eleven; Thence North 0 degrees 38 minutes 30 seconds West a distance of 131.96 feet to a point being corner number Twelve; Thence South 89 degrees 21 minutes 30 seconds West a distance of 502.62 feet to a point being corner number Thirteen; Thence South 0 degrees 38 minutes 30 seconds East a distance of 528.30 feet to a point being corner number Fourteen; Thence North 89 degrees 21 minutes 30 seconds East a distance of 420.18 feet to a point being corner number Fifteen; 24 Thence South 0 degrees 38 minutes 30 seconds East a distance of 447.17 feet to a point being corner number Sixteen and the TRUE POINT OF BEGINNING; and EXCEPT a portion of the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, being more particularly described as follows: COMMENCING at the South quarter corner of Section 9, from whence the center quarter corner of Section 9, bears North 0 degrees 18 minutes 18 seconds West 2634.59 feet distant; Thence North 0 degrees 18 minutes 18 seconds West a distance of 125.00 feet; Thence North 89 degrees 02 minutes 00 seconds East a distance of 60.00 feet to the TRUE POINT OF BEGINNING; Thence North 0 degrees 18 minutes 16 seconds West a distance of 825.06 feet; Thence North 89 degrees 02 minutes 00 seconds East a distance of 565.00 feet; Thence South 0 degrees 18 minutes 18 seconds East a distance of 900.06 feet; Thence South 89 degrees 02 minutes 00 seconds West a distance of 515.00 feet; Thence North 0 degrees 18 minutes 18 seconds West, a distance of 75.00 feet; Thence South 89 degrees 02 minutes 00 seconds West a distance of 50.00 feet to the TRUE POINT OF BEGINNING; and EXCEPT the North 17.00 feet of the South 50.00 feet of the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; EXCEPT the West 10.00 feet thereof; and EXCEPT the East 574.18 feet thereof; and EXCEPT a portion of the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River and Base and Meridian, Maricopa County, Arizona, more particularly described as follows: BEGINNING at the Southeast corner of Section 9; Thence South 89 degrees 02 minutes 00 seconds West along the South line of Section 9, a distance of 1399.80 feet; Thence North 00 degrees 58 minutes 00 seconds West to a point on the North right of way line of Buckeye Road, a distance of 50.00 feet to the TRUE POINT OF BEGINNING; Thence South 89 degrees 02 minutes 00 seconds West, a distance of 580.80 feet along said right of way; Thence North 00 degrees 17 minutes 52 seconds West, a distance of 900.06 feet to a point on the South right of way of Hadley Street; Thence North 89 degrees 02 minutes 00 seconds East, a distance of 580.80 feet along said right of way; 25 Thence South 00 degrees 17 minutes 52 seconds East, a distance of 900.06 feet to the TRUE POINT OF BEGINNING; and EXCEPT that portion of the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, described as follows: COMMENCING at the Southeast corner of said Section 9; Thence South 89 degrees 02 minutes 00 seconds West along the South line of said Section 9, a distance of 83.10 feet; Thence North 00 degrees 58 minutes 00 seconds West, a distance of 50.00 feet to a point on the North right of way line of Buckeye Road, being the TRUE POINT OF BEGINNING; Thence South 89 degrees 02 minutes 00 seconds West along said right of way line, a distance of 1316.70 feet; Thence North 00 degrees 17 minutes 52 seconds West, a distance of 900.06 feet to a point on the South right of way line of Hadley Street; Thence North 89 degrees 02 minutes 00 seconds East along said right of way line, a distance of 1345.10 feet to a point on a tangent curve concave Southwesterly with a radius of 20.00 feet, and a central angle of 90 degrees 58 minutes 17 seconds, a distance of 31.76 feet to a point tangent to the West right of way line of 43rd Avenue; Thence South 00 degrees 00 minutes 27 seconds West along said right of way line, a distance of 504.79 feet; Thence South 01 degrees 09 minutes 12 seconds West along said right of way line, a distance of 100.01 feet; Thence South 00 degrees 00 minutes 27 seconds West along said right of way line, a distance of 242.11 feet; Thence South 51 degrees 16 minutes 25 seconds West, a distance of 53.77 feet to the TRUE POINT OF BEGINNING, as conveyed in that certain Warranty Deed from Arizona Public Service Company to Suncor Development Company dated March 6, 1998 and recorded July 24, 1998, as Document No. 980636446, records of Maricopa County, Arizona; and EXCEPT those roadways for 43rd Avenue, 47th Avenue, Buckeye Road and Hadley Street as delineated on Map of Dedication for APS Property dated May 18, 1989 and recorded November 9, 1989 in Book 335 of Maps, page 21, records of Maricopa County, Arizona; and EXCEPT a parcel of land being located in the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; said parcel being more particularly described as follows: COMMENCING at the South quarter corner of said Section; Thence North 00 degrees 18 minutes 01 seconds West along the West line of the Southeast quarter of Section 9, Township 1 North, Range 2 East, a distance of 1,486.38 feet; 26 Thence North 89 degrees 17 minutes 24 seconds East, a distance of 40 feet to the TRUE POINT OF BEGINNING of the parcel herein described; Thence continuing Northeast along the same bearing, a distance of 317.26 feet along the North line of said parcel; Thence South 01 degrees 11 minutes 27 seconds East, a distance of 95.08 feet; Thence North 89 degrees 17 minutes 24 seconds East, a distance of 49.43 feet; Thence South 00 degrees 42 minutes 36 seconds East, a distance of 100.14 feet; Thence North 89 degrees 17 minutes 24 seconds East, a distance of 43.34 feet; Thence South 00 degrees 42 minutes 36 seconds East, a distance of 105.96 feet; Thence South 89 degrees 20 minutes 44 seconds West along the South line of the parcel herein described, a distance of 412.99 feet; Thence North 00 degrees 18 minutes 01 seconds West along the West line of said parcel, a distance of 300.78 feet to the TRUE POINT OF BEGINNING of the parcel herein described; and EXCEPT a parcel of land located in the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; said parcel being more particularly described as follows: COMMENCING at the East quarter corner of said Section; Thence South 89 degrees 21 minutes 48 seconds West along the North line of the Southeast quarter of Section 9, Township 1 North, Range 2 East, a distance of 2,622.28 feet; Thence South 00 degrees 18 minutes 01 seconds East along the West line of the Southeast quarter of said Section, a distance of 94.82 feet; Thence North 89 degrees 17 minutes 24 seconds East, a distance of 30 feet to the TRUE POINT OF BEGINNING of the parcel herein described; Thence continuing Northeast along the same bearing, a distance of 1,040.41 feet along the North line of said parcel; Thence South 45 degrees 00 minutes 00 seconds East, a distance of 85.85 feet; Thence South 00 degrees 42 minutes 36 seconds East, a distance of 88.39 feet; Thence South 89 degrees 17 minutes 24 seconds West, a distance of 481.33 feet; Thence South, a distance of 293.07 feet; Thence South 89 degrees 17 minutes 24 seconds West, a distance of 618.57 feet; Thence North 00 degrees 18 minutes 01 seconds West, a distance of 442.90 feet to the TRUE POINT OF BEGINNING of the parcel herein described; and 27 EXCEPT a parcel of land located in the Southeast quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; said parcel being more particularly described as follows: COMMENCING at the Southeast corner of said Section; Thence North 00 degrees 03 minutes 22 seconds East along the East line of Section 9, Township 1 North, Range 2 East, a distance of 1,359.93 feet; Thence South 89 degrees 21 minutes 48 seconds West, a distance of 40 feet to the TRUE POINT OF BEGINNING of the parcel herein described; Thence continuing Southwest along the same bearing, a distance of 302.93 feet along the South line of the parcel herein described; Thence North 00 degrees 03 minutes 22 seconds East along the West line of said parcel, a distance of 669.00 feet; Thence North 89 degrees 21 minutes 48 seconds East along the North line of said parcel, a distance of 302.93 feet; Thence South 00 degrees 03 minutes 22 seconds West along the East line of said parcel, a distance of 669.00 feet to the TRUE POINT OF BEGINNING of the parcel herein described. PARCEL NO. 2: The East half of the North half of the East half of the Southwest quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; EXCEPT beginning at the Northeast corner of said Southwest quarter of Section 9 in the Southerly line of the parcel of land described in deed dated March 19, 1910 to Phoenix & Buckeye Railway Company recorded in Book 89 of Deeds, Page 97, records of Maricopa County, Arizona; Thence Westerly along said Southerly line also the North line of said Southwest quarter of Section 9, a distance of 1334.29 feet to the Northwest corner of the Northeast quarter of said Southwest quarter of Section 9, also the Northeast corner of the parcel of land described in Deed dated August 22, 1949 to Arizona Eastern Railroad Company recorded in Docket 491, Page 216, records of Maricopa County, Arizona; Thence Southerly along the West line of said Northeast quarter of said Southwest quarter of Section 9, a distance of 20.0 feet; Thence Easterly parallel with said North line of said Southwest quarter of Section 9, a distance of 1334.38 feet to the East line of said Southwest quarter of Section 9; Thence Northerly along said East line a distance of 20.0 feet to the point of beginning; ALSO EXCEPT a strip of land 20 feet in width in Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, said strip of land lying 10 feet on each side of the following described center line; 28 Beginning at the Northeast corner of said Section 9, and using as a base the North boundary line of said Section, said North boundary line having a bearing of South 89 degrees 22 minutes West based on a magnetic bearing of South 75 degrees 00 minutes West; Thence South 88 degrees 22 minutes West a distance of 2661.5 feet to the True Point of Beginning; Thence South 0 degrees 07 minutes West a distance of 1325 feet; Thence South 0 degrees 01 minutes West a distance of 1243.4 feet; Thence South 0 degrees 14 minutes East a distance of 1331.6 feet; Thence South 0 degrees 27 minutes East a distance of 1318.9 feet to a point in the South boundary line of said Section 9, from which point the Southeast corner of said Section 9 bears North 89 degrees 36 minutes East a distance of 2606.5 feet, as conveyed to the United States of America, by instrument recorded in Deed Book 115, Page 276, records of Maricopa County, Arizona; EXCEPT that portion of the East half of the North half of the East half of the Southwest quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona, more particularly described as follows: COMMENCING at the Northeast corner of said Southwest quarter of Section 9 from whence the Southeast corner of said Southwest quarter of Section 9 lies South 00 degrees 18 minutes 01 seconds East, a distance of 2634.48 feet; Thence South 00 degrees 18 minutes 01 seconds East along the East line of said Southwest quarter of Section 9, a distance of 497.53 feet; Thence South 89 degrees 24 minutes 46 seconds West, a distance of 53.01 feet to the TRUE POINT OF BEGINNING; Thence South 00 degrees 37 minutes 11 seconds East, a distance of 467.02 feet; Thence South 89 degrees 26 minutes 58 seconds West, a distance of 392.04 feet; Thence North 00 degrees 36 minutes 52 seconds West, a distance of 466.77 feet; Thence North 89 degrees 24 minutes 46 seconds East, a distance of 392.00 feet to the TRUE POINT OF BEGINNING; and EXCEPT a parcel of land located in the Southwest quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; said parcel being more particularly described as follows: COMMENCING at the South quarter corner of said Section; Thence North 00 degrees 18 minutes 01 seconds West along the East line of the Southwest quarter of Section 9, Township 1 North, Range 2 East, a distance of 1,281.67 feet; Thence South 89 degrees 17 minutes 36 seconds West, a distance of 40 feet to the TRUE POINT OF BEGINNING of the parcel herein described; 29 Thence continuing Southwest along the same bearing, a distance of 629.09 feet along the South line of the parcel herein described; Thence North 00 degrees 13 minutes 26 seconds West along the West line of the parcel herein described, a distance of 1,123.64 feet; Thence North 89 degrees 21 minutes 48 seconds East, a distance of 221.11 feet; Thence South 00 degrees 36 minutes 52 seconds East, a distance of 781.97 feet; Thence North 89 degrees 17 minutes 24 seconds East, a distance of 402.19 feet; Thence South 00 degrees 18 minutes 01 seconds East, a distance of 341.39 feet to the TRUE POINT OF BEGINNING of the parcel herein described. PARCEL NO. 3: The South one-half of the East one-half of the Southwest quarter of Section 9, Township 1 North, Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, Arizona; EXCEPT the West 30.00 feet and EXCEPT a strip of land 20.00 feet in width in Section 9, said strip of land lying 10.00 feet on each side of the following described centerline; COMMENCING at the Northeast corner of said Section 9, and using as a base the North boundary of said Section, said North boundary line having a bearing of South 89 degrees 22 minutes West based on a magnetic bearing of South 75 degrees 00 minutes West; Thence South 88 degrees 22 minutes West 2,661.5 feet to the POINT OF BEGINNING; Thence South 00 degrees 07 minutes West 1,325 feet; Thence South 00 degrees 01 minutes West 1,243.4 feet; Thence South 00 degrees 14 minutes East 1,331.6 feet; Thence South 00 degrees 27 minutes East 1,318.9 feet to a point in the South boundary line of said Section 9 from which the Southeast corner of said Section 9 bears North 89 degrees 36 minutes East 2,606.5 feet, as conveyed to the United States of America by instrument recorded in Book 115 of Deeds, Page 276, records of Maricopa County, Arizona; and EXCEPT the South 450.00 feet. NAVAJO COUNTY CHOLLA GENERATING STATION POWER PLANT SITE That part of Sections 15, 22, 23, 24, 25, 26, 27, 35 and 36, Township 18 North, Range 19 East, Gila and Salt River Meridian, Navajo County, Arizona described as follows: 30 BEGINNING at a capped pipe marking the common corner of Sections 14, 15, 22 and 23; Thence North 0 degrees 22 minutes 36 seconds West along the East line of said Section 15, a distance of 2669.78 feet to a capped pipe marking the East quarter corner thereof; Thence North 89 degrees 55 minutes 54 seconds West along the East-West mid-section line of said Section 15, a distance of 299.82 feet to a point in the West line of the East 300 feet of the Southeast quarter of said Section 15, being a found 5/8 inch rebar; Thence South 0 degrees 22 minutes 36 seconds East along said West line, a distance of 2668.57 feet to a found 5/8 inch rebar located in the South line of said Section 15; Thence South 0 degrees 3 minutes 13 seconds West along the West line of the East 300 feet of the Northeast quarter of said Section 22, a distance of 1234.75 feet to a point in the Southerly right of way line of old U.S. Highway 66; Thence North 56 degrees 28 minutes 30 seconds West, along said right of way line, a distance of 156.72 feet to a point in the East line of the parcel of land described in Docket 265, page 174; Thence South 34 degrees 45 minutes 39 seconds West, along last said East line, a distance of 3654.13 feet to a point in the Northerly right of way line of the Atchison, Topeka and Santa Fe Railroad; Thence South 44 degrees 6 minutes 47 seconds West, a distance of 210.22 feet to the intersection of the Southerly right of way line of the Atchison, Topeka and Santa Fe Railroad and the North-South mid-section line of said Section 22; Thence South 0 degrees 2 minutes 33 seconds East along last said mid-section line, a distance of 1005.76 feet to the common quarter corner of said Sections 22 and 27; Thence North 89 degrees 44 minutes 21 seconds West along the North line of said Section 27, a distance of 120.00 feet to its Intersection with the thread of the Little Colorado River; Thence Southerly and Easterly along said thread to its intersection with the East line of said Section 27, said point lying South 0 degrees 30 minutes 30 seconds East, a distance of 600.00 feet from the Northeast corner of said Section 27; Thence South 0 degrees 30 minutes 30 seconds East, along last said East line, a distance of 4714.56 feet to the common corner of said Section 26, 27, 34 and 35; Thence North 89 degrees 37 minutes 3 seconds East, along the North line of said Section 35, a distance of 422.00 feet to its intersection with the thread of the Little Colorado River, from which point the common corner of said Sections 25, 26, 35 and 36 bears North 89 degrees 37 minutes 3 seconds East, a distance of 4894.86 feet; Thence Southerly and Southeasterly along said thread to its intersection with the East line of said Section 35, from which point the common corner of said Sections 25, 26, 35 and 36 bears North 0 degrees 14 minutes 4 seconds West, a distance of 3171.07 feet; Thence South 0 degrees 14 minutes 4 seconds East along last said East line, a distance of 2166.50 feet to the common corner of said Sections 35 and 36 and of Sections 1 and 2 of Township 17 North, Range 19 East, Gila and Salt River Meridian; 31 Thence North 88 degrees 27 minutes 31 seconds East along the South line of said Section 36, a distance of 1337.23 feet to the West 1/16th corner between said Sections 36 and 1; Thence North 0 degrees 16 minutes 29 seconds West along the West 1/16th line of said Section 36, a distance of 5324.98 feet to the West 1/16th corner between said Sections 25 and 36; Thence North 89 degrees 0 minutes 0 seconds East along the South line of said Section 25, a distance of 1112.92 feet to its intersection with the Southwesterly right of way line of the Atchison, Topeka and Santa Fe Railroad; Thence North 56 degrees 26 minutes 18 seconds West along said Southwesterly right of way line, a distance of 611.23 feet; Thence North 33 degrees 18 minutes 42 seconds East, a distance of 200.00 feet to the Northeasterly right of way line of the Atchison, Topeka and Santa Fe Railroad, said point being in the East line of the West 2050 feet of said Section 25; Thence North 0 degrees 24 minutes 1 second West along last said East line, a distance of 4808.67 feet to its intersection with the North line of said Section 25, from which the common corner of said Sections 23, 24, 25 and 26 bears South 89 degrees 31 minutes 41 seconds West (South 89 degrees 20 minutes West of record) a distance of 2050.00 feet; Thence North 0 degrees 24 minutes 31 seconds West (North 0 degrees 36 minutes West of record), a distance of 637.66 feet (637.67 feet of record); Thence North 71 degrees 35 minutes 24 seconds West (North 71 degrees 46 minutes West of record), a distance of 2149.74 feet (2150.04 feet of record) to a point in the West line of said Section 24 (said point being North 0 degrees 2 minutes East along the West line of said Section 24, a distance of 1334.13 feet from the Southwest corner of said Section 24, of record); Thence North 0 degrees 14 minutes 48 seconds East along the East line of said Section 23, a distance of 164.99 feet to its intersection with the Southerly right of way line of Old U.S. Highway 66; Thence North 74 degrees 55 minutes 37 seconds West along last said Southerly right of way line, a distance of 1708.33 feet to the beginning of a curve concave Northerly having a radius of 5779.58 feet; Thence continue along last said Southerly right of way line, Northwesterly along the arc of said curve through a central angle of 5 degrees 28 minutes 11 seconds, a distance of 551.73 feet to a point of tangency; Thence continue along last said Southerly right of way line, North 69 degrees 27 minutes 38 seconds West, a distance of 1040.53 to the beginning of a curve concave Northerly having a radius of 2914.79 feet; Thence continue along last said Southerly right of way line, along the arc of last said curve through a central angle of 4 degrees 1 minute 0 seconds, a distance of 83.66 feet to a point from which a radial line bears North 22 degrees 11 minutes 3 seconds East said point being the Northeast corner of that part of the West half of the said Section 23 described in Parcel 1 of Docket 766, page 155; Thence South 26 degrees 20 minutes 42 seconds West, a distance of 359.44 feet to the Southeast corner of said parcel of land; 32 Thence North 68 degrees 47 minutes 52 seconds West, a distance of 484.70 feet to the Southwest corner of said parcel of land; Thence North 33 degrees 42 minutes 40 seconds East, a distance of 396.09 feet to the Northwest corner of said parcel of land, said point being in the arc of a curve in said Southerly right of way line of Old U.S. Highway 66, said curve being concave to the North having a radius of 1482.39 feet and from which a radial line thereof bears North 29 degrees 40 minutes 36 seconds East; Thence Northwesterly along last said Southerly right of way line along the arc of said curve through a central angle of 9 degrees 7 minutes 0 seconds, a distance of 103.40 feet; Thence continue along last said Southerly right of way line, North 56 degrees 19 minutes 38 seconds West, a distance of 1950.09 feet to its intersection with the West line of said Section 23; Thence North 0 degrees 3 minutes 13 seconds East along last said West line, a distance of 1431.70 feet to the POINT OF BEGINNING; EXCEPT that part of said Section 22 lying whiting the right of way of Interstate 40 and being described as follows: BEGINNING at a capped pipe marking the common corner of said Sections 14, 15, 22 and 23; Thence South 0 degrees 3 minutes 13 seconds West along the East line of said Section 22, a distance of 384.09 feet to a point in the Northeasterly right of way line of said Interstate 40 and the TRUE POINT OF BEGINNING; Thence continue South 0 degrees 3 minutes 13 seconds West along last said East line, a distance of 396.43 feet to a point in the Southwesterly right of way line of said Interstate 40; Thence North 63 degrees 11 minutes 44 seconds West along said Southwesterly right of way line, a distance of 335.95 feet to a point in the West line of the East 300 feet of the Northeast quarter of said Section 22; Thence North 0 degrees 3 minutes 13 seconds East, along last said West line, a distance of 413.51 feet to a point in said Northeasterly right of way line; Thence South 59 degrees 11 minutes 46 seconds East, along said Northeasterly right of way line, a distance of 218.60 feet; Thence continue along last said Northeasterly right of way line South 63 degrees 11 minutes 44 seconds East, a distance of 125.38 feet to the TRUE POINT OF BEGINNING; and EXCEPT that part of said Section 22 lying within the right of way of Old U.S. Highway 66 and being described as follows: BEGINNING at a capped pipe marking the common corner of said Sections 14, 15, 22 and 23; Thence South 0 degrees 3 minutes 13 seconds West along the East line of said Section 22, a distance of 1311.58 feet to a point in the Northeasterly right of way line of said Old U.S. Highway 66 and the TRUE POINT OF BEGINNING; 33 Thence continue along last said East line, South 0 degrees 3 minutes 13 seconds West, a distance of 120.12 feet to a point in the Southwesterly right of way line of said Old U.S. Highway 66; Thence North 56 degrees 28 minutes 30 seconds West along last said right of way line, a distance of 359.47 feet; Thence North 0 degrees 3 minutes 13 seconds East, a distance of 120.12 feet to a point in last said Northeasterly right of way line; Thence South 56 degrees 28 minutes 30 seconds East, along last said right of way line, a distance of 359.47 feet to the TRUE POINT OF BEGINNING; and EXCEPT that certain tract of land situated in the Southwest quarter of Section 23, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona, being more particularly described as follows: COMMENCING at the brass cap that marks the Southwest corner of Section 23, from whence the brass cap that marks the Northwest corner of said Section bears North 0 degrees 2 minutes 5 seconds West; Thence North 61 degrees 33 minutes 56 seconds East a distance of 1368.08 feet to a 5/8 inch rebar that marks the Southeasterly corner of said tract and the TRUE POINT OF BEGINNING; Thence North 57 degrees 23 minutes 27 seconds West a distance of 357.99 feet to a 5/8 inch rebar; Thence North 32 degrees 36 minutes 33 seconds East a distance of 117.67 feet to a 5/8 inch rebar; Thence North 72 degrees 58 minutes 14 seconds East a distance of 114.71 feet to a 5/8 inch rebar; Thence North 32 degrees 36 minutes 33 seconds East a distance of 555.92 feet to a brass cap set in concrete; Thence South 77 degrees 44 minutes 13 seconds East a distance of 273.73 feet to a 5/8 inch rebar; Thence South 32 degrees 36 minutes 33 seconds West a distance of 256.05 feet to a 5/8 inch rebar; Thence South 57 degrees 23 minutes 27 seconds East a distance of 27.06 feet to a 5/8 inch rebar; Thence South 32 degrees 36 minutes 33 seconds West a distance of 600.12 feet to the TRUE POINT OF BEGINNING; and EXCEPT that certain tract of land situated in the Southwest quarter of Section 23, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona, being more particularly described as follow: COMMENCING at the brass cap that marks the Southwest corner of Section 23, from whence the brass cap that marks the Northwest corner of said Section bears North 0 degrees 2 minutes 5 seconds West; Thence North 9 degrees 43 minutes 57 seconds East a distance of 1364.55 feet to the 5/8 inch rebar that marks the most Southerly corner of said tract and the TRUE POINT OF BEGINNING; Thence North 34 degrees 53 minutes 35 seconds West a distance of 144.40 feet to a 5/8 inch rebar; 34 Thence North 55 degrees 6 minutes 25 seconds East a distance of 439.58 feet to a 5/8 inch rebar; Thence South 34 degrees 53 minutes 35 seconds East a distance of 85.73 feet to a 5/8 inch rebar; Thence South 55 degrees 6 minutes 25 seconds West a distance of 276.35 feet to a 5/8 inch rebar; Thence South 34 degrees 53 minutes 35 seconds East a distance of 58.67 feet to a 5/8 inch rebar; Thence South 55 degrees 6 minutes 25 seconds West a distance of 163.23 feet to the TRUE POINT OF BEGINNING; and EXCEPT all those parts thereof lying within the Atchison, Topeka and Santa Fe Railroad Companys' 200 foot wide fee owned right of way; and EXCEPT all oil, gas and minerals as reserved in Deed recorded in Docket 129, page 481, records of Navajo County, Arizona, affects Section 25; and EXCEPT 1/16th of all oil, gases and other hydrocarbon substances, coal, stone, metals, minerals, fossils and fertilizers of every name and description and except all materials which may be essential to production of fissionable materials as reserved in Arizona Revised Statutes, affects Section 36; and EXCEPT all oil, gas and sodium as reserved to the United States of America in Patent to the West half of the Northwest quarter of Section 26. WELL FIELD PARCEL 1: The North Half; The Southeast quarter; The North half of the Southwest quarter; and The Southeast quarter of the Southwest quarter of Section 4, Township 17 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT the following two parcels: (1) In the Northeast quarter of Section 4, Township 17 North, Range 19 East of the Gila and Salt River and Meridian, Navajo County, Arizona, more particularly described as follows: FROM the Northeast corner of said Section 4; thence South (assumed bearing) along the East line of the Northeast quarter of said Section 4, a distance of 900.00 feet; Thence West 25.00 feet to the point of beginning of the parcel of land herein described and the Northeast corner thereof; Thence West 460.00 feet; Thence South 460.00 feet; Thence East 460.00 feet; Thence North 460.00 feet to the POINT OF BEGINNING. 35 (2) A rectangular shaped parcel of land in the Northeast quarter of Section 4, Township 17 North, Range 19 East of the Gila and Salt River and Meridian, Navajo County, Arizona, more particularly described as follows: COMMENCING at the Northeast corner of said Section 4; thence South (assumed bearing) along the East line of said Section 4, a distance of 1360.00 feet; Thence West 25.00 feet to the Southeast corner of that certain parcel of land described in Deed to Mountain States Telephone and Telegraph Company recorded in Docket 151, page 497, and the TRUE POINT OF BEGINNING for the parcel herein described; Thence South 400.00 feet; Thence West 460.00 feet; Thence North 400.00 feet to the Southwest corner of said parcel described in Docket 151, page 497; Thence East along the South line of last said parcel, a distance of 460.00 feet to the POINT OF BEGINNING. PARCEL 2: The Southwest quarter of the Southwest quarter of Section 4, Township 17 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona. PARCEL 3: The Southeast quarter of Section 2, Township 17 North, range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT all oil, gas and other hydrocarbon substances, Helium or other substances of a gaseous nature, coal, metals, minerals, fossils, fertilizer or every name and description, together with all uranium, thorium, or any other material which is or may be determined by the laws of the United State, or of this state or decisions of court to be peculiarly essential to the production of fissionable materials as reserved in Deed recorded in Book 509, page 438, records of Navajo County, Arizona. County, Arizona. PARCEL 4: The East half of the Northwest quarter and the West half of the Northeast quarter of Section 34, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT all oil and/or minerals as reserved in Deed recorded in Book 31 of deeds, page 310, and recorded in Docket 688, page 17, records of Navajo County, Arizona. PARCEL 5: The Southwest quarter of the Northwest quarter, the North half of the Southwest quarter, and the Northwest quarter of the Southeast quarter of Section 34, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT the following described property conveyed by Special Warranty Deed recorded in Document No. 2002-6843, records of Navajo County, Arizona: 36 COMMENCING at the Southwest corner of Section 34, a 3" brass cap stamped A.P.S. 1977; Thence North 00 degrees 03 minutes 35 seconds West 1338.47 feet along the West section line; Thence North 89 degrees 56 minutes 02 seconds East 2390.60 feet to a 1/2" rebar and tag LS 22290, the POINT OF BEGINNING; Thence North 00 degrees 08 minutes 50 seconds West 1082.24 feet to a 1/2" rebar and tag LS 22290; Thence North 89 degrees 56 minutes 02 seconds East 1609.99 feet to a 1/2" rebar and tag LS 22290; Thence South 00 degrees 08 minutes 50 seconds East 1082.24 feet to a 1/2" rebar and tag LS 22290; Thence South 89 degrees 56 minutes 02 seconds West 1609.99 feet to the POINT OF BEGINNING. PARCEL 6: Section 28, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT all oil, gas and minerals reserved in Docket 168, page 155, from the Southeast quarter and the South half of the Northeast quarter and the Northwest quarter of the Northeast quarter. PARCEL 7: The Southwest quarter of Section 21, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT any part of the Southwest quarter lying North of the Little Colorado River. PARCEL 8: The South half of Section 6, Township 17 North, Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT all coal and other minerals as reserved in Patent from United States of America; and EXCEPT the East 219 acres thereof. PARCEL 9: The East 219 acres of the South half of Section 6, Township 17 North, Range 20 East of the Gila Salt River and Meridian, Navajo County, Arizona; EXCEPT all coal and other minerals as reserved in Patent from United States of America. PARCEL 10: Section 10 , Township 17 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT all minerals in Patent from United States of America. 37 FLY ASH PARCEL 1: The West half of the West half of the Northwest quarter of the Northwest quarter and the West half of the Northwest quarter of the Southwest quarter of the Northwest quarter of Section 29, Township 18 North, Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona. PARCEL 2: The West half of the East half of the West half of the Northwest quarter of the Northwest quarter and the West half of the East half of the Northwest quarter of the Southwest quarter of the Northwest quarter of Section 29, Township 18 North, Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona. EXCEPT all oil and gas as conveyed in Book 11 of Deeds, page 355, records of Navajo County, Arizona. PARCEL 3: COMMENCING at the Northeast corner of Section 25, Township 18 North, Range 19 East of Gila and Salt River Meridian; Thence along said Section line South 88 degrees 35 minutes West for a distance of 2460 feet to a point; Thence South 43 degrees 30 minutes East for a distance of 380 feet to a point; Thence South 36 degrees 35 minutes East for a distance of 2180 feet to a point; Thence South 63 degrees 50 minutes East for a distance of 1000 feet to a point on the East section line of said Section 25; Thence North 2530 feet to the POINT OF BEGINNING, being in Section 25, Township 18 North, Range 19 East of the Gila and Salt River and Meridian; And including all land in said Section 25 located on the North side of U.S. Highway 66 (now Interstate Highway 40), Navajo County, Arizona; EXCEPT beginning at a point of Section tine 1300 feet West of the Northeast corner of Section 25, Township 18 North, Range 19 East; Thence West on Section line 1095 feet; Thence South 37 degrees 49 minutes East 1100 feet; Thence North 32 degrees 25 minutes East 210.6 feet; Thence North 61 degrees 51 minutes East 600 feet; Thence North 26 degrees 17 minutes West 460 feet to the PLACE OF BEGINNING; and EXCEPT that portion of which lies Southwesterly of the Northeasterly right of way line of existing U.S. Highway 66 (now Interstate Highway 40). 38 PARCEL 4: The East half of the Southeast quarter of the Southeast quarter of Section 24, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navaho County, Arizona. EXCEPT all the oil, gas, sodium and potassium as reserved in Patent from United States of America. PARCEL 5: The South half of the Southwest quarter of Section 19, Township 18 North, Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona. PARCEL 6: All of Section 30 North of the Northerly boundary of Interstate Highway 40 in Township 18 North, Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT the Southeast quarter of the Southeast quarter and the East half of the Southwest quarter of the Southeast quarter of Section 30, Township 18 North, Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona; and EXCEPT all oil, gas and mineral rights as reserved in Patent from United States of America. BOTTOM ASH PARCEL 1: The West half of the Southwest quarter of Section 13, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; EXCEPT all oil, gas rights as reserved in Deed recorded in Book 13 of Deeds, page 164, records of Navajo County, Arizona. PARCEL 2: The West half of the Northwest quarter of the Northwest quarter of the Northwest quarter; The North half of the Northeast quarter of the Northwest quarter of the Northwest quarter of the Northwest quarter; The Southwest quarter of the Northeast quarter of the Northwest quarter of the Northwest quarter of the Northwest quarter; The Northwest quarter of the Southeast quarter of the Northeast quarter of the Northwest quarter of the Northwest quarter of the Northwest quarter; The West half of the West half of the Southeast quarter of the Northwest quarter of the Northwest quarter of the Northwest quarter; The North half of the Northeast quarter of the Northwest quarter of the Southeast quarter of the Northwest quarter of the Northwest quarter of the Northwest quarter of Section 24, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona. 39 PARCEL 3: The North half of the Northeast quarter of the Northeast quarter, the Northeast quarter of the Northwest quarter of the Northeast quarter of Section 23, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona. PARCEL 4: The East half of the Northeast quarter of the Southeast quarter; The Southwest quarter of the Northeast quarter of the Southeast quarter; The East half of the Southwest quarter of the Southeast quarter; and The Southeast quarter of the Southeast quarter of Section 14, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona; Except all oil, gas, sodium and potassium as reserved in Patent from United States of America. YAVAPAI COUNTY MCGUIREVILLE SUBSTATION The West 250.00 feet of the following described parcel: A parcel of land located in the Southeast quarter of Section 33, Township 15 North Range 5 East of the Gila and Salt River Base and Meridian, Yavapai County, Arizona, described as follows: Commencing at the Southeast corner of said Section 33; thence North 89(degree)41'00" West 2694.12 feet to the Southwest corner of said Southeast quarter; thence North 01(degree)01'25" East, along the West line of said Southeast quarter, 1051.66 feet to the true point of beginning; thence continuing North 01(degree)01'25" East, along said West line, 280.00 feet; thence South 88(degree)25'00" East, 660.13 feet; thence South 11053'50" East, along the West line of an easement created by a combination of the deeds recorded in Book 187 of Deeds, Page 174 and Book 1396 of Official Records, Page 937 a distance of 287.92 feet; thence 88(degree)25'00" West 724.51 feet to the true point of beginning. Together with an easement for ingress, egress and utilities set forth in deed recorded in Book 3214 of Official Records, Page 318. SECTION 11. THE ELECTRIC SUBSTATIONS OF THE COMPANY, including all buildings, structures, towers, poles, all equipment, appliances and devices for transforming, converting and distributing electric energy, and all land owned by the Company upon which the same are situated, and all of the Company's easements, rights of way, rights, machinery, equipment, appliances, devices, licenses and supplies forming a part of said substations, or any of them, including additions and improvements to any of the foregoing, or used or enjoyed or capable of being use or enjoyed in conjunction with any thereof. SECTION 12. Additions, extensions and improvements to THE ELECTRIC TRANSMISSION SYSTEMS of the Company. 40 SECTION 13. Additions, extensions and improvements to THE ELECTRIC DISTRIBUTION SYSTEMS of the Company, including, the construction of additional facilities throughout the Company's service area, as well as extension of residential and downtown underground distribution facilities, including associated distribution equipment such as voltage regulators, capacitor banks, sectionalizing equipment, transformers, street lighting systems, meters and services, including reconstruction and improvements to provide efficient Company operation. 41 IN WITNESS WHEREOF, ARIZONA PUBLIC SERVICE COMPANY, party hereto of the first part, has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by its President, one of its Vice Presidents, or its Treasurer, and its corporate seal to be attested by its Secretary or one of its Assistant Secretaries or Associate Secretaries for and in its behalf, in the City of Phoenix, Arizona, and THE BANK OF NEW YORK, party hereto of the second part, has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by one of its Vice Presidents or Assistant Vice Presidents and its corporate seal to be attested by one of its Assistant Vice Presidents or Assistant Treasurers for and in its behalf, in the City of New York, New York, all as of the 1st day of November, 2002. ARIZONA PUBLIC SERVICE COMPANY Barbara M. Gomez -------------------------------------- TREASURER Attest: Betsy A. Pregulman - -------------------------------------- ASSOCIATE SECRETARY Executed, sealed and delivered by ARIZONA PUBLIC SERVICE COMPANY in the presence of: - -------------------------------------- [SEAL] - -------------------------------------- THE BANK OF NEW YORK, As Trustee Debra A. Schwalb -------------------------------------- VICE PRESIDENT Attest: Thomas J. Provenzano - -------------------------------------- Executed, sealed and delivered by THE BANK OF NEW YORK in the presence of: Thomas J. Provenzano - -------------------------------------- Thomas J. Provenzano Vice President [SEAL] 42 STATE OF ARIZONA.. ) ) ss.: COUNTY OF MARICOPA ) On this 1st day of November, 2002, before me, Debra L. Blondin, the undersigned officer, personally appeared Barbara M. Gomez, who acknowledged herself to be the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, and that she, as such Treasurer being authorized so to do, executed the foregoing instrument for the purposes therein contained, by signing the name of the corporation by herself as Treasurer. IN WITNESS WHEREOF, I have hereunto set my hand and seal. Debra L. Blondin -------------------------------------- Notary Public My Commission Expires June 7, 2004 ---------------- [SEAL] STATE OF ARIZONA ) ) ss.: COUNTY OF MARICOPA ) On this 1st day of November, 2002, before me, Debra L. Blondin, the undersigned officer, personally came Barbara M. Gomez, to me known, who being by me duly sworn, did depose and say that she resides in Phoenix, Arizona, that she is the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, the corporation described in and which executed the above instrument; that she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that she signed her name thereto by like order. IN WITNESS WHEREOF, I have hereunto set my hand and seal. Debra L. Blondin -------------------------------------- Notary Public My Commission Expires June 7, 2004 ---------------- [SEAL] STATE OF ARIZONA ) ) ss.: COUNTY OF MARICOPA ) This instrument was acknowledged before me on November 1, 2002 by Barbara M. Gomez and Betsy A. Pregulman, as Treasurer and Associate Secretary, respectively, of ARIZONA PUBLIC SERVICE COMPANY. Debra L. Blondin -------------------------------------- Notary Public My Commission Expires June 7, 2004 ---------------- [SEAL] 43 STATE OF NEW JERSEY ) ) ss.: COUNTY OF PASSAIC ) On this 1st day of November, 2002, before me, Ronald M. Mania, Notary Public in and for the County and State aforesaid, residing therein, duly commissioned and sworn, personally appeared Debra A. Schwalb, known to me to be a Vice President of THE BANK OF NEW YORK, a New York banking corporation, which executed the within instrument, and Thomas J. Provenzano, known to me to be a Vice President of The Bank of New York, who being by me duly sworn, acknowledged before me that the seal affixed to said instrument is the corporate seal of The Bank of New York, that they, being authorized so to do, executed the within instrument on behalf of The Bank of New York by authority of its board of directors, and that said instrument is the free act and deed of The Bank of New York for the purposes therein contained. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written. Ronald M. Mania -------------------------------------- Notary Public My Commission Expires 10/4/2006 ---------------- [SEAL] STATE OF NEW JERSEY ) ) ss.: COUNTY OF PASSAIC ) This instrument was acknowledged before me on November 1, 2002 by Debra A. Schwalb and Thomas J. Provenzano, each as a Vice President of THE BANK OF NEW YORK. Ronald M. Mania -------------------------------------- Notary Public My Commission Expires 10/4/2006 ---------------- [SEAL] EX-4.2 5 ex4-2.txt 57TH SUPPLEMENTAL INDENTURE Exhibit 4.2 ================================================================================ ARIZONA PUBLIC SERVICE COMPANY (formerly Central Arizona Light and Power Company) TO THE BANK OF NEW YORK AS TRUSTEE UNDER CENTRAL ARIZONA LIGHT AND POWER COMPANY'S MORTGAGE AND DEED OF TRUST, DATED AS OF JULY 1, 1946. --------------- Fifty-Seventh Supplemental Indenture --------------- DATED AS OF MARCH 1, 2003 This Mortgage covers real property, personal property and chattels. This instrument and the above-mentioned Mortgage and Deed of Trust contain after-acquired property provisions. ================================================================================ FIFTY-SEVENTH SUPPLEMENTAL INDENTURE --------------- INDENTURE, dated as of the 1st day of March, 2003, made and entered into by and between ARIZONA PUBLIC SERVICE COMPANY, a corporation of the State of Arizona, the principal place of business and mailing address of which is 400 North Fifth Street, Phoenix, Arizona 85004 (hereinafter sometimes called the Company), party of the first part, and THE BANK OF NEW YORK, a New York banking corporation, the mailing address of which is 385 Rifle Camp Road, 3rd Floor, West Paterson, New Jersey 07424 (hereinafter sometimes called the Trustee), party of the second part, as Trustee under the Mortgage and Deed of Trust, dated as of July 1, 1946 (hereinafter called the Mortgage), which Mortgage was executed and delivered by the Company under its former name, Central Arizona Light and Power Company, to secure the payment of bonds issued or to be issued under and in accordance with the provisions of the Mortgage, reference to which said Mortgage is hereby made, this Indenture (hereinafter called the Fifty-seventh Supplemental Indenture) being supplemental thereto; WHEREAS, said Mortgage was recorded and filed in Counties in the State of Arizona as follows:
FILED AND ABSTRACTED RECORDED AS REAL MORTGAGE AS CHATTEL MORTGAGE --------------------------- -------------------- CHATTEL DATE BOOK OR MORTGAGE COUNTY RECORDED DOCKET PAGE BOOK PAGE ------ -------- ------ ---- ---- ---- Apache........................... 7-28-50 16 1 9 154 Cochise.......................... 2-3-53 80 28 19 292 Coconino......................... 1-20-53 39 1 10 286 Gila............................. 1-17-53 32 84 17 -- Graham........................... 12-3-63 92 87 15 223 Maricopa......................... 8-6-46 408 163 92 204 Mohave........................... 11-13-57 28 68 12 13 Navajo........................... 10-14-49 31 483 16 521 Pima............................. 1-24-53 558 351 14 -- Pinal............................ 10-25-52 68 31 12 591 Yavapai.......................... 8-7-46 79 1 12 223 Yuma............................. 8-1-47 58 173 21 265 and in Counties in the State of New Mexico as follows: McKinley......................... 5-31-61 36 153 4 295 San Juan......................... 1-31-61 472 140 (No. 72441)
the copy recorded in Yuma County, Arizona also being effective for La Paz County, Arizona, formed on December 31, 1982; and copies of said Mortgage were filed with the office of the Bureau of Indian Affairs at Window Rock, Arizona, and with the Navajo Tribe of Indians at Window Rock, Arizona, and in the offices of the Secretary of State and the State Land Department of the State of Arizona (all the said counties and the said offices above referred to being herein referred to as "jurisdictions"); and WHEREAS, by the Mortgage, the Company covenanted that it would execute and deliver such supplemental indenture or indentures and such further instruments and do such further acts as might be necessary or proper to carry out more effectually the purposes of the Mortgage and to make subject to the Lien of the 2 Mortgage any property thereafter acquired, made or constructed and intended to be subject to the Lien thereof; and WHEREAS, the Company has executed and delivered to the Trustee fifty-six indentures supplemental to the Mortgage (hereinafter respectively called the First through the Fifty-sixth Supplemental Indentures) dated as of December 1, 1947, April 1, 1949, February 1, 1950, December 1, 1950, February 1, 1953, November 1, 1953, March 1, 1954, October 1, 1957, March 1, 1959, November 1, 1961, June 1, 1962, December 1, 1962, September 1, 1963, September 1, 1967, April 1, 1970, March 15, 1972, April 1, 1974, February 15, 1975, June 1, 1975, November 15, 1975, April 15, 1977, January 15, 1978, March 1, 1979, October 15, 1979, May 15, 1980, February 2, 1982, April 15, 1982, July 1, 1983, October 15, 1983, June 15, 1984, January 15, 1985, May 1, 1985, June 1, 1985, November 1, 1985, January 15, 1986, March 1, 1986, May 1, 1986, February 1, 1987, June 1, 1987, November 15, 1987, April 1, 1989, February 15, 1990, May 15, 1990, April 15, 1991, December 15, 1991, January 15, 1992, March 1, 1992, June 15, 1992, February 1, 1993, August 1, 1993, August 1, 1993, September 15, 1993, March 1, 1994, November 15, 1996, April 1, 1997, and November 1, 2002, each of which has been or will be recorded or filed in, or a recording or filing is or will be effective with respect to, each jurisdiction referred to above; and WHEREAS, in addition to the property described in the Mortgage, as heretofore supplemented and amended, the Company has acquired certain other property, rights and interests in property; and WHEREAS, the Company has heretofore issued, in accordance with the provisions of the Mortgage, as heretofore supplemented and amended, bonds of a series entitled and designated First Mortgage Bonds, 2-3/4% Series due 1976 (hereinafter called the bonds of the First Series), in the aggregate principal amount of Eight Million Five Hundred Thousand Dollars ($8,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3-1/8% Series due 1977 (hereinafter called the bonds of the Second Series), in the aggregate principal amount of Two Million Five Hundred Thousand Dollars ($2,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3% Series due 1979 (hereinafter called the bonds of the Third Series), in the aggregate principal amount of Four Million Dollars ($4,000,000); bonds of a series entitled and designated First Mortgage Bonds, 2-3/4% Series due 1980 (hereinafter called the bonds of the Fourth Series), in the aggregate principal amount of Five Million Dollars ($5,000,000); bonds of a series entitled and designated First Mortgage Bonds, 2-7/8% Series due 1980 (hereinafter called the bonds of the Fifth Series), in the aggregate principal amount of Six Million Dollars ($6,000,000); bonds of a series entitled and designated First Mortgage Bonds, 3-1/2% Series due 1983 (hereinafter called the bonds of the Sixth Series), in the aggregate principal amount of Fourteen Million Five Hundred Thousand Dollars ($14,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3 1/2% Series due November 1, 1983 (hereinafter called the bonds of the Seventh Series), in the aggregate principal amount of Five Million Seven Hundred Twenty-three Thousand Dollars ($5,723,000); bonds of a series entitled and designated First Mortgage Bonds, 3-1/4% Series due 1984 (hereinafter called the bonds of the Eighth Series), in the aggregate principal amount of Fifteen Million Dollars ($15,000,000); bonds of a series entitled and designated First Mortgage Bonds, 5-1/8% Series due 1987 (hereinafter called the bonds of the Ninth Series), in the aggregate principal amount of Fifteen Million Dollars ($15,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.70% Series due 1989 (hereinafter called the bonds of the Tenth Series), in the aggregate principal amount of Twenty Million Dollars ($20,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.80% Series due 1991 (hereinafter called the bonds of the Eleventh Series), in the aggregate principal amount of Thirty-five Million Dollars ($35,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.45% Series due 1992 (hereinafter called the bonds of the Twelfth Series), in the aggregate principal amount of Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and 3 designated First Mortgage Bonds, 4.40% Series due 1992 (hereinafter called the bonds of the Thirteenth Series), in the aggregate principal amount of Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and designated First Mortgage Bonds, 4.50% Series due 1993 (hereinafter called the bonds of the Fourteenth Series), in the aggregate principal amount of Fifteen Million Dollars ($15,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.25% Series due 1997 (hereinafter called the bonds of the Fifteenth Series), in the aggregate principal amount of Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and designated First Mortgage Bonds, 8.50% Series due 1975 (hereinafter called the bonds of the Sixteenth Series), in the aggregate principal amount of Thirty Million Dollars ($30,000,000); bonds of a series entitled and designated First Mortgage Bonds, 7.45% Series due 2002 (hereinafter called the bonds of the Seventeenth Series), in the aggregate principal amount of Sixty Million Dollars ($60,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.20% Series due 2004 (hereinafter called the bonds of the Eighteenth Series), in the aggregate principal amount of Fifty Million Dollars ($50,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9.50% Series due 1982 (hereinafter called the bonds of the Nineteenth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9.80% Series due 1980 (hereinafter called the bonds of the Twentieth Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10.625% Series due 2000 (hereinafter called the bonds of the Twenty-first Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.45% Series A due 2007 (hereinafter called the bonds of the Twenty-second Series), in the aggregate principal amount of Thirteen Million Dollars ($13,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6.45% Series B due 2007 (hereinafter called the bonds of the Twenty-third Series), in the aggregate principal amount of Thirty Million Dollars ($30,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6% Series A due 2008 (hereinafter called the bonds of the Twenty-fourth Series), in the aggregate principal amount of Thirty-four Million Dollars ($34,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9.95% Series due 2004 (hereinafter called the bonds of the Twenty-fifth Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12-1/8% Series due 2009 (hereinafter called the bonds of the Twenty-sixth Series), in the aggregate principal amount of Seventy-five Million Dollars ($75,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12-7/8% Series due 2000 (hereinafter called the bonds of the Twenty-seventh Series), in the aggregate principal amount of One Hundred Eighty-five Million Dollars ($185,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-3/8% Series due 1985 (hereinafter called the bonds of the Twenty-eighth Series), in the aggregate principal amount of Sixty Million Two Hundred Fifty Thousand Dollars ($60,250,000); bonds of a series entitled and designated First Mortgage Bonds, 16% Series due 1992 (hereinafter called the bonds of the Twenty-ninth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12-3/4% Series due 2013 (hereinafter called the bonds of the Thirtieth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 13-1/2% Series due 2013 (hereinafter called the bonds of the Thirty-first Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 15% Series due 1994 (hereinafter called the bonds of the Thirty-second Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 12% Series due 1995 (hereinafter called the bonds of the Thirty-third Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 13-1/4% Series due 2007 (hereinafter called the bonds of the Thirty-fourth Series), in the aggregate principal amount of Fifty Million Dollars ($50,000,000); bonds of a series entitled and designated First Mortgage Bonds, 11-1/2% Series due 2015 (hereinafter called the bonds of the Thirty-fifth Series), in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 11-1/2% Series due November 1, 2015 (hereinafter called the bonds of the Thirty-sixth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage 4 Bonds, 11% Series due 2016 (hereinafter called the bonds of the Thirty-seventh Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9-1/4% Series due 1996 (hereinafter called the bonds of the Thirty-eighth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9% Series due 1996 (hereinafter called the bonds of the Thirty-ninth Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9% Series due 2017 (hereinafter called the bonds of the Fortieth Series), in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9-7/8% Series due 1997 (hereinafter called the bonds of the Forty-first Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-3/4% Series due 2017 (hereinafter called the bonds of the Forty-second Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-3/4% Series due 2019 (hereinafter called the bonds of the Forty-third Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10-1/4% Series due 2000 (hereinafter called the bonds of the Forty-fourth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 10 1/4% Series due 2020 (hereinafter called the bonds of the Forty-fifth Series), in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9-1/2% Series due 2021 (hereinafter called the bonds of the Forty-sixth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 9% Series due 2021 (hereinafter called the bonds of the Forty-seventh Series), in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 7-1/8% Series due 1997, in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000), and bonds of a series entitled and designated First Mortgage Bonds, 8-3/4% Series due 2024, in the aggregate principal amount of One Hundred Seventy-five Million Dollars ($175,000,000) (hereinafter collectively called the bonds of the Forty-eighth Series); bonds of a series entitled and designated First Mortgage Bonds, 7-5/8% Series due 1998, in the aggregate principal amount of One Hundred Million Dollars ($100,000,000), and bonds of a series entitled and designated First Mortgage Bonds, 8-1/8% Series due 2002, in the aggregate principal amount of One Hundred Twenty-five Million Dollars ($125,000,000) (hereinafter collectively called the bonds of the Forty-ninth Series); bonds of a series entitled and designated First Mortgage Bonds, 7-5/8% Series due 1999 (hereinafter called the bonds of the Fiftieth Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 8% Series due 2025 (hereinafter called the bonds of the Fifty-first Series), in the aggregate principal amount of One Hundred Fifty Million Dollars ($150,000,000); bonds of a series entitled and designated First Mortgage Bonds, 7-1/4% Series due 2023 (hereinafter called the bonds of the Fifty-second Series), in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 5-7/8% Series due 2028 (hereinafter called bonds of the Fifty-third Series), in the aggregate principal amount of Twelve Million Eight Hundred Fifty Thousand Dollars ($12,850,000); bonds of a series entitled and designated First Mortgage Bonds, 5-7/8% Series due 2028 (hereinafter called bonds of the Fifty-fourth Series), in the aggregate principal amount of One Hundred Forty-one Million One Hundred Fifty Thousand Dollars ($141,150,000); bonds of a series entitled and designated First Mortgage Bonds, 5-1/2% Series due 2028 (hereinafter called bonds of the Fifty- fifth Series), in the aggregate principal amount of Twenty-five Million Dollars ($25,000,000); bonds of a series entitled and designated First Mortgage Bonds, 5-3/4% Series due 2000 (hereinafter called bonds of the Fifty-sixth Series) in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, 6-5/8% Series due 2004 (hereinafter called bonds of the Fifty-seventh Series) in the aggregate principal amount of One 5 Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, Senior Note Series A (hereinafter called bonds of the Fifty-eighth Series) in the aggregate principal amount of One Hundred Million Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage Bonds, Senior Note Series B (hereinafter called bonds of the Fifth-ninth Series) in the aggregate principal amount of Fifty Million Dollars ($50,000,000); and bonds of a series entitled and designated First Mortgage Bonds, Senior Note Series C (hereinafter called bonds of the Sixtieth Series) in the aggregate principal amount of Ninety Million Dollars ($90,000,000); and WHEREAS, said The Bank of New York, by an instrument in writing, effective on the opening of business on September 29, 1995, succeeded to Bank of America National Trust and Savings Association as Trustee under the Mortgage; and, pursuant to Section 104 of the Mortgage, The Bank of New York is the successor Trustee under the Mortgage; and WHEREAS, Section 8 of the Mortgage provides that the form of each series of bonds (other than bonds of the First Series) issued thereunder shall be established by Resolution of the Board of Directors of the Company and that the form of each series, as established by said Board of Directors, shall specify the descriptive title of the bonds and various other terms thereof, and may also contain such provisions not inconsistent with the provisions of the Mortgage as the Board of Directors may, in its discretion, cause to be inserted therein expressing or referring to the terms and conditions upon which such bonds are to be issued and/or secured under the Mortgage; and WHEREAS, Section 120 of the Mortgage provides, among other things, that any power, privilege or right expressly or impliedly reserved to or in any way conferred upon the Company by any provision of the Mortgage, whether such power, privilege or right is in any way restricted or is unrestricted, may be in whole or in part waived or surrendered or subjected to any restriction if at the time unrestricted or to additional restriction if already restricted, and the Company may enter into any further covenants, limitations or restrictions for the benefit of any one or more series of bonds issued thereunder, or the Company may cure any ambiguity contained therein, or in any supplemental indenture, or may establish the terms and provisions of any series of bonds other than said First Series, by an instrument in writing executed and acknowledged by the Company in such manner as would be necessary to entitle a conveyance of real estate to record in all of the states in which any property at the time subject to the Lien of the Mortgage shall be situated; and WHEREAS, the Company now desires to create a new series of bonds to be issued under and pursuant to the Mortgage in accordance with the provisions of Article VI thereof, and to add to its covenants and agreements contained in the Mortgage, as heretofore supplemented and amended, certain other covenants and agreements to be observed by it and to alter and amend in certain respects the covenants and provisions contained in the Mortgage, as heretofore supplemented and amended; and WHEREAS, Maricopa County, Arizona Pollution Control Corporation (the "Issuer") has issued Fifty-Seven Million Dollars ($57,000,000) in aggregate principal amount of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 1994 Series C (the "Maricopa Bonds") pursuant to the Indenture of Trust dated as of May 1, 1994 (as amended from time to time, the "Maricopa Indenture") between the Issuer and The Bank of New York, as trustee (together with its successors in such capacity, the "Maricopa Trustee"). The Issuer loaned the proceeds of the Maricopa Bonds to the Company pursuant to the Loan Agreement dated as of May 1, 1994 between the Issuer and the Company (as amended from time to time, the "Loan Agreement"), and the Company agreed to make payments of principal, premium, if any, and interest on, and purchase price of, the Maricopa Bonds from time to time when due, to the extent that monies for such payments are not otherwise available pursuant to the terms of the Maricopa Indenture (the "Loan Agreement Payment Obligations"); and 6 WHEREAS, pursuant to the provisions of the Maricopa Indenture, the Maricopa Bonds will bear interest at a Term Rate (as defined in the Maricopa Indenture) during the period beginning March 6, 2003 and ending on March 4, 2004 or such earlier termination date as may occur pursuant to the terms of the Maricopa Indenture (the "Term Rate Period"); and WHEREAS, in order to secure the Company's Loan Agreement Payment Obligations to and including the hereinafter defined Termination Date, the Company desires to provide for the issuance under the Mortgage of a new series of bonds designated "1.70% First Mortgage Bonds, Maricopa 1994 Series C, having the same rate of interest, payment dates and redemption and tender provisions and in the same aggregate principal amount as the Maricopa Bonds; and WHEREAS, the execution and delivery by the Company of this Fifty-seventh Supplemental Indenture, and the terms of the bonds of the Sixty-first Series hereinafter referred to, have been duly authorized by the Board of Directors of the Company by appropriate Resolutions of said Board of Directors; NOW THEREFORE, THIS INDENTURE WITNESSETH: That Arizona Public Service Company, in consideration of the premises and of One Dollar to it duly paid by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, and in further evidence of assurance of the estate, title and rights of the Trustee and in order further to secure the payment of both the principal of and interest and premium, if any, on the bonds from time to time heretofore, herewith or hereafter issued under the Mortgage, according to their tenor and effect, and the performance of all the provisions of the Mortgage (including any instruments supplemental thereto and any modifications made as in the Mortgage provided) and of said bonds, hereby grants, bargains, sells, releases, conveys, assigns, transfers, mortgages, pledges, sets over and confirms (subject, however, to Excepted Encumbrances as defined in Section 6 of the Mortgage and to the liens permitted by Section 36 of the Mortgage) unto The Bank of New York, as Trustee under the Mortgage, and to its successor or successors in said trust, and to said Trustee and its successors and assigns forever, all the properties of the Company described in the Mortgage, as heretofore supplemented and amended (except any properties which have been released from the Lien of the Mortgage), and all the properties specifically described in Article V hereof. Also all other property, real, personal and mixed, of the kind or nature specifically mentioned in Article V hereof or of any other kind or nature (except any herein or in the Mortgage, as heretofore supplemented and amended, expressly excepted and except any which may not lawfully be mortgaged or pledged hereunder), now owned or, subject to the provisions of subsection (I) of Section 87 of the Mortgage, hereafter acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) and wheresoever situated, including (without in anywise limiting or impairing by the enumeration of the same the scope and intent of the foregoing or of any general description contained in this Fifty-seventh Supplemental Indenture) all lands, power sites, flowage rights, water rights, water locations, water appropriations, ditches, flumes, reservoirs, reservoir sites, canals, raceways, dams, dam sites, aqueducts, and all other rights or means for appropriating, conveying, storing and supplying water; all rights of way and roads; all plants for the generation of electricity by steam, water and/or other power; all power houses, gas plants, street lighting systems, standards and other equipment incidental thereto, telephone, radio and television systems, air-conditioning systems and equipment incidental thereto, water works, water systems, steam heat and hot water plants, substations, lines, service and supply systems, bridges, culverts, tracks, ice or refrigeration plants and equipment, offices, buildings and other structures and equipment thereof; all machinery, engines, boilers, dynamos, electric, gas and other machines, regulators, meters, transformers, generators, motors, electrical, gas and mechanical appliances, conduits, cables, water, steam heat, gas or other pipes, gas mains and pipes, service pipes, fittings, valves and connections, pole and transmission lines, wires, cables, tools, implements, apparatus, furniture and chattels; all franchises, consents or permits; all lines for the transmission and distribution of electric current, 7 gas, steam heat or water for any purpose including towers, poles, wires, cables, pipes, conduits, ducts and all apparatus for use in connection therewith; all real estate, lands, easements, servitudes, licenses, permits, franchises, privileges, rights of way and other rights in or relating to public or private property, real or personal, or the occupancy of such property and (except as herein or in the Mortgage, as heretofore supplemented and amended, expressly excepted) all the right, title and interest the Company may now have or hereafter acquire in and to any and all property of any kind or nature appertaining to and/or used and/or occupied and/or enjoyed in connection with any property hereinbefore or in the Mortgage, as heretofore supplemented and amended, described. TOGETHER WITH all and singular the tenements, hereditaments, prescriptions, servitudes and appurtenances belonging or in anywise appertaining to the aforementioned property or any part thereof, with the reversion and reversions, remainder and remainders and (subject to the provisions of Section 57 of the Mortgage) the tolls, rents, revenues, issues, earnings, income, product and profits thereof, and all the estate, right, title, interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforementioned property and franchises and every part and parcel thereof. IT IS HEREBY AGREED by the Company that, subject to the provisions of subsection (I) of Section 87 of the Mortgage and to the extent permitted by law, all the property, rights and franchises acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) after the date hereof, except any herein or in the Mortgage, as heretofore supplemented and amended, expressly excepted, shall be and are as fully granted and conveyed hereby and as fully embraced within the lien hereof and the Lien of the Mortgage as if such property, rights and franchises were now owned by the Company and were specifically described herein and conveyed hereby. PROVIDED that the following are not and are not intended to be now or hereafter granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed hereunder and are hereby expressly excepted from the lien and operation of this Fifty-seventh Supplemental Indenture and from the Lien and operation of the Mortgage, viz.: (1) cash, shares of stock, bonds, notes and other obligations and other securities not hereafter specifically pledged, paid, deposited, delivered or held under the Mortgage or covenanted so to be; (2) merchandise, equipment, apparatus, materials or supplies held for the purpose of sale or other disposition in the usual course of business; fuel, oil and similar materials and supplies consumable in the operation of any of the properties of the Company; construction equipment acquired for temporary use; all aircraft, tractors, rolling stock, trolley coaches, buses, motor coaches, automobiles, motor trucks and other vehicles and materials and supplies held for the purpose of repairing or replacing (in whole or part) any of the same; all timber, minerals, mineral rights and royalties and all Natural Gas and Oil Production Property, as defined in Section 4 of the Mortgage; (3) bills, notes and accounts receivable, judgments, demands and chooses in action, and all contracts, leases and operating agreements not specifically pledged under the Mortgage or covenanted so to be; (4) the last day of the term of any lease or leasehold which may be or become subject to the Lien of the Mortgage; (5) electric energy, gas, steam, ice and other materials or products generated, manufactured, produced, purchased or acquired by the Company for sale, distribution or use in the ordinary course of its business; and (6) the Company's franchise to be a corporation; PROVIDED, HOWEVER, that the property and rights expressly excepted from the Lien and operation of the Mortgage in the above subdivisions (2) and (3) shall (to the extent permitted by law) cease to be so excepted in the event and as of the date that the Trustee or a receiver or trustee shall enter upon and take possession of the Mortgaged and Pledged Property in the manner provided in Article XIII of the Mortgage by reason of the occurrence of a Default as defined in Section 65 thereof. TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed by the Company as aforesaid, or intended so to be, unto The Bank of New York, the Trustee, and its successors and assigns forever. 8 IN TRUST NEVERTHELESS, for the same purposes and upon the same terms, trusts and conditions and subject to and with the same provisos and covenants as are set forth in the Mortgage, as supplemented and amended. AND IT IS HEREBY COVENANTED by the Company that all the terms, conditions, provisos, covenants and provisions contained in the Mortgage, as supplemented and amended, shall affect and apply to the property hereinbefore described and conveyed and to the estate, rights, obligations and duties of the Company and the Trustee and the beneficiaries of the trust with respect to said property, and to the Trustee and its successors as Trustee of said property in the same manner and with the same effect as if the said property had been owned by the Company at the time of the execution of the Mortgage and had been specifically and at length described in and conveyed to said Trustee by the Mortgage as a part of the property therein stated to be conveyed. The Company further covenants and agrees to and with the Trustee and its successors in said trust under the Mortgage, as follows: ARTICLE I. SIXTY-FIRST SERIES OF BONDS. SECTION 1. There shall be a series of bonds designated "1.70% First Mortgage Bonds, Maricopa 1994 Series C (hereinafter sometimes referred to as the "Sixty-first Series" or the "Bonds"), limited to the aggregate principal amount of $57,000,000, each of which shall also bear the descriptive title First Mortgage Bond, and the form thereof, which shall be established by Resolution of the Board of Directors of the Company, shall contain suitable provisions with respect to the matters hereinafter specified in this Supplemental Indenture. Bonds of the Sixty-first Series shall be dated as provided in Section 10 of the Mortgage; shall be issued as a single fully registered bond, and shall be registered in the name of the Maricopa Trustee; shall evidence, secure and provide for the payment of the Company's Loan Agreement Payment Obligations; and shall be payable on each date provided in or pursuant to the Maricopa Indenture for the payment of principal (whether upon redemption or acceleration) of, and interest on, the Maricopa Bonds, until the principal of and interest on the Maricopa Bonds shall have been fully paid or provision for the payment thereof shall have been made in accordance with the Maricopa Indenture, in the amount then payable as principal and interest upon the Maricopa Bonds; and on each date provided in or pursuant to the Maricopa Indenture for the payment of the purchase price of the Maricopa Bonds tendered for purchase in accordance with Section 2.01(d) or Section 2.01(e) of the Maricopa Indenture, in the amount then payable as such purchase price of the tendered Maricopa Bonds, to the extent proceeds of the remarketing of such tendered Maricopa Bonds are insufficient to pay the purchase price thereof; provided, however, that the Bonds shall terminate and expire and shall be of no further force and effect at 5:00 p.m. Eastern Standard Time on the Termination Date (defined below). The principal and purchase price of and interest on the Bonds shall be payable by the Company to the Maricopa Trustee, as pledgee and assignee of the Issuer, in accordance with the requirements of the Maricopa Indenture. All payments by the Company on the Bonds shall be made on or prior to the due date thereof. The Bonds of the Sixty-first Series will terminate and expire, and be of no further force and effect, at 5:00 p.m. Eastern Standard Time on the earlier of: (1) the effective date of the first Rate Period (as defined in the Maricopa Indenture) immediately following the Term Rate Period and (2) the first date during or after the Term Rate Period on which the Maricopa Bonds are subject to mandatory tender pursuant to Section 2.01(e) of the Maricopa Indenture, in each case, as long as tendering holders of Maricopa Bonds have been paid the purchase 9 price for the Maricopa Bonds pursuant to any optional or mandatory tender occurring on the Termination Date and the Company is not otherwise in default in its Loan Agreement Payment Obligations under Section 4.2 of the Loan Agreement on such date. In the event that on the date specified in clause (1) or (2) of the immediately preceding sentence, tendering holders of Maricopa Bonds have not been paid the purchase price for tendered Maricopa Bonds or the Company is otherwise in default in such Loan Agreement Payment Obligations, the Bonds will terminate and expire on the first date thereafter on which such payment obligations have been satisfied. Such date of termination and expiration of the Bonds is herein referred to as the "Termination Date." The Company shall have no obligation to make payments with respect to the Bonds unless and until, and only to the extent that, payments shall be due and payable on the Maricopa Bonds to and including the Termination Date. Any provision hereof to the contrary notwithstanding, the Company shall receive a credit against its obligation to make any payment of interest on the Bonds in an amount equal to the amount, if any, held by the Maricopa Trustee under the Maricopa Indenture on deposit in the Bond Fund (as defined in the Maricopa Indenture) and available to make the corresponding payment on the Maricopa Bonds. In addition, the Company shall receive a credit against its obligation to make any payment of principal or purchase price of the Bonds, whether upon redemption, acceleration or tender of the Maricopa Bonds or otherwise, in an amount equal to the amount, if any, held by the Maricopa Trustee under the Maricopa Indenture on deposit in said Bond Fund and available to make the corresponding payment on the Maricopa Bonds. The Company covenants and agrees that, prior to the Termination Date, it will not take any action (except as described herein or as contemplated in the Maricopa Indenture or the Loan Agreement) that would cause the outstanding principal amount of the Bonds of the Sixty-first Series to be less than the outstanding principal amount of the Maricopa Bonds. SECTION 2. Upon payment of the principal of and interest due on the Maricopa Bonds, whether by acceleration or otherwise, or upon provision for the payment thereof having been made in accordance with the Maricopa Indenture, whether with payments made pursuant to the Bonds or with other funds available for such payment, Bonds in a principal amount equal to the principal amount of Maricopa Bonds so paid or for which such provision for payment has been made shall be deemed fully paid, satisfied and discharged and the obligations of the Company thereunder shall be terminated and such Bonds shall be surrendered to and cancelled by the Trustee. The Company will issue and the Trustee will authenticate a new Bond for the unpaid portion thereof. SECTION 3. Bonds of the Sixty-first Series shall be held by the Maricopa Trustee and shall not be transferable except to its permitted successors and assigns under the Maricopa Indenture. The Maricopa Trustee, as the holder of the Bonds, shall attend meetings of bondholders under the Mortgage or deliver its proxy in connection therewith. Either at such meeting, or otherwise when the consent of the holders of the Bonds is sought without a meeting, the Maricopa Trustee shall vote as the holder of the Bonds, or shall consent with respect thereto; provided, however, that the Maricopa Trustee shall not vote in favor of, or consent to, any modification of the Mortgage which is correlative to a modification of the Maricopa Indenture or the Loan Agreement which would require the approval of owners of Maricopa Bonds without the approval of the owners of Maricopa Bonds and other bonds issued under the Maricopa Indenture which would be required for such correlative modification of such Maricopa Indenture or Loan Agreement. 10 ARTICLE II. REDEMPTION OF BONDS AND OTHER PROVISIONS The Bonds shall be redeemed, in whole or in part, from time to time, on the date on which a corresponding principal amount of Maricopa Bonds is redeemed as provided in the Maricopa Indenture, upon the Maricopa Trustee's notification of the Trustee of such redemption, at a redemption price equal to the redemption price of such Maricopa Bonds being so redeemed. Any such notice shall be received by the Trustee no later than 5 days prior to any redemption date fixed for the Bonds to be redeemed and shall specify the principal amount of such Bonds to be redeemed, the redemption date, and the amount of accrued interest to be paid thereon. The Company shall deposit in trust with the Trustee on the redemption date an amount of money sufficient to pay the principal amount plus accrued interest, if any, on the Bonds to be redeemed. Upon presentation to the Trustee of any Bonds by the Maricopa Trustee for payment under this Article II, such Bonds so presented shall be redeemed and paid in full to the extent so redeemed. In the event of redemption of the Bonds in part only, a new bond of the Sixty-first Series and of like tenor for the unredeemed portion thereof will be issued in the name of the Maricopa Trustee upon the cancellation of the then existing Bond. Redemption of the Bonds shall be effected, without further notice by the Company to the Trustee, by the payment by the Company of the applicable redemption price specified in this Article II at the place specified for payment of principal of and interest on such bonds. In the event the principal of all Maricopa Bonds is declared due and payable pursuant to the Maricopa Indenture, upon the filing with the Trustee of a written demand for the acceleration of the payment of principal of all Bonds, the payment of principal on all Bonds shall become immediately due and payable. The Bonds will not be subject to prepayment or redemption prior to maturity except as provided herein, notwithstanding the provisions of Section 39, Section 64 or Section 87 of the Mortgage, or with "Proceeds of Released Property," as defined in the Mortgage. The Company hereby covenants and agrees that until the Termination Date, it will not consolidate with or merge into any other corporation, or convey or transfer, subject to the Lien of the Indenture, all or substantially all of the Mortgaged and Pledged Property as an entirety. The Bonds will not be subject to any sinking fund. ARTICLE III. REPLACEMENT FUND PROVISIONS -- OTHER RELATED PROVISIONS OF THE MORTGAGE -- DIVIDEND COVENANT -- RECORD DATES -- AUTHENTICATING AGENT. SECTION 4. The Company covenants that the provisions of Section 39 of the Mortgage, which were to remain in effect so long as any bonds of the First Series remained Outstanding, shall remain in full force and effect so long as any bonds of the Sixty-first Series are Outstanding. Clause (d) of subsection (II) of Section 4 of the Mortgage, as heretofore amended, clause (6) and clause (e) of Section 5 of the Mortgage, as heretofore amended, and Section 29 of the Mortgage, as heretofore amended, are hereby further amended by inserting therein the words "and Sixty-first Series" after the words "bonds of the First Series and Second Series and Third Series and Fourth Series and Fifth Series and Sixth Series and Seventh Series and Eighth Series and Ninth Series and Tenth Series and Eleventh Series and Twelfth Series and Thirteenth Series and Fourteenth Series and Fifteenth Series and Sixteenth 11 Series and Seventeenth Series and Eighteenth Series and Nineteenth Series and Twentieth Series and Twenty-first Series and Twenty-second Series and Twenty-third Series and Twenty-fourth Series and Twenty- fifth Series and Twenty-sixth Series and Twenty-seventh Series and Twenty- eighth Series and Twenty-ninth Series and Thirtieth Series and Thirty-first Series and Thirty-second Series and Thirty-third Series and Thirty-fourth Series and Thirty-fifth Series and Thirty-sixth Series and Thirty-seventh Series and Thirty-eighth Series and Thirty-ninth Series and Fortieth Series and Forty-first Series and Forty-second Series and Forty-third Series and Forty-fourth Series and Forty-fifth Series and Forty-sixth Series and Forty- seventh Series and Forty-eighth Series and Forty-ninth Series and Fiftieth Series and Fifty-first Series and Fifty-second Series and Fifty-third Series and Fifty-fourth Series and Fifty-fifth Series and Fifty-sixth Series, and Fifty-seventh Series and Fifty-eighth Series and Fifty-ninth Series and Sixtieth Series" each time such words occur therein. Clause (e) of subsection (II) of Section 4 of the Mortgage, as heretofore amended, is hereby further amended by the insertion therein after the words "and Sixtieth" the words "and Sixty-first." The last paragraph of Section 12 of the Mortgage, as heretofore amended, the last paragraph of Section 17 of the Mortgage, as heretofore amended, and the last paragraph of Section 110 of the Mortgage, as heretofore amended, are hereby amended by inserting therein the words "or the Sixty-first Series" after the words "Sixtieth Series" each time such words occur therein. ARTICLE IV. MISCELLANEOUS PROVISIONS. SECTION 5. The terms defined in the Mortgage, as supplemented and amended, shall, for all purposes of this Fifty-seventh Supplemental Indenture, have the meanings specified therein, except that the term "Mortgage" shall mean only the original Mortgage and Deed of Trust, dated as of July 1, 1946; the term "Mortgage, as heretofore supplemented and amended" shall mean the Mortgage, as supplemented and amended by the First through Fifty-sixth Supplemental Indentures hereinabove referred to; and the term "Mortgage, as supplemented and amended," shall mean the Mortgage, as supplemented and amended by the First through Fifty-sixth Supplemental Indentures hereinabove referred to and as supplemented and amended by this Fifty-seventh Supplemental Indenture and any future supplemental indentures. SECTION 6. The Trustee hereby accepts the trusts herein declared, provided, created, supplemented or amended and agrees to perform the same upon the terms and conditions herein and in the Mortgage, as heretofore supplemented and amended, set forth and upon the following terms and conditions: The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Fifty-seventh Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general, each and every term and condition contained in Article XVII of the Mortgage shall apply to and form part of this Fifty-seventh Supplemental Indenture with the same force and effect as if the same were herein set forth in full with such omissions, variations and insertions, if any, as may be appropriate to make the same conform to the provisions of this Fifty-seventh Supplemental Indenture. SECTION 7. Whenever in this Fifty-seventh Supplemental Indenture either of the parties hereto is named or referred to, this shall, subject to the provisions of Articles XVI and XVII of the Mortgage, be deemed to include the successors and assigns of such party, and all the covenants and agreements in this Fifty-seventh Supplemental Indenture contained by or on behalf of the Company or by or on behalf of the Trustee shall, subject as aforesaid, bind and 12 inure to the respective benefits of the respective successors and assigns of such parties, whether so expressed or not. SECTION 8. Nothing in this Fifty-seventh Supplemental Indenture, expressed or implied, is intended or shall be construed to confer upon, or to give to, any person, firm or corporation, other than the parties hereto and the holders of the bonds Outstanding under the Mortgage, any right, remedy or claim under or by reason of this Fifty-seventh Supplemental Indenture or any covenant, condition, stipulation, promise or agreement hereof, and all the covenants, conditions, stipulations, promises and agreements in this Fifty-seventh Supplemental Indenture contained by or on behalf of the Company shall be for the sole and exclusive benefit of the parties hereto and of the holders of the bonds Outstanding under the Mortgage. SECTION 9. This Fifty-seventh Supplemental Indenture may be executed simultaneously in several counterparts, each of which shall be an original and all of which shall constitute but one and the same instrument. ARTICLE V. SPECIFIC DESCRIPTION OF PROPERTY. SECTION 10. CERTAIN REAL PROPERTY LOCATED IN: PINAL COUNTY ROBSON SUBSTATION That part of Section 17, Township 7 South, Range 7 East of the Gila and Salt River Base and Meridian, Pinal County, Arizona, lying North and East of the Arizona Highway 84 more particularly described as follows: Beginning at the Southeast corner of said Section 17; thence S 89(degree)40'35" W along the South line of said Section 17, a distance of 44.42 feet to a point; Thence N 0(degree)19'25" W a distance of 50 feet to a point; thence N 0(degree)04'32" E a distance of 73.39 feet to the true point of beginning of the parcel herein described; thence Northerly along a curve to the right, said curve having a central angle of 27(degree)47'59", and a radius of 290.00 feet, for a distance of 140.71 feet to a point; said point being the beginning of a curve to the left, said curve having a central angle of 28(degree)50'15", and a radius of 210.00 feet, for a distance of 105.70 feet to a point; thence N 0(degree)57'45" W a distance of 13.41 feet to a point; thence S 89(degree)40'35" W a distance of 309.17 feet to a point; thence S 0(degree)19'15" E a distance of 250.00 feet to a point; thence N 89(degree)40'35" E a distance of 250.00 feet to the true point of beginning. SECTION 11. THE ELECTRIC SUBSTATIONS OF THE COMPANY, including all buildings, structures, towers, poles, all equipment, appliances and devices for transforming, converting and distributing electric energy, and all land owned by the Company upon which the same are situated, and all of the Company's easements, rights of way, rights, machinery, equipment, appliances, devices, licenses and supplies forming a part of said substations, or any of them, including additions and improvements to any of the foregoing, or used or enjoyed or capable of being use or enjoyed in conjunction with any thereof. SECTION 12. Additions, extensions and improvements to THE ELECTRIC TRANSMISSION SYSTEMS of the Company. SECTION 13. Additions, extensions and improvements to THE ELECTRIC DISTRIBUTION SYSTEMS of the Company, including, the construction of additional facilities throughout the Company's service area, as well as extension of 13 residential and downtown underground distribution facilities, including associated distribution equipment such as voltage regulators, capacitor banks, sectionalizing equipment, transformers, street lighting systems, meters and services, including reconstruction and improvements to provide efficient Company operation. 14 IN WITNESS WHEREOF, ARIZONA PUBLIC SERVICE COMPANY, party hereto of the first part, has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by its President, one of its Vice Presidents, or its Treasurer, and its corporate seal to be attested by its Secretary or one of its Assistant Secretaries or Associate Secretaries for and in its behalf, in the City of Phoenix, Arizona, and THE BANK OF NEW YORK, party hereto of the second part, has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by one of its Vice Presidents or Assistant Vice Presidents and its corporate seal to be attested by one of its Assistant Vice Presidents or Assistant Treasurers for and in its behalf, in the City of West Paterson, New Jersey, all as of the 1st day of March, 2003. ARIZONA PUBLIC SERVICE COMPANY Barbara M. Gomez -------------------------------------- TREASURER Attest: Betsy A. Pregulman - -------------------------------------- ASSOCIATE SECRETARY Executed, sealed and delivered by ARIZONA PUBLIC SERVICE COMPANY in the presence of: Andrea Bernal - -------------------------------------- Andrea Bernal Norann Asciutto [SEAL] - -------------------------------------- Norann Asciutto THE BANK OF NEW YORK, As Trustee Thomas Vlahakis -------------------------------------- VICE PRESIDENT Attest: Thomas J. Provenzano - -------------------------------------- Thomas J. Provenzano, Vice President Executed, sealed and delivered by THE BANK OF NEW YORK in the presence of: Rosemary Melendez - -------------------------------------- Rosemary Melendez, Assistant Treasurer David J. O'Brien [SEAL] - -------------------------------------- David J. O'Brien, Vice President 15 STATE OF ARIZONA ) ) ss.: COUNTY OF MARICOPA ) On this 4th day of March, 2003, before me, Debra L. Blondin, the undersigned officer, personally appeared Barbara M. Gomez, who acknowledged herself to be the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, and that she, as such Treasurer being authorized so to do, executed the foregoing instrument for the purposes therein contained, by signing the name of the corporation by herself as Treasurer. IN WITNESS WHEREOF, I have hereunto set my hand and seal. Debra L. Blondin -------------------------------------- Notary Public My Commission Expires June 7, 2004 ---------------- [SEAL] STATE OF ARIZONA ) ) ss.: COUNTY OF MARICOPA ) On this 4th day of March, 2003, before me, Debra L. Blondin, the undersigned officer, personally came Barbara M. Gomez, to me known, who being by me duly sworn, did depose and say that she resides in Phoenix, Arizona, that she is the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, the corporation described in and which executed the above instrument; that she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by order of the Board of Directors of said corporation, and that she signed her name thereto by like order. IN WITNESS WHEREOF, I have hereunto set my hand and seal. Debra L. Blondin -------------------------------------- Notary Public My Commission Expires June 7, 2004 ---------------- [SEAL] STATE OF ARIZONA ) ) ss.: COUNTY OF MARICOPA ) This instrument was acknowledged before me on March 4, 2003 by Barbara M. Gomez and Betsy A. Pregulman, as Treasurer and Associate Secretary, respectively, of ARIZONA PUBLIC SERVICE COMPANY. Debra L. Blondin -------------------------------------- Notary Public My Commission Expires June 7, 2004 ---------------- [SEAL] 16 STATE OF NEW JERSEY ) ) ss.: COUNTY OF PASSAIC ) On this 5th day of March, 2003, before me, Ronald M. Mania, Notary Public in and for the County and State aforesaid, residing therein, duly commissioned and sworn, personally appeared Thomas Vlahakis, known to me to be a Vice President of THE BANK OF NEW YORK, a New York banking corporation, which executed the within instrument, and Thomas J. Provenzano, known to me to be a Vice President of The Bank of New York, who being by me duly sworn, acknowledged before me that the seal affixed to said instrument is the corporate seal of The Bank of New York, that they, being authorized so to do, executed the within instrument on behalf of The Bank of New York by authority of its board of directors, and that said instrument is the free act and deed of The Bank of New York for the purposes therein contained. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written. Ronald M. Mania -------------------------------------- Notary Public My Commission Expires 10/4/2006 ---------------- [SEAL] STATE OF NEW JERSEY ) ) ss.: COUNTY OF PASSAIC ) This instrument was acknowledged before me on March 5th, 2003 by Thomas Vlahakis and Thomas J. Provenzano, each as a Vice President of THE BANK OF NEW YORK. Ronald M. Mania -------------------------------------- Notary Public My Commission Expires 10/4/2006 ---------------- [SEAL] 17 EX-10.1A 6 ex10-1a.txt 2003 OFFICER VARIABLE INCENTIVE PLAN Exhibit 10.1a Under the 2003 Officers Variable Incentive Plan, the Chief Executive Officer, with the approval of the Human Resources Committee of the Pinnacle West Board of Directors, annually designates the officers who will participate in the program, establishes their participation level, and establishes certain financial and operational goals. The impact, if any, of each officer's performance on his or her variable pay award is determined by the Chief Executive Officer, with the approval by the Human Resources Committee. However, the calculation and the amount of payment, if any, under this Plan are in the sole discretion of the Human Resources Committee of the Board of Directors. Accordingly, achievement of financial and operational goals is just one method that may be utilized to measure performance. EX-10.2A 7 ex10-2a.txt 2003 CEO VARIABLE INCENTIVE PLAN Exhibit 10.2a Under the 2003 CEO Variable Incentive Plan, the Human Resources Committee of the Pinnacle West Board of Directors, annually establishes the participation level and establishes certain financial and operational goals. However, the calculation and the amount of payment, if any, under this Plan are in the sole discretion of the Human Resources Committee. Accordingly, achievement of financial and operational goals is just one method that may be utilized to measure performance. EX-10.3A 8 ex10-3a.txt SCHEDULES OF WJP & JED TO APS DEFERRED COMP PLAN Exhibit 10.3a 1986 Exhibit B EXECUTIVES' BENEFIT SUMMARY DOCUMENT FOR BILL POST Annual Retirement Total Retirement Age Year Date Benefit Benefit - --- ---- ---- ------- ------- 60 2010 2-15-10 $162,020 $1,620,200 61 2011 2-15-11 172,551 1,725,510 62 2012 2-15-12 183,767 1,837,670 63 2013 2-15-13 195,712 1,957,120 64 2014 2-15-14 208,433 2,084,330 65 2015 2-15-15 221,981 2,219,809 66 2016 2-15-16 236,410 2,364,100 1985 Exhibit B EXECUTIVES' BENEFIT SUMMARY DOCUMENT FOR JOHN DAVIS Annual Retirement Total Retirement Age Year Date Benefit Benefit - --- ---- ---- ------- ------- 60 2006 3-15-06 $ 57,583 $ 575,830 61 2007 3-15-07 61,326 613,260 62 2008 3-15-08 65,312 653,120 63 2009 3-15-09 69,558 695,580 64 2010 3-15-10 74,079 740,790 65 2011 3-15-11 78,894 788,940 1984 Exhibit B EXECUTIVES' BENEFIT SUMMARY DOCUMENT FOR JOHN E. DAVIS Annual Retirement Total Retirement Age Year Date Benefit Benefit - --- ---- ---- ------- ------- 60 2006 2-15-06 $ 94,454 $ 944,540 61 2007 2-15-07 100,594 1,005,940 62 2008 2-15-08 107,132 1,071,320 63 2009 2-15-09 114,096 1,140,960 64 2010 2-15-10 121,512 1,215,120 65 2011 2-15-11 129,410 1,294,100 EX-10.4A 9 ex10-4a.txt LETTER AGREEMENT DATED 6/28/01 - WHEELER Exhibit 10.4a [LETTERHEAD OF PINNACLE WEST CAPITAL CORPORATION] JACK DAVIS President June 28, 2001 Steve Wheeler One Arizona Center 400 East Van Buran Phoenix, AZ 85004-0001 Dear Steve, I'm delighted that you have made the decision to join Pinnacle West Capital Corporation (PNW) beginning June 29, 2001. This is an exciting and challenging time in the Company, and your experience will have a direct impact on our efforts. The information outlined below covers the major items we have discussed regarding our offer of employment. As you know, this offer is for the position of Senior Vice President of Transmission Operations, Regulation and Planning with an annual base salary of $275,000, effective your first day of employment. You will participate in the officer annual incentive program with a maximum opportunity equal to fifty-two percent of your annual base salary. Any incentive payout for 2001 results will be paid in full and not pro-rated. Incentive dollars are generally paid during the first quarter of the subsequent year. Within two weeks of your first day of employment you will also receive a $100,000 employment incentive, and three thousand shares of Pinnacle West stock. In addition to the base and incentive compensation referenced above, you will also receive a semi-monthly auto allowance totaling $7,440 per year. I have enclosed a summary of our employee benefits and a schedule showing the applicable premiums that are cost shared with our employees. Since you are not immediately eligible for PNW medical plan coverage, the premium cost of any external medical coverage you carry will be paid by the Company until your eligibility date. Further, enclosed is a description of our Employee Savings Plan in which you will be eligible to participate 31 days after employment. Please note that the Employee Savings Plan is a pre-tax savings plan. Also the premiums that apply to our medical and dental plans are on a pre-tax basis. Regarding pension, effective your first day of employment, you will be credited with ten years of vested service solely for the purpose of calculating future pension benefits. Additionally, you will receive two years of service for pension purposes in each of the first two years of employment. Thereafter you will receive pension crediting based on the pension policy applicable to officers. During 2001 you will be eligible for four weeks of vacation. For purposes of vacation accrual, you will be eligible for five weeks vacation after five years. Eligibility for all officer benefits not specifically mentioned above would be in accordance with the applicable policies and plan documents. Effective July 1, 2002 your base salary will increase to $300,000 and you will receive an additional three thousand shares of stock. This stock award will be in addition to any other officer stock distribution that may occur as determined by the PNW Board of Directors. This offer is contingent upon successful completion of employment prerequisites, which include a background check, physical exam and drug screen. On behalf of Pinnacle West Capital Corporation I'd like to welcome you to our team. In the event you have any questions, feel free to contact me or Armando Flores who will be coordinating the details of your employment. Sincerely, /s/ Jack Davis EX-10.5A 10 ex10-5a.txt 2002 LONG-TERM INCENTIVE PLAN Exhibit 10.5a PINNACLE WEST CAPITAL CORPORATION 2002 LONG-TERM INCENTIVE PLAN 1. OBJECTIVES. The Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan (the "Plan") is designed to attract, motivate and retain selected employees of the Company. These objectives are accomplished by making long-term incentive awards under the Plan, thereby providing Participants with a proprietary interest in the Company's growth and performance. 2. DEFINITIONS. (A) "AWARDS" -- The grant of any form of Stock Option, Performance Share, or Stock Ownership Incentive Award (whether granted singly, in combination or in tandem) to a Participant pursuant to such terms, conditions, performance requirements, limitations and restrictions as the Committee may establish in order to fulfill the objectives of the Plan. (B) "AWARD AGREEMENT" -- An agreement between PNW and a Participant that sets forth the terms, conditions, performance requirements, limitations and restrictions applicable to an Award. (C) "BOARD" -- The Board of Directors of Pinnacle West Capital Corporation ("PNW"). (D) "CAPITAL STOCK" OR "STOCK" -- PNW's common stock (no par value). (E) "CODE" -- The Internal Revenue Code of 1986, as amended from time to time. (F) "COMMITTEE" -- The Committee designated by the Board to administer the Plan and chosen from those of its members, each of whom qualify as: (i) a "Non-Employee Director" of PNW as defined in Rule 16b-3(b)(3) (or any successor provision) under the Securities Exchange Act of 1934 and (ii) an "outside director" under section 162(m) (or any successor provision) of the Code and the regulations thereunder. (G) "COMPANY" -- PNW or any of its subsidiaries (including subsidiaries of subsidiaries) or any other entity in which PNW or any of its subsidiaries has a significant equity or other interest, as determined by the Committee. (H) "FAIR MARKET VALUE" -- The closing price of Capital Stock on the New York Stock Exchange for the date in question provided that if no sales of Capital Stock were made on said exchange on that date, the closing price of Capital Stock as reported for the most recent preceding day on which sales of Capital Stock were made on said exchange. (I) "FISCAL YEAR" -- The Fiscal Year of PNW (may be changed from time to time). (J) "PARTICIPANT" -- An individual to whom an Award has been made under the Plan. Awards may be made to employees of PNW or any of its subsidiaries (including subsidiaries of subsidiaries) or any other 2002 Long-Term Incentive plan Page 2 entity in which PNW or any of its subsidiaries has a significant equity or other interest, as determined by the Committee. (K) "PERFORMANCE PERIOD" -- A period of one or more consecutive Fiscal Years over which one or more of the performance criteria listed in Section 5(d) shall be measured pursuant to the grant of Awards (whether such Awards take the form of Stock Options, Performance Share Awards or Stock Ownership Incentive Awards). Performance Periods may overlap one another. 3. CAPITAL STOCK AVAILABLE FOR AWARDS. Subject to adjustment pursuant to Section 12, the number of shares that may be issued under the Plan for Awards granted is six million (6,000,000). Shares of Capital Stock may be made available from the authorized but un-issued shares of PNW, from shares held in PNW's treasury and not reserved for some other purpose, or from shares purchased on the open market. For purposes of determining the number of shares of Capital Stock issued under the Plan, no shares shall be deemed issued until they are actually delivered to a Participant, or such other person in accordance with Section 9. Shares covered by Awards, that either wholly or in part are not earned or that expire or are forfeited, terminated, canceled, or exchanged or other Awards, shall be available for future issuance under Awards. Further, shares tendered to PNW in connection with the exercise of Stock Options, or withheld by PNW for the payment of tax withholding on any Award, shall also be available for future issuance under Awards. 4. ADMINISTRATION. The Plan shall be administered by the Committee, which shall have full power to select Participants, interpret the Plan and adopt such rules, regulations and guidelines for carrying out the Plan as it may deem necessary or proper. A majority of the Committee shall constitute a quorum. The acts of a majority of the members present at any meeting at which a quorum is present and acts approved in writing by a majority of the Committee in lieu of a meeting shall be deemed acts of the Committee. Each member of the Committee is entitled to rely in good faith upon any report or other information furnished to that member by any officer or other employee of PNW, any subsidiary, PNW's certified public accountants, any executive compensation consultant or other professional retained by PNW to assist in the administration of the Plan. 5. AWARDS. The Committee shall determine the type(s) of Award(s) to be made to each Participant and shall set forth in the related Award Agreement the terms, conditions, performance requirements, limitations and restrictions applicable to each Award. Awards may be granted singly, in combination or in tandem. Awards may also be made in combination or in tandem with, in replacement or payment of, or as alternatives to, grants, rights or compensation earned under any other Plan of the Company, including the Plan of any acquired entity. (A) STOCK OPTION -- A Stock Option is a grant of a right to purchase a specified number of shares of Capital Stock. The exercise price of said Grant shall be not less than 100% of Fair Market Value on the date of Grant of such right. No individual may be granted Options to purchase more than 600,000 shares during any Fiscal Year. No Stock 2 2002 Long-Term Incentive plan Page 3 Option shall have a term of more than ten (10) years. No Stock Option may be repriced during its term. All Stock Options shall be non-qualified Stock Options. (B) PERFORMANCE SHARE AWARD -- A Performance Share Award is an Award denominated in units of stock. The maximum number of shares of Capital Stock that may be issued under Performance Share Awards and Stock Ownership Incentive Awards shall not exceed 1,800,000. Performance Share Awards will provide for the payment of stock if performance goals are achieved over specified Performance Periods. The maximum possible Performance Share Grant to any single Participant is 120,000 units in any Fiscal Year. (C) STOCK OWNERSHIP INCENTIVE AWARD -- A Stock Ownership Incentive Award is an award of stock if certain performance goals and stock ownership requirements are achieved. The maximum possible Stock Ownership Incentive Award, which may be made to any single Participant in any Fiscal Year, is 15,000 shares. (D) PERFORMANCE CRITERIA UNDER SECTION 162(M) OF THE CODE FOR PERFORMANCE SHARE AWARDS, AND STOCK OWNERSHIP INCENTIVE AWARDS -- The performance criteria for Performance Share Awards, and Stock Ownership Incentive Awards made to any "covered employee" (as defined in section 162(m) of the Code), and which are intended to qualify as "performance-based compensation" (as defined in section 162(m) of the Code), shall consist of objective tests based on one or more of the following: PNW's earnings per share growth compared to a comparative group of S&P Electric Utilities; earnings; cash flow; customer satisfaction; revenues; financial return ratios; market performance; shareholder return and/or value; operating profits (including earnings before income taxes, depreciation and amortization); net profits; earnings per share; earnings per share growth; profit returns and margins; stock price; working capital; business trends; production cost; project milestones; and plant and equipment performance, as well as one or more of the following operational measures: safety, environment and minimizing customer price per kilowatt-hour. Performance criteria may be measured solely on a corporate, subsidiary or business unit basis or a combination thereof. Satisfaction of Stock Ownership guidelines may also be a prerequisite to payment. (E) DETERMINATIONS OF COMMITTEE -- Nothing herein shall preclude the Committee from making any payments or granting any Awards whether or not such payments or Awards qualify for tax deductibility under section 162(m) of the Code. No payments are to be made to a Participant if the applicable performance criteria are not achieved for a given Performance Period. If the applicable performance criteria are achieved for a given Performance Period, the Committee has full discretion to reduce or eliminate the amount otherwise payable for that Performance Period. Under no circumstances may the Committee use discretion to increase the amount payable to a Participant under a Performance Share Award, or a Stock Ownership Incentive Award. 6. PAYMENT OF AWARDS. Payment of Awards shall be made in the form Stock and may include such restrictions as the Committee shall determine. Dividends or dividend equivalent rights may be extended to and made part of any Award denominated in Stock or units of Stock, subject to such terms, conditions and restrictions as the Committee may establish. At the discretion of the 3 2002 Long-Term Incentive plan Page 4 Committee, a Participant may be offered an election to substitute an Award for another Award (or Awards) of the same or different type. 7. STOCK OPTION EXERCISE. The price at which shares of Capital Stock may be purchased under a Stock Option shall be paid in full in cash at the time of the exercise or, if permitted by the Committee, by means of tendering Capital Stock or surrendering another Award or any combination thereof. The Committee shall determine acceptable methods of tendering Capital Stock or other Awards and may impose such conditions on the use of Capital Stock or other Awards to exercise a Stock Option, as it deems appropriate. In addition, the Optionee may effect a "cashless exercise" of a Stock Option in which the option shares are sold through a broker and a portion of the proceeds, to cover the exercise price, is paid to PNW or otherwise in accordance with the rules and procedures adopted by the Committee. 8. TAX WITHHOLDING. Prior to the payment or settlement of any Award, the Participant must pay, or make arrangements acceptable to PNW for the payment of, any and all federal, state and local tax withholding that in the opinion of PNW is required by law. PNW shall have the right to deduct applicable taxes from any Award payment and withhold (at the time of delivery or vesting of shares of Stock under the Plan) an appropriate number of shares for payment of taxes required by law or to take such other action as may be necessary in the opinion of PNW to satisfy all obligations for withholding of such taxes. 9. TRANSFERABILITY. No Award shall be transferable, assignable, payable to, or exercisable by anyone other than the Participant to whom it was granted, except: (a) by will or the laws of descent and distribution; or (b) that the Committee (in the form of an Award Agreement or otherwise) may permit transfers of Awards by gift or otherwise to a member of a Participant's immediate family and/or trusts whose beneficiaries are members of the Participant's immediate family, or to such other persons or entities as may be approved by the Committee. 10. AMENDMENT, MODIFICATION, SUSPENSION OR TERMINATION OF THE PLAN. The Board may amend, modify, suspend or terminate the Plan for the purpose of meeting or addressing any changes in law or other legal requirements or for any other purpose permitted by law; provided, however, that no such amendment, modification, suspension or termination of the Plan shall adversely affect in any material way any Award previously granted under the Plan, without the written consent of the Participant. Subject to changes in law or other legal requirements that would permit otherwise, the Plan may not be amended without the approval of the shareholders of PNW, to: (a) increase the aggregate number of shares of Capital Stock that may be issued under the Plan (except for adjustments pursuant to Section 12); (b) permit the granting of Stock Options with exercise prices lower than those specified in Section 5(a); (c) modify the Plan's eligibility requirements, or (d) change the performance criteria applicable to Covered Employees. 4 2002 Long-Term Incentive plan Page 5 11. TERMINATION OF EMPLOYMENT. If the employment of a Participant terminates, the status of the Award shall be as set forth in the Award Agreement, provided that if a Participant is covered by a Key Executive Employment and Severance Agreement ("KEESA"), which entitles the Participant's termination to be treated as a "Normal Termination", if such termination occurs within two years following a Change of Control (as defined in such KEESA), the Award Agreement shall give such Participant at least those rights provided for in such KEESA. 12. ADJUSTMENTS. In the event of any change in the outstanding Capital Stock of PNW by reason of a stock split, stock dividend, combination or reclassification of shares, recapitalization, merger, or similar event, the Committee shall adjust appropriately: (a) the number of shares of Capital Stock: (i) available for issuance under the Plan; (ii) for which Awards may be granted to an individual Participant set forth in Section 5 and (iii) covered by outstanding Awards denominated in stock or units of stock; (b) the exercise and grant prices related to outstanding Awards, and (c) the appropriate Fair Market Value and other price determinations for such Awards. In the event of any other change affecting the Capital Stock or any distribution (other than normal cash dividends) to holders of Capital Stock such adjustments shall be made in the number and kind of shares and the exercise, grant and conversion prices of the affected Awards (including adjustments to avoid fractional shares) to give proper effect to such event as may be deemed equitable by the Committee. In the event of a corporate merger, consolidation, acquisition of property or stock, separation, reorganization or liquidation, the Committee shall be authorized to cause PNW to issue or assume Stock Options, whether or not in a transaction to which section 424(a) of the Code applies, by means of substitution of new Stock Options for previously issued Stock Options or an assumption of previously issued Stock Options. In such event, the aggregate number of shares of Capital Stock available for issuance under Awards under Section 3, including the individual Participant maximums set forth in Section 5, will be adjusted to reflect such substitution or assumption. 13. MISCELLANEOUS. (A) Any notice to PNW required by any of the provisions of the Plan shall be addressed to the senior human resources officer of PNW in writing and shall become effective when it is received. (B) The Plan shall be unfunded and the Company shall not be required to establish any special account or fund or to otherwise segregate or encumber assets to ensure payment of any Award. (C) Nothing contained in the Plan shall prevent the Company from adopting other or additional compensation arrangements or plans, subject to shareholder approval (if such approval is required) and such arrangements or plans may be either generally applicable or applicable only in specific cases. (D) No Participant shall have any claim or right to be granted an Award under the Plan and nothing contained in the Plan shall be deemed or construed to give any Participant the right to be retained in the employ of the Company or to interfere with the right of the Company to discharge any Participant at any time without regard to the effect such discharge may have upon the Participant under the Plan. Except to the extent otherwise provided in any plan or in an Award Agreement, no 5 2002 Long-Term Incentive plan Page 6 Award under the Plan shall be deemed compensation for purposes of computing benefits or contributions under any other plan of the Company. (E) The Plan and each Award Agreement shall be governed by the laws of the State of Arizona, excluding any conflicts or choice of law rule or principle that might otherwise refer construction or interpretation of the Plan to the substantive law of another jurisdiction. Unless otherwise provided in the Award Agreement recipients of an Award under the Plan are deemed to submit to the exclusive jurisdiction and venue of the federal or state courts of Arizona, County of Maricopa to resolve any and all issues that may arise out of or relate to the Plan or any related Award Agreement. (F) The Committee shall have full power and authority to interpret the Plan and to make any determinations thereunder. The Committee's determinations shall be binding and conclusive. Determinations made by the Committee under the Plan need not be uniform and may be made selectively among individuals, whether or not such individuals are similarly situated. (G) If any provision of the Plan is, or becomes, or is deemed invalid, illegal or unenforceable in any jurisdiction, or would disqualify the Plan or any Award under any law deemed applicable by the Committee, such provision shall be construed or deemed amended or limited in scope to conform to applicable laws or, in the discretion of the Committee, it shall be stricken and the remainder of the Plan shall remain in full force and effect. (H) The Plan, as adopted by the Board on March 20, 2002, is subject to approval of the stockholders of PNW within 12 months of the date it was adopted. Awards may be granted prior to such approval but no such Award may be exercised, vested or settled prior to such approval. If such approval is not obtained, any such Award shall be void ab initio and of no force or effect. If such approval is obtained, no further Awards shall be granted under the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan other than Awards providing for the issuance of up to 20,000 shares of Stock to be used under such plan to satisfy PNW's obligations to make Stock Awards to certain executives. (I) Subject to earlier termination, pursuant to Section 10, the Plan will terminate on March 19, 2012. Awards outstanding at the termination of the Plan will not be affected by such termination. 6 EX-12.1 11 ex12-1.txt COMPUTATION OF EARNINGS TO FIXED CHARGES Exhibit 12.1 PINNACLE WEST CAPITAL CORPORATION Computation of Earnings to Fixed Charges ($000's)
2002 2001 2000 1999 1998 --------- --------- --------- --------- --------- Income From Continuing Operations $ 215,153 $ 327,367 $ 302,332 $ 269,772 $ 242,892 Income Taxes 138,100 213,535 194,200 141,592 138,589 Fixed Charges 220,492 211,958 202,804 194,070 201,184 --------- --------- --------- --------- --------- Total 573,745 752,860 699,336 605,434 582,665 Fixed Charges: Interest Expense 188,353 175,822 166,447 157,142 163,975 Estimated Interest Portion of Annual Rents 32,139 36,136 36,357 36,928 37,209 --------- --------- --------- --------- --------- Total Fixed Charges 220,492 211,958 202,804 194,070 201,184 Ratio of Earnings to Fixed Charges (rounded down) 2.60 3.55 3.44 3.11 2.89 ========= ========= ========= ========= =========
EX-21.1 12 ex21-1.txt SUBSIDIARIES OF THE COMPANY Exhibit 21.1 SUBSIDIARIES OF PINNACLE WEST CAPITAL CORPORATION Arizona Public Service Company State of Incorporation: Arizona Axiom Power Solutions, Inc. State of Incorporation: Arizona Bixco, Inc. State of Incorporation: Arizona PWENewco, Inc. State of Incorporation: Arizona APS Energy Services Company, Inc. State of Incorporation: Arizona Tucson District LLC State of Incorporation: Arizona SunCor Development Company State of Incorporation: Arizona SunCor Golf, Inc. State of Incorporation: Arizona Golden Heritage Homes, Inc. State of Incorporation: Arizona Golden Heritage Construction, Inc. State of Incorporation: Arizona SCM, Inc. State of Incorporation: Arizona Golf de Mexico, S.A. DE C.V. Incorporation: Tijuana, Baja California, Mexico SunCor Realty & Management Company State of Incorporation: Arizona Palm Valley Golf Club, Inc. State of Incorporation: Arizona Rancho Viejo de Santa Fe, Inc. State of Incorporation: New Mexico Ranchland Utility Company State of Incorporation: New Mexico El Dorado Investment Company State of Incorporation: Arizona El Dorado Ventures State of Incorporation: Arizona NAC Holding, Inc. State of Incorporation: Delaware Pinnacle West Energy Corporation State of Incorporation: Arizona GenWest, LLC State of Incorporation: Delaware SunCor Realty & Management Company State of Incorporation: Arizona Hidden Hills of Scottsdale LLC State of Incorporation: Arizona EX-23.1 13 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. 33-15190, 333-52476, 333-101457 and 333-53150 on Form S-3; Registration Statement Nos. 33-47534, 333-40796, 33-54307, 333-95035, 333-91786 and 33-1720 on Form S-8; and Registration Statement No. 2-96386 on Form S-14, all of Pinnacle West Capital Corporation, of our report dated February 3, 2003 (March 4, 14, 26 and 27, 2003 as to Note 24) (which report expresses an unqualified opinion and includes explanatory paragraphs relating to the change in 2002 in the method of accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue No. 02-3, ISSUES INVOLVED IN ACCOUNTING FOR DERIVATIVE CONTRACTS HELD FOR TRADING PURPOSES AND CONTRACTS INVOLVED IN ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES, and 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 Pinnacle West Capital Corporation for the year ended December 31, 2002. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona March 27, 2003 EX-99.1 14 ex99-1.txt CERTIFICATION OF WILLIAM J. POST Exhibit 99.1 FORM OF CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (WILLIAM J. POST) I, William J. Post, the Chairman of the Board and Chief Executive Officer of Pinnacle West Capital Corporation ("Pinnacle West"), certify, to the best of my knowledge, that: (a) the attached Annual Report on Form 10-K of Pinnacle West 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 Pinnacle West. William J. Post ---------------------------------------- William J. Post Chairman of the Board and Chief Executive Officer Date: March 31, 2003 EX-99.2 15 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 Pinnacle West Capital Corporation ("Pinnacle West"), certify, to the best of my knowledge, that: (a) the attached Annual Report on Form 10-K of Pinnacle West 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 Pinnacle West. Donald E. Brandt ---------------------------------------- Donald E. Brandt Senior Vice President and Chief Financial Officer Date: March 31, 2003 EX-99.3 16 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 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 APS and various parties, APS was required to transfer all of its 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 APS to cancel any plans to divest interests in any of its generating assets. The ACC has further established a requirement that APS 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 APS' service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS' customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS' service territory. As 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 APS WITHOUT THE ABILITY TO ADJUST RETAIL RATES COULD HAVE AN ADVERSE IMPACT ON OUR BUSINESS AND FINANCIAL RESULTS. A 1999 settlement agreement limits APS' 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 APS' current bundled retail rates. Under the ACC's rules, APS is 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 APS 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 APS' 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 APS' current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supplemental power in the wholesale spot market. The ACC has further established a requirement that APS 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 APS' procurement of wholesale power. In sum, there can be no assurance that APS would be able to fully recover the costs of wholesale power under its present rate structure. Although APS could seek to adjust its 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, directly and through our subsidiaries, subject to governmental regulation which may have a negative impact on our business and results of operations. We are 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 our filing of an annual exemption statement with the SEC. APS is subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence its operating environment and may affect its ability to recover costs from utility customers. APS is required to have numerous permits, approvals and certificates from the agencies that regulate APS' 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 APS can charge customers. We believe the 3 necessary permits, approvals and certificates have been obtained for APS' existing operations. However, we are unable to predict the impact on our business and operating results from the future regulatory activities of any of 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. Through APS, 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 4 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. 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 5 maintain short-term reliability. On October 16, 2001, APS 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. 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 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 APS' customers, could have a material adverse effect on our results of operations. THE MARKET PRICE OF OUR COMMON STOCK MAY BE VOLATILE. The market price of our common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond our control: * variations in our quarterly operating results; * operating results that vary from the expectations of management, securities analysts and investors; * changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors; 6 * developments generally affecting industries in which we operate, particularly the energy distribution and energy generation industries; * announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments; * announcements by third parties of significant claims or proceedings against us; * favorable or adverse regulatory developments; * our dividend policy; * future sales of our equity or equity-linked securities; and * general domestic and international economic conditions. In addition, the stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of our common stock. OUR STOCK PRICE COULD BE AFFECTED BECAUSE A SUBSTANTIAL NUMBER OF SHARES OF OUR COMMON STOCK COULD BE AVAILABLE FOR SALE IN THE FUTURE. Sales in the public market of a substantial number of shares of common stock could depress the market price of the common stock and could impair our ability to raise capital through the sale of additional equity securities. Because of the number of shares of our common stock that we are authorized to issue under our articles of incorporation, a substantial number of shares of our common stock could be available for future sale. OUR CASH FLOW AND ABILITY TO PAY DIVIDENDS LARGELY DEPENDS ON THE PERFORMANCE OF OUR SUBSIDIARIES. We conduct our operations primarily through subsidiaries. Substantially all of our consolidated assets are held by such subsidiaries. Accordingly, our cash flow and our ability to pay dividends on our capital stock are largely dependent upon the earnings of these subsidiaries and the distribution or other payment of such earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. The subsidiaries are separate and distinct legal entities and have no obligation to pay dividends or to make any funds available for such payment. The debt agreements of some of our subsidiaries may restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. Section 39(III) of APS' mortgage requires APS to meet a financial covenant before paying common stock dividends. Under this covenant, APS may pay dividends on its common 7 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 APS to pay approximately $3 billion of dividends compared to APS' current annual common stock dividends of $170 million. As part of the ACC's approval of a $500 million financing arrangement between APS and Pinnacle West Energy, the ACC required APS to maintain a common equity ratio of at least forty percent and prohibited APS from paying common stock dividends if such payment would reduce its common equity below that threshold. WE HAVE AND MAY ENTER INTO CREDIT AND OTHER AGREEMENTS FROM TIME TO TIME THAT RESTRICT OUR ABILITY TO PAY DIVIDENDS. Payment of dividends on the common stock may be restricted by loan agreements, indentures and other transactions entered into by us from time to time. As of March 28, 2003, one of our loan agreements restricts our ability to pay dividends to dividends paid on our capital stock in the ordinary course and consistent with past practice (including increases in such dividends consistent with past practices). However, if an event of default exists under that agreement, we would be prohibited from paying any dividends while the event of default continues. 8 -----END PRIVACY-ENHANCED MESSAGE-----