-----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, D6j4mj9u0PNhQon+rkxusJLYm7BcXNx03w2WDPrYBHCKGfxNr9rzX+m5t6J4OKKn MzYxDa9f3lyOfUDsm8GWOw== 0000950147-99-000288.txt : 19990402 0000950147-99-000288.hdr.sgml : 19990402 ACCESSION NUMBER: 0000950147-99-000288 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARIZONA PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000007286 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 860011170 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-04473 FILM NUMBER: 99579602 BUSINESS ADDRESS: STREET 1: 400 N FIFTH ST STREET 2: P O BOX 53999 CITY: PHOENIX STATE: AZ ZIP: 85004 BUSINESS PHONE: 6022501000 10-K405 1 ANNUAL REPORT FOR THE YEAR ENDED 12/31/98 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, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to ______ Commission File Number 1-4473 ARIZONA PUBLIC SERVICE COMPANY (Exact name of registrant as specified in its charter) ARIZONA 86-0011170 (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (Address of principal executive (602) 250-1000 offices, (Registrant's telephone number, including zip code) including area code) - -------------------------------------------------------------------------------- Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered - -------------------------------------------------------------------------------- 10% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025............... New York 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 any amendment to this Form 10-K. [X] As of March 30, 1999, there were issued and outstanding 71,264,947 shares of the registrant's common stock, $2.50 par value, all of which were held beneficially and of record by Pinnacle West Capital Corporation. THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I1(A) AND (B) AND IS THEREFORE FILING THIS DOCUMENT WITH THE REDUCED DISCLOSURE FORMAT. TABLE OF CONTENTS Page ---- GLOSSARY.................................................................. 1 PART I Item 1. Business.................................................... 3 Item 2. Properties.................................................. 12 Item 3. Legal Proceedings........................................... 15 Item 4. Submission of Matters to a Vote of Security Holders......... 15 Supplemental Item. Executive Officers of the Registrant........................ 16 PART II Item 5. Market for Registrant's Common Stock and Related Security Holder Matters..................................... 18 Item 6. Selected Financial Data..................................... 19 Item 7. Financial Review............................................ 20 Item 7A Quantitative and Qualitative Disclosures about Market Risk................................................. 27 Item 8. Financial Statements and Supplementary Data................. 28 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure......................... 58 PART III Item 10. Directors and Executive Officers of the Registrant.......... 58 Item 11. Executive Compensation...................................... 58 Item 12. Security Ownership of Certain Beneficial Owners and Management.................................................. 58 Item 13. Certain Relationships and Related Transactions.............. 58 PART IV Item 14. Exhibits, Financial Statements, Financial Statement Schedules, and Reports on Form 8-K.......................... 59 SIGNATURES................................................................ 80 i GLOSSARY ACC -- Arizona Corporation Commission ACC STAFF -- Staff of the Arizona Corporation Commission AFUDC -- Allowance for Funds Used During Construction AMENDMENTS -- Clean Air Act Amendments of 1990 ANPP -- Arizona Nuclear Power Project, also known as Palo Verde APS -- Arizona Public Service Company CC&N -- Certificate of convenience and necessity CHOLLA -- Cholla Power Plant CHOLLA 4 -- Unit 4 of the Cholla Power Plant COMPANY -- Arizona Public Service Company CUC -- Citizens Utilities Company DOE -- United States Department of Energy EITF -- Emerging Issues Task Force EITF 97-4 -- Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Applications of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises -- Accounting for the Discontinuation of Application of FASB Statement No. 71" EITF 98-10 -- Emerging Issues Task Force Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" ENERGY ACT -- National Energy Policy Act of 1992 EPA -- United States Environmental Protection Agency FASB -- Financial Accounting Standards Board FERC -- Federal Energy Regulatory Commission FOUR CORNERS -- Four Corners Power Plant GAAP -- Generally accepted accounting principles ITC -- Investment tax credit KW -- Kilowatt, one thousand watts KWH -- Kilowatt-hour, one thousand watts per hour MORTGAGE -- Mortgage and Deed of Trust, dated as of July 1, 1946, as supplemented and amended MW -- Megawatt, one million watts MWH -- Megawatt hours, one million watts per hour 1935 ACT -- Public Utility Holding Company Act of 1935 NGS -- Navajo Generating Station NRC -- Nuclear Regulatory Commission PACIFICORP -- An Oregon-based utility company PALO VERDE -- Palo Verde Nuclear Generating Station PINNACLE WEST -- Pinnacle West Capital Corporation, an Arizona corporation, the Company's parent SEC -- Securities and Exchange Commission SFAS NO. 34 -- Statement of Financial Accounting Standards No. 34, "Capitalization of Interest Cost" 1 SFAS NO. 71 -- Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS NO. 123 -- Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" SFAS NO. 130 -- Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" SFAS NO. 133 -- Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" SALT RIVER PROJECT -- Salt River Project Agricultural Improvement and Power District USEC -- United States Enrichment Corporation WASTE ACT -- Nuclear Waste Policy Act of 1982, as amended 2 PART I ITEM 1. BUSINESS THE COMPANY We were incorporated in 1920 under the laws of Arizona and are engaged principally in serving electricity in the State of Arizona. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). Pinnacle West owns all of the outstanding shares of our common stock. We are Arizona's largest electric utility, with 799,000 customers. We provide wholesale or retail electric service to the entire state of Arizona, with the exception of Tucson and about one-half of the Phoenix area. During 1998, no single purchaser or user of energy accounted for more than 2% of total electric revenues. At December 31, 1998, we employed 6,075 people, which includes employees assigned to joint projects where we are project manager. This document contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax, and environmental legislation; our ability to successfully compete outside our traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; and Year 2000 issues. See "Competition" in this Item for a discussion of some of these factors. COMPETITION RETAIL GENERAL. Under current law, we are not in direct competition with any other regulated electric utility for electric service in our retail service territory. Nevertheless, we are subject to varying degrees of competition in certain territories adjacent to or within areas that we serve that are also currently served by other utilities in our region (such as Tucson Electric Power Company, Southwest Gas Corporation, and Citizens Utility Company) as well as cooperatives, municipalities, electrical districts, and similar types of governmental organizations (principally Salt River Project). We face competitive challenges from low-cost hydroelectric power and natural gas fuel, as well as the access of some utilities to preferential low-priced federal power and other subsidies. In addition, some customers, particularly industrial and large commercial, may own and operate facilities to generate their own electric energy requirements. Such facilities may be operated by the customers themselves or by other entities engaged for such purpose. ARIZONA ELECTRIC INDUSTRY RESTRUCTURING. See Note 3 of Notes to Financial Statements in Item 8 for a discussion of the electric industry restructuring in Arizona, including ACC rules for the introduction of retail electric competition; stranded cost recovery; and Arizona legislative initiatives. See also "Financial Review - Competition and Industry Restructuring" in Item 7. WHOLESALE GENERAL. We compete with other utilities, power marketers, and independent power producers in the sale of electric capacity and energy in the wholesale market. We expect that competition to sell capacity will remain 3 vigorous. Our rates for wholesale power sales and transmission services are subject to regulation by the FERC. During 1998, approximately 16% of our electric operating revenues resulted from such sales and charges. The National Energy Policy Act of 1992 (the "Energy Act") has promoted increased competition in the wholesale electric power markets. The Energy Act reformed provisions of the Public Utility Holding Company Act of 1935 (the "1935 Act") and the Federal Power Act to remove certain barriers to competition for the supply of electricity. For example, the Energy Act permits the FERC to order transmission access for third parties to transmission facilities owned by another entity so that independent suppliers and other third parties can sell at wholesale to customers wherever located. The Energy Act does not, however, permit the FERC to issue an order requiring transmission access to retail customers. Effective July 9, 1996, a FERC decision requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with access to transmission facilities comparable to the transmission owners' access for wholesale transactions, establishes information requirements, and provides for recovery of certain wholesale stranded costs. Retail stranded costs resulting from a state-authorized retail direct-access program are the responsibility of the states, unless a state lacks authority to impose rates to recover such costs, in which case FERC will consider doing so. We have filed a revised open access tariff in accordance with this decision. We do not believe that this decision will have a material adverse impact on our results of operations or financial position. REGULATORY ASSETS Our major regulatory assets are deferred income taxes and rate synchronization cost deferrals. These items, combined with miscellaneous regulatory assets and liabilities, amounted to approximately $900 million at December 31, 1998. Under a 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that will end June 30, 2004. Our existing regulatory orders and the current regulatory environment support our accounting practices related to regulatory assets. If rate recovery of these assets is no longer probable, whether due to competition or regulatory action, we would be required to write off the remaining balance as an extraordinary charge to expense. This could have a material impact on our financial statements. See Notes 1, 3, and 10 of Notes to Financial Statements in Item 8 for additional information. COMPETITIVE STRATEGIES We are pursuing strategies to maintain and enhance our competitive position. These strategies include (i) cost management, with an emphasis on the reduction of variable costs (fuel, operations, and maintenance expenses) and on increased productivity through technological efficiencies; (ii) a focus on our core business through customer service, distribution system reliability, business segmentation, and the anticipation of market opportunities; (iii) an emphasis on good regulatory relationships; (iv) asset maximization (e.g., higher capacity factors and lower forced outage rates); (v) expanding our generation asset base to support growth in the competitive power marketing arena; (vi) strengthening our capital structure and financial condition; (vii) leveraging core competencies into related areas, such as energy management products and services; and (viii) establishing a trading floor and implementing a risk management program to provide for more stability of prices and the ability to retain or grow incremental margin through more competitive pricing and risk management. Underpinning our competitive strategies are the strong growth characteristics of our service territory. As competition in the electric utility industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete effectively in a more competitive, restructured industry. 4 GENERATING FUEL AND PURCHASED POWER 1998 ENERGY MIX Our sources of energy during 1998 were: coal - 36.2%; nuclear - 27.5%; purchased power - 32.3%; and other - 4.0%. COAL SUPPLY We believe that Cholla has sufficient reserves of low sulfur coal committed to the plant through 2005. In 1998, the current supplier agreed to allow Cholla to test burn coal from other sources, which led to coal purchases on the spot market. The current supplier is expected to continue to provide substantially all of Cholla's low sulfur coal requirements. We believe there are sufficient reserves of low sulfur coal available to allow the continued operation of Cholla for its useful life. We also believe that Four Corners and NGS have sufficient reserves of low sulfur coal available for use by those plants to continue operating them for their useful lives. The current sulfur content of coal being used at Four Corners, NGS, and Cholla is approximately 0.77%, 0.54%, and 0.44%, respectively. In 1998, average prices paid for coal supplied from the reserves dedicated under existing contracts were slightly lower, but still comparable to 1997. Escalation components of existing long-term coal contracts impact future coal prices. In addition, major price adjustments can occur from time to time as a result of contract renegotiation. NGS and Four Corners are located on the Navajo Reservation and held under easements granted by the federal government as well as leases from the Navajo Nation. See "Properties- Plant Sites Leased from the Navajo Nation" in Item 2. We purchase all of the coal which fuels Four Corners from a coal supplier with a long-term lease of coal reserves owned by the Navajo Nation and for NGS from a coal supplier with a long-term lease with the Navajo Nation and the Hopi Tribe. Coal is supplied to Cholla from a coal supplier who mines all of the coal under a long-term lease of coal reserves owned by the Navajo Nation, the federal government, and private landholders. See Note 12 of Notes to Financial Statements in Item 8 for information regarding our obligation for coal mine reclamation. NATURAL GAS SUPPLY We are a party to contracts with a number of natural gas operators and marketers which allow us to purchase natural gas in the method we determine to be most economic. Currently, we are purchasing the majority of our natural gas requirements from 25 companies pursuant to contracts. Our natural gas supply is transported pursuant to a firm transportation service contract with El Paso Natural Gas Company. We continue to analyze the market to determine the most favorable source and method of meeting our natural gas requirements. NUCLEAR FUEL SUPPLY The fuel cycle for Palo Verde is comprised of the following stages: + the mining and milling of uranium ore to produce uranium concentrates, + the conversion of uranium concentrates to uranium hexafluoride, + the enrichment of uranium hexafluoride, + the fabrication of fuel assemblies, + the utilization of fuel assemblies in reactors and + the storage of spent fuel and the disposal thereof. The Palo Verde participants have made contractual arrangements to obtain quantities of uranium concentrates anticipated to be sufficient to meet operational requirements through 2001. Existing contracts and options could be utilized to meet approximately 93% of requirements in 2002, 62% of requirements in 2003, 51% of requirements 5 in 2004, and 44% of requirements from 2005 through 2007. Spot purchases on the uranium market will be made, as appropriate, in lieu of any uranium that might be obtained through contractual options. The Palo Verde participants have contracted for 85% of conversion services required through 2002. The Palo Verde participants have an enrichment services contract and an enriched uranium product contract that furnish enrichment services required for the operation of the three Palo Verde units through 2003. In addition, existing contracts will provide fuel assembly fabrication services until at least 2003 for each Palo Verde unit, and through contract options, approximately fifteen additional years are available. SPENT NUCLEAR FUEL AND WASTE DISPOSAL. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "Waste Act"), DOE is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. The NRC, pursuant to the Waste Act, requires operators of nuclear power reactors to enter into spent fuel disposal contracts with DOE. We have done so on our behalf and on behalf of the other Palo Verde participants. Under the Waste Act, DOE was to develop the facilities necessary for the storage and disposal of spent nuclear fuel and to have the first such facility in operation by 1998. That facility was to be a permanent repository. DOE has announced that such a repository now cannot be completed before 2010. In July 1996, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) ruled that the DOE has an obligation to start disposing of spent nuclear fuel no later than January 31, 1998. By way of letter dated December 17, 1996, DOE informed us and other contract holders that DOE anticipates that it will be unable to begin acceptance of spent nuclear fuel for disposal in a repository or interim storage facility by January 31, 1998. In November 1997, the D.C. Circuit issued a Writ of Mandamus precluding DOE from excusing its own delay on the grounds that DOE has not yet prepared a permanent repository or interim storage facility. On May 5, 1998, the D.C. Circuit issued a ruling refusing to order DOE to begin moving spent nuclear fuel. On July 24, 1998, we filed a Petition for Review regarding DOE's obligation to begin accepting spent nuclear fuel. ARIZONA PUBLIC SERVICE COMPANY V. DEPARTMENT OF ENERGY AND UNITED STATES OF AMERICA, No. 98-1346 (D.C. Cir.). See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to Financial Statements in Item 8 for a discussion of interim spent fuel storage costs. Several bills have been introduced in Congress contemplating the construction of a central interim storage facility; however, there is resistance to certain features of these bills both in Congress and the Administration. Facility funding is a further complication. While all nuclear utilities pay into a so-called nuclear waste fund an amount calculated on the basis of the output of their respective plants, 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). According to DOE spokespersons, the fund may now be at a level less than needed to achieve a 2010 operational date for a permanent repository. No funding will be available for a central interim facility until one is authorized by Congress. We have storage capacity in existing fuel storage pools at Palo Verde which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of Palo Verde through about 2002. We also believe we could augment that wet storage with new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. One way or another, we currently believe that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation beyond 2002. A new low-level waste facility was built in 1995 on-site which could store an amount of waste equivalent to ten years of normal operation at Palo Verde. Although some low-level waste has been stored on-site, we are currently shipping low-level waste to off-site facilities. We currently believe that interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available. 6 We believe that scientific and financial aspects of the issues of spent fuel and low-level waste storage and disposal can be resolved satisfactorily. However, we also acknowledge that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which we are less able to predict. PURCHASED POWER AGREEMENTS In addition to that available from its own generating capacity (see "Properties" in Item 2), we purchase electricity from other utilities under various arrangements. One of the most important of these is a long-term contract with Salt River Project. This contract may be canceled by Salt River Project on three years' notice and requires Salt River Project to make available, and us to pay for, certain amounts of electricity. The amount of electricity is based in large part on customer demand within certain areas now served by us pursuant to a related territorial agreement. The generating capacity available to us pursuant to the contract was 292 MW January through May 1998, and starting June 1998 increased to 316 MW. In 1998, we received approximately 943,354 MWh of energy under the contract and paid about $43 million for capacity availability and energy received. See Note 3 of Notes to Financial Statements for a discussion of amendments to agreements with Salt River Project. In September 1990, we entered into certain agreements with PacifiCorp relating principally to sales and purchases of electric power and electric utility assets. In July 1991 we sold Cholla 4 to PacifiCorp. As part of the transaction, PacifiCorp agreed to make a firm system sale to us for thirty years during our summer peak season. The amount of the sale for the first seven years was 175 MW and it increases after that at our option, up to a maximum amount of 380 MW. We converted the firm system sales to one-for-one seasonal capacity exchanges with PacifiCorp on October 31, 1997. On January 1, 1999 our agreements with PacifiCorp provide for 275 MW capacity exchange and beginning in May 1999, an additional 205 MW capacity exchange begins. In 1998, we had 275 MW of generating capacity available from PacifiCorp. We received approximately 281,217 MWh of energy under the exchange. During 1996, we entered into an agreement with Citizens Utilities Company to build, own, operate, and maintain a combustion turbine in northwest Arizona. CUC terminated the combustion turbine project in February 1999. We have notified CUC that we will retain the rights to the combustion turbine project. CONSTRUCTION PROGRAM During the years 1996 through 1998, we incurred approximately $899 million in capitalized expenditures. Utility capitalized expenditures for the years 1999 through 2001 are expected to be primarily for expanding transmission and distribution capabilities to meet customer growth, upgrading existing facilities, and for environmental purposes. Capitalized expenditures, including expenditures for environmental control facilities, for the years 1999 through 2001 have been estimated as follows: (MILLIONS OF DOLLARS) BY YEAR BY MAJOR FACILITIES - ------------------------------ ----------------------------------------- 1999 $328 Production $236 2000 317 Transmission and Distribution 564 2001 300 General 113 ---- Other Projects 32 Total $945 ---- ==== Total $945 ==== The amounts for 1999 through 2001 exclude capitalized interest costs and include capitalized property taxes and about $30-$35 million each year for nuclear fuel. We conduct a continuing review of our construction program. We are considering expanding certain of our operations over the next several years, which may result in additional expenditures. We currently believe that there will be opportunities to expand our investment in generating assets in the next five years. It is expected that these generating assets would be organized in a newly-created, non-regulated affiliate under Pinnacle West. 7 MORTGAGE REPLACEMENT FUND REQUIREMENTS So long as any of our first mortgage bonds are outstanding, we are required for each calendar year to deposit with the trustee under our Mortgage cash in a formularized amount related to net additions to our mortgaged utility plant. We may satisfy all or any part of this "replacement fund" requirement by utilizing redeemed or retired bonds, net property additions, or property retirements. For 1998, the replacement fund requirement amounted to approximately $138 million. Certain of the bonds we have issued under the Mortgage that are callable prior to maturity are redeemable at their par value plus accrued interest with cash we deposit in the replacement fund. This is subject in many cases to a period of time after the original issuance of the bonds during which they may not be so redeemed. ENVIRONMENTAL MATTERS EPA ENVIRONMENTAL REGULATION CLEAN AIR ACT. We are subject to a number of requirements under the Clean Air Act. Pursuant to the 1977 amendments to the Clean Air Act, the EPA adopted regulations that address visibility impairment in certain federally-protected areas which can be reasonably attributed to specific sources. In September 1991, the EPA issued a final rule that limited sulfur dioxide emissions at NGS. One NGS unit had to comply with this rule in 1997, one in 1998, and the last unit in 1999. Salt River Project is the NGS operating agent. Salt River Project estimates a capital cost of $430 million and annual operations and maintenance costs of approximately $14 million for all three units, for NGS to meet these requirements. We are required to fund 14% of these expenditures. Approximately 93% of these capital costs have been incurred through 1998. The Clean Air Act Amendments of 1990 (the "Amendments") address, among other things: + "acid rain," + visibility in certain specified areas, + hazardous air pollutants and + areas that have not attained national ambient air quality standards. With respect to "acid rain," the Amendments establish a system of sulfur dioxide emissions "allowances." Each existing utility unit is granted a certain number of "allowances." For Phase II plants, which include our plants, allowances will be required beginning in the year 2000 to operate the plants. On March 5, 1993, the EPA promulgated rules listing allowance allocations applicable to our plants. Based on those allocations, we will have sufficient allowances to permit continued operation of our plants at current levels without installing additional equipment. In addition, the Amendments require the EPA to set nitrogen oxides emissions limitations. These limitations require certain plants to install additional pollution control equipment. In December 1996, the EPA issued rules for nitrogen oxides emissions limitations that may require us to install additional pollution control equipment at Four Corners by January 1, 2000. On February 14, 1997, we filed a Petition for Review in the United States Court of Appeals for the District of Columbia. We alleged that the EPA improperly classified Four Corners Unit 4 in these rules, thereby subjecting Unit 4 to a more stringent emission limitation. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, No. 97-1091. In February 1998, the Court vacated the Unit 4 emission limitation and remanded the issue to EPA for reconsideration. We cannot currently predict how the EPA will respond. However, based on our initial evaluation, we currently estimate our capital cost of complying with the rules may be approximately $4 million. With respect to protection of visibility in certain specified areas, the Amendments require the EPA to conduct a study concerning visibility impairment in those areas and to identify sources contributing to such impairment. 8 Interim findings of this study indicate that any beneficial effect on visibility as a result of the Amendments would be offset by expected population and industry growth. The Amendments also require EPA to establish a "Grand Canyon Visibility Transport Commission" to complete a study on visibility impairment in the "Golden Circle of National Parks" in the Colorado Plateau. NGS, Cholla, and Four Corners are located near the Golden Circle of National Parks. The Commission completed its study and on June 10, 1996 submitted its final recommendations to the EPA. The Commission recommended that, beginning in 2000 and every 5 years thereafter, if actual sulfur dioxide emissions from all stationary sources in an eight-state region (including Arizona, New Mexico, Utah, Nevada, and California) exceed the projected emissions, which are projected to decline under the current regulatory scheme, the projected total emissions will be changed to a "regional emissions cap" and an emissions trading program would be implemented to limit total sulfur dioxide emissions in the region. The EPA will consider these recommendations before promulgating final requirements on a regional haze regulatory program which the EPA proposed in July 1997 and which is expected to be finalized by mid-1999. Under EPA's proposed regional haze program, states would be required to submit plans to meet "presumptive reasonable progress targets" for achieving perceptible improvements in visibility conditions in Federal Class I areas (e.g., national parks) every 10-15 years. The proposal also calls for states to conduct three year "best available retrofit technology" ("BART") reviews on point sources which became operational between 1962 and 1977 and which may normally be anticipated to contribute to regional haze visibility impairment. Also, in July 1997, EPA promulgated final National Ambient Air Quality Standards for ozone and particulate matter. Pursuant to the 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. Because the actual level of emissions controls, if any, for any unit cannot be determined at this time, we currently cannot estimate the capital expenditures, if any, which would result from the final rules. However, we do not currently expect these rules to have a material adverse effect on our financial position or results of operations. With respect to hazardous air pollutants emitted by electric utility steam generating units, the Amendments require two studies. The results of the first study indicated an impact from mercury emissions from such units in certain unspecified areas. The EPA has not yet stated whether or not mercury emissions limitations will be imposed. Secondly, the EPA will complete a general study in the next several years concerning the necessity of regulating hazardous air pollutant emissions from such units under the Amendments. Because we cannot speculate as to the ultimate requirements by the EPA, we cannot currently estimate the capital expenditures, if any, which may be required as a result of these studies. Certain aspects of the Amendments may require us to make related expenditures, such as permit fees. We do not expect any of these to have a material impact on our financial position or results of operations. 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"). PRPs may be strictly, and often jointly and severally, liable for the cost of any necessary remediation of the substances. The EPA had previously advised us that the EPA considers us to be a PRP in the Indian Bend Wash Superfund Site, South Area. Our Ocotillo Power Plant is located in this area. We are in the process of conducting an investigation to determine the extent and scope of contamination at the plant site. Based on the information to date, including available insurance coverage and an EPA estimate of cleanup costs, we do not expect this matter to have a material impact on our financial position or results of operations. MANUFACTURED GAS PLANT SITES. We are currently investigating properties which we now own or which were at one time owned by us or our corporate predecessor, that were at one time sites of, or sites associated with, manufactured gas plants. The purpose of this investigation is to determine if: 9 + waste materials are present + such materials constitute an environmental or health risk and + we have any responsibility for remedial action. Where appropriate, we have begun remediation of certain of these sites. We do not expect these matters to have a material adverse effect on our financial position or results of operations. PURPORTED NAVAJO ENVIRONMENTAL REGULATION Four Corners and NGS are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. We are the Four Corners operating agent. We own a 100% interest in Four Corners Units 1, 2, and 3, and a 15% interest in Four Corners Units 4 and 5. We own a 14% interest in NGS 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 "Acts"). Pursuant to the Acts, the Navajo Nation Environmental Protection Agency is authorized to promulgate regulations covering air quality, drinking water, and pesticide activities, including those that occur at Four Corners and NGS. By separate letters dated October 12 and October 13, 1995, the Four Corners participants and the NGS participants requested the United States Secretary of the Interior to resolve their dispute with the Navajo Nation regarding whether or not the Acts apply to operations of Four Corners and NGS. On October 17, 1995, the Four Corners participants and the NGS 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 Acts to the operations of Four Corners and NGS and + the Navajo Nation and its agencies and courts lack adjudicatory jurisdiction to determine the enforceability of the Acts as applied to Four Corners and NGS. On October 18, 1995, the Navajo Nation and the Four Corners and NGS participants agreed to indefinitely stay these proceedings so that the parties may attempt to resolve the dispute without litigation. The Secretary and the Court have stayed these proceedings pursuant to a request by the parties. We cannot currently predict the outcome of this matter. In February 1998, the EPA promulgated regulations specifying those provisions of the Clean Air Act for which it is appropriate to treat Indian tribes in the same manner as states. The EPA indicated that it believes that the Clean Air Act generally would supersede pre-existing binding agreements that may limit the scope of tribal authority over reservations. On April 10, 1998, we filed a Petition for Review in the United States Court of Appeals for the District of Columbia. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, No. 98-1196. On February 19, 1999, the EPA promulgated regulations setting forth the EPA's approach to issuing Federal operating permits to covered stationary sources on Indian reservations, pursuant to the Amendments. We are currently evaluating the impact of these regulations. WATER SUPPLY Assured supplies of water are important for our generating plants. At the present time, we have adequate water to meet our needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions in recent years. 10 Both groundwater and surface water in areas important to our operations have been the subject of inquiries, claims, and legal proceedings which will require a number of years to resolve. We are one of a number of parties in a proceeding before a state court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. (STATE OF NEW MEXICO, IN THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY OF FARMINGTON, UTAH INTERNATIONAL, INC., ET AL., SAN JUAN COUNTY, NEW MEXICO, District Court No. 75-184). An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for a then-agreed upon cost, sufficient water from its allocation to offset the loss. A summons served on us in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County Superior Court. (IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA RIVER SYSTEM AND SOURCE, Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the geographic area subject to the summons. Our rights and the rights of the Palo Verde participants to the use of groundwater and effluent at Palo Verde is potentially at issue in this action. As project manager of Palo Verde, we filed claims that dispute the court's jurisdiction over the Palo Verde participants' groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, we seek confirmation of such rights. Three of our less-utilized power plants are also located within the geographic area subject to the summons. Our claims dispute the court's jurisdiction over our groundwater rights with respect to these plants. Alternatively, we seek confirmation of such rights. Issues important to the claims are pending on appeal to the Arizona Supreme Court. No trial date concerning our water rights claims has been set in this matter. We have also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County Superior Court. (IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE LITTLE COLORADO RIVER SYSTEM AND SOURCE, Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417). Our groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. Our claims dispute the court's jurisdiction over our groundwater rights. Alternatively, we seek confirmation of such rights. The parties are in the process of settlement negotiations with respect to this matter. No trial date concerning our water rights claims has been set in this matter. Although the foregoing matters remain subject to further evaluation, we expect that the described litigation will not have a material adverse impact on our financial position or results of operations. 11 ITEM 2. PROPERTIES ACCREDITED CAPACITY Our present generating facilities have an accredited capacity 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 --------- 1,712,000 --------- Gas or Oil: Two steam units at Ocotillo and two steam units at Saguaro... 435,000(1) Eleven combustion turbine units.............................. 493,000 Three combined cycle units................................... 255,000 --------- 1,183,000 --------- Nuclear: 29.1% owned or leased Units 1, 2, and 3 at Palo Verde........ 1,086,300 --------- Other............................................................. 5,600 --------- Total........................................................ 3,986,900 ========= - ---------- (1) West Phoenix steam units (108,300 kW) are currently mothballed. ----------------------------------------------------- RESERVE MARGIN Our peak one-hour demand on our electric system was recorded on July 16, 1998 at 5,072,000 kW, compared to the 1997 peak of 4,608,600 kW recorded on August 22. Taking into account additional capacity then available to us under purchase power contracts as well as our own generating capacity, our capability of meeting system demand on July 16, 1998, computed in accordance with accepted industry practices, amounted to 5,139,600 kW, for an installed reserve margin of 3.1%. The power actually available to us from our resources fluctuates from time to time due in part to planned outages and technical problems. The available capacity from sources actually operable at the time of the 1998 peak amounted to 4,862,600 kW, for a margin of (3.9%). Firm purchases from neighboring utilities totaling 1,467,000 kW were in place at the time of the peak ensuring the ability to meet the load requirement, with an actual reserve margin of 7.4%. PLANT SITES LEASED FROM NAVAJO NATION NGS and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. We do not believe that the risk with respect to enforcement of these easements and leases is material. The lease for Four Corners waives until 2001 the requirement that we, as well as our fuel supplier, pay certain taxes to the Navajo Nation. In September 1997, a settlement agreement was finalized between the coal supplier to Four Corners, the Navajo Nation, and us which settled certain issues in the Four Corners lease regarding the obligation of the fuel supplier to pay taxes prior to the expiration of tax waivers in 2001. Pursuant to the agreement, in 1997 we recognized approximately $14 million of pretax earnings related to a partial refund of 12 possessory interest taxes paid by the fuel supplier. The parties also agreed to renegotiate their business relationship before 2001 in an effort to permit the electricity generated at Four Corners to be priced competitively. We cannot currently predict the outcome of this matter. Certain of our transmission lines and almost all of its contracted coal sources are also located on Indian reservations. See "Generating Fuel and Purchased Power--Coal Supply" in Item 1. PALO VERDE NUCLEAR GENERATING STATION PALO VERDE LEASES See Note 9 of Notes to Financial Statements in Item 8 for a discussion of three sale and leaseback transactions related to Palo Verde Unit 2. REGULATORY Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986, and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize us, as operating agent for Palo Verde, to operate the three Palo Verde units at full power. NUCLEAR DECOMMISSIONING COSTS The NRC recently amended its rules on financial assurance requirements for the decommissioning of nuclear power plants. The amended rules became effective on November 23, 1998. The amended rules provide that a licensee may use an external sinking fund 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." Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on the external sinking fund mechanism are not met. We currently rely on the external sinking fund mechanism to meet the NRC financial assurance requirements for our interests in Palo Verde Units 1, 2, and 3. The decommissioning costs of Palo Verde Units 1, 2, and 3 are currently included in ACC jurisdictional rates. Proposed ACC rules regarding the introduction of retail electric competition in Arizona (see Note 3) currently provide that decommissioning costs would be recovered through a non-bypassable "system benefits" charge, which would allow us to maintain our external sinking fund mechanism. See Note 13 of Notes to Financial Statements in Item 8 for additional information about our nuclear decommissioning costs. PALO VERDE LIABILITY AND INSURANCE MATTERS See "Palo Verde Nuclear Generating Station" in Note 12 of Notes to Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including us, for Palo Verde. 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 "Financial Review ___ Capital Needs and Resources" in Item 7 for a discussion of our construction plans. See Notes 5, 8, and 9 of Notes to Financial Statements in Item 8 with respect to our property not held in fee or held subject to any major encumbrance. 13 [MAP PAGE] In accordance with Item 304 of Regulation S-T of the Securities Exchange Act of 1934, our Service Territory map contained in this Form 10-K is a map of the State of Arizona showing the Company's service area, the location of its major power plants and principal transmission lines, and the location of transmission lines operated by the Company for others. The 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; and the Palo Verde Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona (each of which plants is reflected on such map as being jointly owned with other utilities), as well as the Ocotillo Power Plant and West Phoenix Power Plant, each located near Phoenix, Arizona, and the Saguaro Power Plant, located near Tucson, Arizona. The Company's 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. 14 ITEM 3. LEGAL PROCEEDINGS See "Environmental Matters" and "Water Supply" in Item 1 in regard to pending or threatened litigation and other disputes. See "Regulatory Matters" in Note 3 of Notes to Financial Statements in Item 8 for a discussion of competition and the rules regarding the introduction of retail electric competition in Arizona. On February 28, 1997 and October 16, 1998, we filed lawsuits to protect our legal rights regarding the rules and the amended rules, respectively, and in each complaint we asked the Court for (i) a judgment vacating the retail electric competition rules, (ii) a declaratory judgment that the rules are unlawful because, among other things, they were entered into without proper legal authorization, and (iii) a permanent injunction barring the ACC from enforcing or implementing the rules and from promulgating any other regulations without lawful authority. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 97-03753 (consolidated under CV 97-03748.) ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-18896. On August 28, 1998, we filed two lawsuits to protect our legal rights under the stranded cost order and in its complaints the Company asked the Court to vacate and set aside the order. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-15728. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, 1-CA-CC-98-0008. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 15 SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE REGISTRANT The Company's executive officers are as follows: AGE AT NAME MARCH 1, 1999 POSITION(S) AT MARCH 1, 1999 - ---- ------------- ---------------------------- Richard Snell 68 Chairman of the Board of Directors(1) William J. Post 48 Chief Executive Officer(1) Jack E. Davis 52 President, Energy Delivery and Sales(1) William L. Stewart 55 President, Generation(1) George A. Schreiber, Jr. 50 Executive Vice President and Chief Financial Officer(1) Armando B. Flores 55 Executive Vice President, Corporate Business Services James M. Levine 49 Senior Vice President, Nuclear Generation Jan H. Bennett 51 Vice President, Distribution John G. Bohon 53 Vice President, Corporate Services and Human Resources John R. Denman 56 Vice President, Fossil Generation Edward Z. Fox 45 Vice President, Environmental/Health/Safety and New Technology Ventures William E. Ide 52 Vice President, Nuclear Engineering Nancy C. Loftin 45 Vice President, Chief Legal Counsel and Secretary Gregg R. Overbeck 52 Vice President, Nuclear Production Chris N. Froggatt 41 Controller Michael V. Palmeri 40 Treasurer - ---------- (1) Member of the Board of Directors. Our executive officers 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. Snell was elected to his present position as of February 1990. He was also elected Chairman of the Board, President and Chief Executive Officer of Pinnacle West at that time. He retired as President in February 1997 and as Chief Executive Officer in February 1999. Mr. Snell is also a director of Pinnacle West, Aztar Corporation, and Central Newspapers, Inc. Mr. Post was elected President and Chief Executive Officer in February 1997. In October 1998, he resigned as President and maintained the position of Chief Executive Officer. Prior to that time he was Senior Vice President and Chief Operating Officer (September 1994 - February 1997) and Senior Vice President, Planning, Information and Financial Services (June 1993 - September 1994). Mr. Post was President of Pinnacle West (February 1997 - February 1999) and in February 1999, he became Chief Executive Officer of Pinnacle West. Mr. Post is also a director of Pinnacle West. Mr. Davis was elected to his present position in October 1998. Prior to that time he was Executive Vice President, Commercial Operations (September 1996 - - October 1998) and Vice President, Generation and Transmission (June 1993-September 1996). 16 Mr. Stewart was elected to his present position in October 1998. Prior to that time he was Executive Vice President, Generation (September 1996 - October 1998), Executive Vice President, Nuclear (May 1994 - September 1996) and Senior Vice President--Nuclear for Virginia Power (since 1989). Mr. Schreiber was elected to his present position in February 1997. Prior to that time he was Managing Director at PaineWebber, Inc. (since February 1990). Mr. Schreiber was Executive Vice President of Pinnacle West (February 1997 - February 1999), and he is currently President (since February 1999) and Chief Financial Officer (since February 1997) of Pinnacle West. Mr. Schreiber is also a director of Pinnacle West. Mr. Flores was elected to his present position in October 1998. Prior to that time, he was Senior Vice President, Corporate Business Services (September 1996 - October 1998) and Vice President, Human Resources (1991-1996). Mr. Flores is a director of Harris Trust Bank. Mr. Levine was elected to his present position in September 1996. Prior to that time he was Vice President, Nuclear Production (since September 1989). Mr. Bennett was elected to his present position in May 1991. Mr. Bohon was elected to his present position in October 1998. Prior to that time he was Vice President, Procurement (April 1997 - October 1998) and Director, Corporate Services (December 1989-April 1997). Mr. Denman was elected to his present position in April 1997. Prior to that time he was Director of Fossil Generation (since 1990). Mr. Fox was elected to his present position in October 1995. Prior to that time he was Director, Arizona Department of Environmental Quality and Chairman, Wastewater Management Authority of Arizona (July 1991-September 1995). Mr. Ide was elected to his present position in September 1996. Prior to that time he was Director, Palo Verde Operations (1994-1996) and Palo Verde Unit 1 Plant Manager (1988-1994). Ms. Loftin was elected to the positions of Vice President and Chief Legal Counsel in September 1996 and has been Secretary since April 1987. Prior to that time, in addition to Secretary, she was Corporate Counsel (since February 1989). Mr. Overbeck was elected to his current position in July 1995. Prior to that time he was Assistant to Vice President of the Company (January 1994-July 1995). Mr. Froggatt was elected to his present position in July 1997. Prior to that time he was Director, Accounting Services (since December 1992) of the Company. Mr. Palmeri was elected to his present position in July 1997. Prior to that time he was Assistant Treasurer (February 1994-July 1997) and Manager of Finance (June 1990-February 1994) of Pinnacle West. He also became Treasurer of Pinnacle West in July 1997. 17 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS The Company's common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for the Company's common stock. The chart below sets forth the dividends declared on the Company's common stock for each of the four quarters for 1998 and 1997. COMMON STOCK DIVIDENDS (THOUSANDS OF DOLLARS) - -------------------------------------------------------------------------------- QUARTER 1998 1997 - -------------------------------------------------------------------------------- 1st Quarter $42,500 $42,500 2nd Quarter 42,500 42,500 3rd Quarter 42,500 42,500 4th Quarter 42,500 42,500 - -------------------------------------------------------------------------------- After payment or setting aside for payment of cumulative dividends and mandatory sinking fund requirements, where applicable, on all outstanding issues of preferred stock, the holders of common stock are entitled to dividends when and as declared out of funds legally available therefor. See Notes 4 and 5 of Notes to Financial Statements in Item 8 for restrictions on retained earnings available for the payment of common stock dividends. 18 ITEM 6. SELECTED FINANCIAL DATA
1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- (THOUSANDS OF DOLLARS) Electric Operating Revenues ............. $2,006,398 $1,878,553 $1,718,272 $1,614,952 $1,626,168 Fuel and Purchased Power ................ 537,501 436,627 325,523 269,798 300,689 Operating Expenses ...................... 1,098,086 1,070,101 1,027,541 963,400 957,046 ---------- ---------- ---------- ---------- ---------- Operating Income ..................... 370,811 371,825 365,208 381,754 368,433 Other Income ............................ 20,448 21,586 35,217 25,548 44,510 Interest Deductions -- Net .............. 136,012 141,918 156,954 167,732 169,457 ---------- ---------- ---------- ---------- ---------- Net Income ........................... 255,247 251,493 243,471 239,570 243,486 Preferred Dividends .................. 9,703 12,803 17,092 19,134 25,274 ---------- ---------- ---------- ---------- ---------- Earnings for Common Stock ............ $ 245,544 $ 238,690 $ 226,379 $ 220,436 $ 218,212 ========== ========== ========== ========== ========== Total Assets ............................ $6,393,299 $6,331,142 $6,423,222 $6,418,262 $6,348,261 ========== ========== ========== ========== ========== Capital Structure: Common Stock Equity .................. $1,975,755 $1,849,324 $1,729,390 $1,621,555 $1,571,120 Non-Redeemable Preferred Stock ....... 85,840 142,051 165,673 193,561 193,561 Redeemable Preferred Stock ........... 9,401 29,110 53,000 75,000 75,000 Long-Term Debt Less Current Maturities.......................... 1,876,540 1,953,162 2,029,482 2,132,021 2,181,832 ---------- ---------- ---------- ---------- ---------- Total Capitalization ............... 3,947,536 3,973,647 3,977,545 4,022,137 4,021,513 Current Maturities of Long-Term Debt . 164,378 104,068 153,780 3,512 3,428 Commercial Paper ..................... 178,830 130,750 16,900 177,800 131,500 ---------- ---------- ---------- ---------- ---------- Total .............................. $4,290,744 $4,208,465 $4,148,225 $4,203,449 $4,156,441 ========== ========== ========== ========== ==========
- ---------- See "Financial Review" in Item 7 for a discussion of certain information in the foregoing table. 19 ITEM 7. FINANCIAL REVIEW In this section, we explain our results of operations, general financial condition, and outlook, including: + the changes in our earnings from 1997 to 1998 and from 1996 to 1997 + the factors impacting our business, including competition and electric industry restructuring + the effects of regulatory agreements on our results + our capital needs and resources and + Year 2000 technology issues. Throughout this Financial Review, we refer to specific "Notes" in the Notes to Financial Statements that begin on page 35. These Notes add further details to the discussion. RESULTS OF OPERATIONS 1998 COMPARED WITH 1997 Our 1998 earnings increased $6.9 million - a 2.9% increase - over 1997 earnings primarily because of an increase in customers, expanded power marketing and trading activities, and lower financing costs. In the comparison, these positive factors more than offset the effects of milder weather, two fuel-related settlements recorded in 1997, and two retail price reductions. See Note 3 for additional information about the price reductions. In 1998, electric operating revenues increased $128 million primarily because of: + increased power marketing and trading revenues ($94 million) + increases in the number of customers and the amount of electricity used by customers ($77 million) and + miscellaneous factors ($8 million). As mentioned above, these positive factors were partially offset by the effects of milder weather ($33 million) and reductions in retail prices ($18 million). Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted from higher prices, increased activity in Western bulk power markets, and increased sales to large customers in California. The increase in power marketing and trading revenues was accompanied by related increases in purchased power expenses. The two fuel-related settlements increased 1997 pretax earnings by about $21 million. The income statement reflects these settlements as reductions in fuel expense and as other income. Operations and maintenance expense increased $15 million because of customer growth, initiatives related to competition, and expansion of our power marketing and trading function. Depreciation and amortization expense increased $11 million because we had more plant in service. Financing costs decreased by $9 million primarily because of lower amounts of outstanding debt and preferred stock. 20 1997 COMPARED WITH 1996 Our 1997 earnings increased $12.3 million - a 5.4% increase - over 1996 earnings primarily because of: + an increase in customers + a $32 million pretax charge in 1996 for a voluntary severance program + two fuel-related settlements in 1997 and + lower financing costs. These positive factors more than offset the effects of our 1996 regulatory agreement with the Arizona Corporation Commission (ACC), which during 1997 resulted in about $60 million of additional regulatory asset amortization and a $35 million revenue decrease caused by two retail price reductions. See Note 3 and "Results of Operations ___ Regulatory Agreements" below for additional information. In addition, we recognized $12 million of income tax benefits in 1996 that were not repeated in 1997. In 1997, electric operating revenues increased $160 million primarily because of: + increased power marketing revenues ($128 million) + an increase in the number of customers ($58 million) and + weather effects ($7 million). As mentioned above, these positive factors were partially offset by a $35 million revenue decrease caused by retail price reductions. The increase in power marketing revenues resulted from increased activity in Western bulk power markets. This did not significantly affect our earnings because the increase was substantially offset by higher purchased power expenses. Two fuel-related settlements in 1997 increased pretax earnings by about $21 million. The income statement shows these settlements as reductions in fuel expense and as other income. About $16 million of the settlements related to years prior to 1997 and $5 million related to 1997. We expect the total annual savings from the settlements for at least the next several years to be about $10 million before income taxes. We do not have a fuel adjustment clause as part of our retail rate structure. As a result, we show changes in fuel and purchased power expenses in current earnings. We lowered our operations and maintenance expenses in 1997 by putting in place a voluntary severance program in late 1996, with related savings reflected in 1997. These savings were partially offset by increased expenses for marketing, information technology, and power plant maintenance. We decreased our financing costs by $12 million during 1997 by lowering the amounts of outstanding debt and preferred stock. REGULATORY AGREEMENTS Regulatory agreements with the ACC affect the results of our operations. The following discussion focuses on two agreements: a 1996 agreement to accelerate the amortization of our regulatory assets and a 1994 settlement to accelerate amortization of our deferred investment tax credits (ITCs). Under the 1996 agreement with the ACC, we are recovering substantially all of our present regulatory assets through accelerated amortization. The recovery of these assets is taking place over an eight-year period that will end June 30, 2004. For more details, see Note 3. This accelerated amortization increased annual amortization expense by about $120 million ($72 million after taxes). Also, as part of the 1996 regulatory agreement, we reduced our retail prices by 3.4% effective July 1, 1996. This reduces revenue by about $48.5 million annually ($29 million after taxes). We also agreed to share future cost savings with our customers, which resulted in the following additional retail price reductions: 21 + $17.6 million annually ($10.5 million after income taxes), or 1.2%, effective July 1, 1997, and + $17 million annually ($10 million after income taxes), or 1.1%, effective July 1, 1998. We expect to file with the ACC for another retail price decrease of approximately $10.8 million annually ($6.5 million after income taxes) to become effective July 1, 1999. The amount and timing of the price decrease are subject to ACC approval. This will be the last price decrease under the 1996 regulatory agreement. We discuss above, in "Results of Operations," the factors that offset the earnings impact of the accelerated regulatory asset amortization and the price decreases. As part of the 1994 rate settlement, we accelerated amortization of substantially all deferred ITCs over a five-year period that ends on December 31, 1999. The amortization of ITCs is shown on our income statement as Other Income ___ Income Taxes. It decreases annual income tax expense by about $28 million. Beginning in 2000, no further benefits will be reflected in income tax expense. See Note 10. CAPITAL NEEDS AND RESOURCES Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt and preferred stock. We pay for our capital requirements with: + cash from our operations + annual cash payments from Pinnacle West of $50 million from 1996 through 1999 (see Note 3) and + to the extent necessary, external financing. During the period from 1996 through 1998, we paid for all of our capital expenditures with cash from our operations. We expect to do so in 1999 through 2001 as well. Our capital expenditures in 1998 were $327 million. Our projected capital expenditures for the next three years are: 1999, $328 million; 2000, $317 million; and 2001, $300 million. These amounts include about $30-$35 million each year for nuclear fuel. In general, most of the projected capital expenditures are for: + expanding transmission and distribution capabilities to meet customer growth + upgrading existing utility property and + environmental purposes. In addition, we are considering expanding certain of our operations over the next several years, which may result in additional expenditures. We currently believe that there will be opportunities to expand our investment in generating assets in the next five years. It is expected that these generating assets would be organized in a newly created non-regulated affiliate under Pinnacle West. During 1998, we redeemed about $145 million of long-term debt and $76 million of preferred stock, including premiums, with cash from operations and long- and short-term debt. Our long-term debt and preferred stock redemption requirements and payment obligations on a capitalized lease for the next three years are: 1999, $260 million; 2000, $115 million; and 2001, $2 million. On March 1, 1999, we redeemed all $95 million of our outstanding preferred stock. Based on market conditions and optional call provisions, we may make optional redemptions of long-term debt from time to time. 22 As of December 31, 1998, we had credit commitments from various banks totaling about $400 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At the end of 1998, we had about $179 million of commercial paper and $125 million of long-term bank borrowings outstanding. In 1998, we issued $100 million of unsecured long-term debt and in February 1999, we issued $125 million of unsecured long-term debt. Although provisions in our first mortgage bond indenture, articles of incorporation, and ACC financing orders establish maximum amounts of additional first mortgage bonds that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements. COMPETITION AND INDUSTRY RESTRUCTURING The electric industry is undergoing significant change. It is moving to a competitive, market-based structure from a highly-regulated, cost-based environment in which companies have been entitled to recover their costs and to earn fair returns on their invested capital in exchange for commitments to serve all customers within designated service territories. In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition in Arizona and adopted amendments to the rules in August 1998. On January 11, 1999, the ACC issued an order which stayed the amended rules and granted waivers from compliance with the rules to all affected utilities (including us) pending further ACC decisions. On February 5, 1999, ACC hearing officers issued recommendations for changes to the amended rules. These recommended changes were further amended by an ACC Procedural Order dated March 12, 1999. See Note 3 for additional information about these rules and other competitive developments, including an agreement with Salt River Project Agricultural Improvement and Power District (Salt River Project). We cannot currently predict when or if the amended rules will be further modified, when the stay of the amended rules will be lifted, or when retail electric competition will be introduced in Arizona with respect to affected utilities. The rules as recommended indicate that the ACC will allow affected utilities the opportunity to fully recover unmitigated stranded costs, but do not set forth the mechanisms for determining and recovering such costs. On June 22, 1998, the ACC issued an order on stranded cost determination and recovery and on February 5, 1999, an ACC hearing officer issued recommended changes to that order. These recommended changes were further amended by an ACC Procedural Order dated March 12, 1999. See Note 3 for additional information on proposed modifications to the stranded cost order. An Arizona joint legislative committee studied electric utility restructuring issues in 1996 and 1997. In May 1998, a law was enacted to facilitate implementation of retail electric competition in the state. Additionally, legislation related to electric competition has been proposed in the United States Congress. See Note 3 for a discussion of legislative developments. We believe that further ACC decisions, legislation at the Arizona and federal levels, and perhaps amendments to the Arizona Constitution will ultimately be required before significant implementation of retail electric competition can lawfully occur in Arizona. Until it has been determined how competition will be implemented in Arizona, including the manner in which stranded costs will be addressed, we cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operations. 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. We prepare our financial statements in accordance with Statement of Financial Accounting Standards (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. Our existing regulatory orders and the current regulatory environment support our accounting practices related to regulatory assets, which amounted to about $900 million at December 31, 1998. Under the 1996 regulatory agreement, the ACC 23 accelerated the amortization of substantially all of our regulatory assets to an eight-year period that will end June 30, 2004. If we cease to be cost-based regulated, we would no longer be able to apply the provisions of SFAS No. 71 to part or all of our operations, which could have a material impact on our financial statements. See Note 1 for additional information on regulatory accounting. YEAR 2000 READINESS DISCLOSURE OVERVIEW As the year 2000 approaches, many companies face problems because many computer systems and equipment will not properly recognize calendar dates beginning with the year 2000. We are addressing the Year 2000 issue as described below. We initiated a comprehensive company-wide Year 2000 program during 1997 to review and resolve all Year 2000 issues in mission critical systems (systems and equipment that are key to business function, health, and safety) in a timely manner to ensure the reliability of electric service to our customers. This included a company-wide awareness program of the Year 2000 issue. The following chart shows Year 2000 readiness of our mission critical systems as of January 31, 1999: INVENTORY ASSESSMENT REMEDIATION & TESTING 100% 100% 70%* * Estimated to be at 100% by June 30, 1999, except one Palo Verde unit as discussed below. DISCUSSION We have been actively implementing and replacing systems and technology since 1995 for general business reasons unrelated to the Year 2000, and these actions have resulted in substantially all of our major information technology (IT) systems becoming Year 2000 ready. The major IT systems that were, and are being, implemented and replaced include the following: + Work Management + Materials Management + Energy Management + Payroll + Financial + Human Resources + Trouble Call Management + Computer and Communications Network Upgrades + Geographic Information Management + Customer Information System and + Palo Verde Site Work Management. We have made, and will continue to make, certain modifications to computer hardware and software systems and applications, including IT and non-IT systems, in an effort to ensure they are capable of handling changing business needs, including dates in the year 2000 and thereafter. In addition, we are analyzing other IT systems and non-IT systems, including embedded technology and real-time process control systems, for potential modifications. We have inventoried and assessed essentially all mission critical IT and non-IT systems and equipment. We are 70% complete with the remediation and testing of these systems. Remediation and testing is expected to be completed by June 30, 1999, for all mission critical systems, except for those items that can only be completed during maintenance outages at Palo Verde, which will be completed for the last unit, which is substantially identical to the other two units, during the last half of 1999. We have an internal audit/quality review team that is periodically reviewing the individual Year 2000 projects and their Year 2000 readiness. 24 We currently estimate that we will spend about $5 million relating to Year 2000 issues, about $3 million of which has been spent to date. This includes an estimated allocation of payroll costs for our employees working on Year 2000 issues, and costs for consultants, hardware, and software. We do not separately track other internal costs. This does not include costs incurred since 1995 to implement and replace systems for reasons unrelated to the Year 2000, as discussed above. Our cost to address the Year 2000 issue is charged to operating expenses as incurred and has not had, and is not expected to have, a material adverse effect on our financial position, cash flows, or results of operations. We expect to fund this cost with available cash balances and cash provided by operations. We are communicating with our significant suppliers, business partners, other utilities, and large customers to determine the extent to which we may be affected by these third parties' plans to remediate their own Year 2000 issues in a timely manner. We have been interfacing with suppliers of systems, services, and materials in order to assess whether their schedules for analysis and remediation of Year 2000 issues are timely and to assess their ability to continue to supply required services and materials. We are also working with the North American Electric Reliability Council (NERC) through the Western Systems Coordinating Council (WSCC) to develop operational plans for stable grid operation that will be used by other utilities and us in the western United States. These plans are expected to be completed by June 30, 1999. However, we cannot currently predict the effect on us if the systems of these other companies are not Year 2000 ready. We currently expect that our most reasonably likely worst case Year 2000 scenario would be intermittent loss of power to customers, similar to an outage during a severe weather disturbance. In this situation, we would restore power as soon as possible by, among other things, re-routing power flows. We do not currently expect that this scenario would have a material adverse effect on our financial position, cash flows, or results of operations. We are working to develop our own contingency plans to handle Year 2000 issues, including the most reasonably likely worst case scenario, discussed above, and we expect these plans to be completed by June 30, 1999. As discussed above, we have also been working with NERC and WSCC to develop contingency plans related to grid operation. ACCOUNTING MATTERS We describe two new accounting rules in Note 2. First, the new rule on energy trading and risk management is effective in 1999. We do not expect it to have a material impact on our financial results. Secondly, the new standard on derivatives is effective for us in 2000. We are currently evaluating what impact it will have on our financial statements. Also, see Note 13 for a description of a proposed standard on accounting for certain liabilities related to closure or removal of long-lived assets. RISK MANAGEMENT Our operations include managing market risks related to changes in interest rates, commodity prices, and investments held by the nuclear decommissioning trust fund. 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 the nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed and floating rate debt. The nuclear decommissioning fund also has risks associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in rates. The tables below present contractual balances of our long-term debt and commercial paper at the expected maturity dates as well as the fair value of those instruments on December 31, 1998 and December 31, 1997. The weighted average interest rates for the various debt presented are actual as of December 31, 1998 and December 31, 1997. 25 EXPECTED MATURITY/PRINCIPAL REPAYMENT DECEMBER 31, 1998 (THOUSANDS OF DOLLARS)
SHORT-TERM VARIABLE LONG-TERM FIXED LONG-TERM ------------------- ------------------- ------------------- INTEREST INTEREST INTEREST RATES AMOUNT RATES AMOUNT RATES AMOUNT ------------------- ------------------- ------------------- 1999 6.21% $ 178,830 -- $ -- 7.24% $ 164,378 2000 -- -- -- -- 5.79% 114,711 2001 -- -- -- -- 7.48% 2,488 2002 -- -- -- -- 8.13% 125,000 2003 -- -- 5.69% 125,000 -- -- Years thereafter -- -- 3.39% 456,860 7.75% 1,058,963 ---------- ---------- ---------- Total $ 178,830 $ 581,860 $1,465,540 ========== ========== ========== Fair Value $ 178,830 $ 581,860 $1,525,900 ========== ========== ==========
EXPECTED MATURITY/PRINCIPAL REPAYMENT DECEMBER 31, 1997 (THOUSANDS OF DOLLARS)
SHORT-TERM VARIABLE LONG-TERM FIXED LONG-TERM ------------------- ------------------- ------------------- INTEREST INTEREST INTEREST RATES AMOUNT RATES AMOUNT RATES AMOUNT ------------------- ------------------- ------------------- 1998 6.27% $ 130,750 -- $ -- 7.62% $ 104,068 1999 -- -- -- -- 7.25% 164,378 2000 -- -- -- -- 5.83% 104,711 2001 -- -- -- -- 7.48% 2,488 2002 -- -- 6.25% 150,000 8.13% 125,000 Years thereafter -- -- 3.62% 439,990 7.92% 973,628 ---------- ---------- ---------- Total $ 130,750 $ 589,990 $1,474,273 ========== ========== ========== Fair Value $ 130,750 $ 589,990 $1,504,417 ========== ========== ==========
COMMODITY PRICE RISK We utilize a variety of derivative instruments including exchange-traded futures, options, and swaps as part of our overall risk management strategies and for trading purposes. In order to reduce the risk of adverse price fluctuations in the electricity and natural gas markets, we enter into futures and/or option transactions to hedge certain natural gas held in storage as well as certain expected purchases and sales of natural gas and electricity. The changes in market value of such contracts have a high correlation to the price changes in the hedged commodity. Gains and losses related to derivatives that qualify as hedges of expected transactions are recognized in income when the underlying hedged physical transaction closes (deferral method). Gains and losses on derivatives utilized for trading are recognized in income on a current basis (the mark to market method). 26 We have prepared a sensitivity analysis to estimate our exposure to the market risk of our derivative position for natural gas and electricity. With respect to these derivatives, a potential adverse price movement of 10% in the market price of natural gas and electricity from the December 31, 1998 levels would decrease the fair value of these instruments by approximately $1 million. This analysis does not include the favorable impact that the same hypothetical price movement would have on expected physical purchases and sales of natural gas and electricity. We are exposed to credit losses in the event of non-performance or non-payment by counterparties. We use a credit management process to assess and monitor the financial viability of counterparties. We do not expect counterparty defaults to materially impact our financial condition, results of operations, or net cash flows. FORWARD-LOOKING STATEMENTS The above discussion contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax, and environmental legislation; our ability to successfully compete outside our traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; and Year 2000 issues. These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes we currently expect or seek. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. See "Financial Review" in Item 7 for a discussion of quantitative and qualitative disclosures about market risk. 27 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS Page ---- Report of Management...................................................... 29 Independent Auditors' Report.............................................. 30 Statements of Income for 1998, 1997, and 1996............................. 31 Balance Sheets as of December 31, 1998 and 1997........................... 32 Statements of Cash Flows for 1998, 1997, and 1996......................... 34 Statements of Retained Earnings for 1998, 1997, and 1996.................. 35 Notes to Financial Statements............................................. 35 See Note 14 of Notes to Financial Statements for the selected quarterly financial data required to be presented in this Item. 28 REPORT OF MANAGEMENT The primary responsibility for the integrity of the Company's financial information rests with management, which has prepared the accompanying financial statements and related information. Such information was prepared in accordance with generally accepted accounting principles appropriate in the circumstances and based on management's best estimates and judgments. Materiality was given due consideration. These financial statements have been audited by independent auditors and their report is included. Management maintains and relies upon systems of internal accounting controls. A limiting factor in all systems of internal accounting control is that the cost of the system should not exceed the benefits to be derived. Management believes that the Company's system provides the appropriate balance between such costs and benefits. Periodically the internal accounting control system is reviewed by both the Company's internal auditors and its independent auditors to test for compliance. Reports issued by the internal auditors are released to management, and such reports or summaries thereof are transmitted to the Audit Review Committee of the Board of Directors and the independent auditors on a timely basis. The Audit Review Committee, composed solely of outside directors, meets periodically with the internal auditors and independent auditors (as well as management) to review the work of each. The internal auditors and independent auditors have free access to the Audit Review Committee, without management present, to discuss the results of their audit work. Management believes that the Company's systems, policies, and procedures provide reasonable assurance that operations are conducted in conformity with the law and with management's commitment to a high standard of business conduct. William J. Post George A. Schreiber, Jr. William J. Post George A. Schreiber, Jr. Chief Executive Officer Executive Vice President and Chief Financial Officer 29 INDEPENDENT AUDITORS' REPORT We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 1998 and 1997 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1998 and 1997 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. Deloitte & Touche LLP Deloitte & Touche LLP Phoenix, Arizona March 4, 1999 30 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF INCOME YEAR ENDED DECEMBER 31, ------------------------------------- 1998 1997 1996 ---------- ---------- ---------- (THOUSANDS OF DOLLARS) Electric Operating Revenues ............. $2,006,398 $1,878,553 $1,718,272 ---------- ---------- ---------- Fuel Expenses: Fuel for electric generation ......... 231,967 201,341 230,393 Purchased power ...................... 305,534 235,286 95,130 ---------- ---------- ---------- Total .............................. 537,501 436,627 325,523 ---------- ---------- ---------- Operating Revenues Less Fuel Expenses ... 1,468,897 1,441,926 1,392,749 ---------- ---------- ---------- Other Operating Expenses: Operations and maintenance excluding fuel expenses ...................... 414,041 399,434 430,714 Depreciation and amortization (Note 1) 376,574 365,671 297,210 Income taxes (Note 10) ............... 192,207 184,737 178,513 Other taxes .......................... 115,264 120,259 121,104 ---------- ---------- ---------- Total .............................. 1,098,086 1,070,101 1,027,541 ---------- ---------- ---------- Operating Income ........................ 370,811 371,825 365,208 ---------- ---------- ---------- Other Income (Deductions): Allowance for equity funds used during construction ....................... -- -- 5,209 Income taxes (Note 10) ............... 32,751 31,413 45,552 Other -- net ......................... (12,303) (9,827) (15,544) ---------- ---------- ---------- Total .............................. 20,448 21,586 35,217 ---------- ---------- ---------- Income Before Interest Deductions ....... 391,259 393,411 400,425 ---------- ---------- ---------- Interest Deductions: Interest on long-term debt ........... 137,214 140,931 147,666 Interest on short-term borrowings .... 7,481 9,404 10,621 Debt discount, premium and expense ... 7,580 7,791 8,176 Capitalized interest ................. (16,263) (16,208) (9,509) ---------- ---------- ---------- Total .............................. 136,012 141,918 156,954 ---------- ---------- ---------- Net Income .............................. 255,247 251,493 243,471 Preferred Stock Dividend Requirements ... 9,703 12,803 17,092 ---------- ---------- ---------- Earnings for Common Stock ............... $ 245,544 $ 238,690 $ 226,379 ========== ========== ========== See Notes to Financial Statements. 31 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS ASSETS DECEMBER 31, ------------------------- 1998 1997 ----------- ----------- (THOUSANDS OF DOLLARS) Utility Plant (Notes 5, 8 and 9): Electric plant in service and held for future use...................................... $ 7,265,604 $ 7,009,059 Less accumulated depreciation and amortization .. 2,814,762 2,620,607 ----------- ----------- Total ......................................... 4,450,842 4,388,452 Construction work in progress ................... 228,643 237,492 Nuclear fuel, net of amortization of $68,569 and $66,081 ................................... 51,078 51,624 ----------- ----------- Utility Plant -- net .......................... 4,730,563 4,677,568 ----------- ----------- Investments and Other Assets (Note 13) ............. 183,549 164,906 ----------- ----------- Current Assets: Cash and cash equivalents ....................... 5,558 12,552 Accounts receivable: Service customers ............................. 205,999 141,022 Other ......................................... 23,213 31,313 Allowance for doubtful accounts ............... (1,725) (1,338) Accrued utility revenues ........................ 67,740 58,559 Materials and supplies (at average cost) ........ 69,074 70,634 Fossil fuel (at average cost) ................... 13,978 9,621 Deferred income taxes (Note 10) ................. 3,999 3,496 Other ........................................... 26,695 24,529 ----------- ----------- Total Current Assets .......................... 414,531 350,388 ----------- ----------- Deferred Debits: Regulatory asset for income taxes (Note 10) ..... 400,795 458,369 Rate synchronization cost deferral .............. 303,660 358,871 Unamortized costs of reacquired debt ............ 53,744 63,501 Unamortized debt issue costs .................... 14,916 15,303 Other ........................................... 291,541 242,236 ----------- ----------- Total Deferred Debits ......................... 1,064,656 1,138,280 ----------- ----------- Total ......................................... $ 6,393,299 $ 6,331,142 =========== =========== See Notes to Financial Statements. 32 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS LIABILITIES DECEMBER 31, ----------------------- 1998 1997 ---------- ---------- (THOUSANDS OF DOLLARS) Capitalization (Notes 4 and 5): Common stock ...................................... $ 178,162 $ 178,162 Additional paid--in capital ....................... 1,195,625 1,142,364 Retained earnings ................................. 601,968 528,798 ---------- ---------- Common stock equity ............................. 1,975,755 1,849,324 Non-redeemable preferred stock .................... 85,840 142,051 Redeemable preferred stock ........................ 9,401 29,110 Long-term debt less current maturities ............ 1,876,540 1,953,162 ---------- ---------- Total Capitalization ............................ 3,947,536 3,973,647 ---------- ---------- Current Liabilities: Commercial paper (Note 6) ......................... 178,830 130,750 Current maturities of long-term debt (Note 5) ..... 164,378 104,068 Accounts payable .................................. 145,139 107,423 Accrued taxes ..................................... 59,827 85,886 Accrued interest .................................. 31,218 31,660 Customer deposits ................................. 26,815 29,116 Other ............................................. 16,755 19,588 ---------- ---------- Total Current Liabilities ....................... 622,962 508,491 ---------- ---------- Deferred Credits and Other: Deferred income taxes (Note 10) ................... 1,312,007 1,345,177 Deferred investment tax credit (Note 10) .......... 32,465 60,093 Unamortized gain--sale of utility plant (Note 9)... 77,787 82,363 Customer advances for construction ................ 31,451 29,294 Other ............................................. 369,091 332,077 ---------- ---------- Total Deferred Credits and Other ................ 1,822,801 1,849,004 ---------- ---------- Commitments and Contingencies (Note 12) Total ............................................. $6,393,299 $6,331,142 ========== ========== 33 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, --------------------------------- 1998 1997 1996 --------- --------- --------- (THOUSANDS OF DOLLARS) Cash Flows from Operations: Net income .......................................... $ 255,247 $ 251,493 $ 243,471 Items not requiring cash: Depreciation and amortization ..................... 376,574 365,671 297,210 Nuclear fuel amortization ......................... 32,856 32,702 33,566 Allowance for equity funds used during construction..................................... -- -- (5,209) Deferred income taxes -- net ...................... (26,374) (55,278) (12,717) Deferred investment tax credit -- net ............. (27,628) (27,630) (27,630) Changes in certain current assets and liabilities: Accounts receivable -- net ........................ (56,490) (11,069) (33,044) Accrued utility revenues .......................... (9,181) (3,089) (1,951) Materials, supplies and fossil fuel ............... (2,797) 7,793 11,945 Other current assets .............................. (2,166) (1,762) (4,928) Accounts payable .................................. 33,731 (56,710) 68,788 Accrued taxes ..................................... (26,059) (441) 3,500 Accrued interest .................................. (442) (7,455) (2,565) Other current liabilities ......................... (4,654) (3,997) (522) Other -- net ........................................ (29,641) 46,625 7,616 --------- --------- --------- Net cash provided ................................. 512,976 536,853 577,530 --------- --------- --------- Cash Flows from Investing: Capital expenditures ................................ (319,142) (307,876) (258,598) Capitalized interest ................................ (16,263) (16,208) (9,509) Other ............................................... (8,593) (15,982) (102) --------- --------- --------- Net cash used ..................................... (343,998) (340,066) (268,209) --------- --------- --------- Cash Flows from Financing: Long-term debt ...................................... 126,245 109,906 205,830 Short-term borrowings--net .......................... 48,080 113,850 (160,900) Common equity infusion from parent .................. 50,000 50,000 50,000 Dividends paid on common stock ...................... (170,000) (170,000) (170,000) Dividends paid on preferred stock ................... (10,279) (13,307) (17,416) Repayment of preferred stock ........................ (75,517) (47,201) (50,360) Repayment and reacquisition of long-term debt ....... (144,501) (240,004) (172,343) --------- --------- --------- Net cash used ..................................... (175,972) (196,756) (315,189) --------- --------- --------- Net increase (decrease) in cash and cash equivalents ... (6,994) 31 (5,868) Cash and cash equivalents at beginning of year ......... 12,552 12,521 18,389 --------- --------- --------- Cash and cash equivalents at end of year ............... $ 5,558 $ 12,552 $ 12,521 ========= ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Interest (excluding capitalized interest) ......... $ 128,627 $ 141,991 $ 150,603 Income taxes ...................................... $ 235,475 $ 236,676 $ 158,553
See Notes to Financial Statements. 34 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF RETAINED EARNINGS YEAR ENDED DECEMBER 31, ------------------------------ 1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Retained earnings at beginning of year .......... $528,798 $460,106 $403,843 Add: Net income ................................ 255,247 251,493 243,471 -------- -------- -------- Total ........................................ 784,045 711,599 647,314 -------- -------- -------- Deduct: Dividends: Common stock (Notes 4 and 5) ................. 170,000 170,000 170,000 Preferred stock (at required rates) (Note 4).. 9,703 12,801 17,092 Other .......................................... 2,374 -- 116 -------- -------- -------- Total deductions ............................. 182,077 182,801 187,208 -------- -------- -------- Retained earnings at end of year ................ $601,968 $528,798 $460,106 ======== ======== ======== See Notes to Financial Statements. APS NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS We are Arizona's largest electric utility, with 799,000 customers. We provide wholesale or retail electric service to the entire state of Arizona, with the exception of Tucson and about one-half of the Phoenix area. ACCOUNTING RECORDS Our accounting records are maintained in accordance with generally accepted accounting principles (GAAP). The preparation of financial statements in accordance with GAAP requires the use of estimates by management. Actual results could differ from those estimates. REGULATORY ACCOUNTING We are regulated by the Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC). The accompanying financial statements reflect the rate-making policies of these commissions. We prepare our financial statements in accordance with Statement of Financial Accounting Standards (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. Our major regulatory assets are deferred income taxes (see Note 10) and rate synchronization cost deferrals (see "Rate Synchronization Cost Deferrals" in this Note). These items, combined with miscellaneous regulatory assets and liabilities, amounted to approximately $900 million at December 31, 1998 and $1.0 billion at December 31, 1997. Most of these items are included in "Deferred Debits" on the Balance Sheets. Under the 1996 regulatory agreement (see Note 3), the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that will end June 30, 2004. We record the accelerated portion of the regulatory asset amortization, approximately $120 million pretax in 1998 and 1997 and $60 million pretax in 1996, in depreciation and amortization expense on the Statements of Income. 35 APS NOTES TO FINANCIAL STATEMENTS During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be discontinued no later than when 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, which could result in write-downs or write-offs of physical and/or regulatory assets. Additionally, the EITF determined that regulatory assets should not be written off if they are to be recovered from a portion of the entity which continues to apply SFAS No. 71. Although rules have been proposed for transitioning generation services to competition, there are many unresolved issues. We continue to apply SFAS No. 71 to our generation operations. If rate recovery of regulatory assets is no longer probable, whether due to competition or regulatory action, we would be required to write off the remaining balance as an extraordinary charge to expense. COMMON STOCK All of the outstanding shares of our common stock are owned by Pinnacle West. See Note 4. UTILITY PLANT AND DEPRECIATION Utility plant is the term we use to describe the business property and equipment that supports electric service. 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 charge retired utility plant, plus removal costs less salvage realized, to accumulated depreciation. See Note 13 for information on a proposed accounting standard that impacts accounting for removal costs. We record depreciation on utility property on a straight-line basis. For the years 1996 through 1998 the rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 20%. The weighted-average rate for 1998 was 3.32%. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 50 years. CAPITALIZED INTEREST In 1997 we began capitalizing interest in accordance with SFAS No. 34, "Capitalization of Interest Cost." Capitalized interest represents the cost of debt funds used to finance construction of utility plant. Plant construction costs, including capitalized interest, are recovered in authorized rates 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 for 1998 was 6.88% and for 1997 was 7.25%. Prior to 1997 we accrued an allowance for funds used during construction (AFUDC). AFUDC represented the cost of debt and equity funds used to finance construction of utility plant. AFUDC did not represent current cash earnings. AFUDC has been calculated using a composite rate of 7.75% for 1996. REVENUES We record electric operating revenues on the accrual basis, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. 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). Beginning July 1, 1996, the deferrals are being amortized over an eight-year period in 36 APS NOTES TO FINANCIAL STATEMENTS accordance with the 1996 regulatory agreement (see Note 3). Prior to July 1, 1996, the deferrals were amortized over thirty-five year periods. Amortization of the deferrals is included in depreciation and amortization expense on the Statements of Income. NUCLEAR FUEL We charge nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method that is based on actual physical usage. We divide the cost of the fuel by the estimated number of thermal units that we expect to produce with that fuel. We then multiply that rate by the number of thermal units that we produce within the current period. This provides us with current period nuclear fuel expense. We also charge nuclear fuel expense for the permanent disposal of spent nuclear fuel. The United States Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel, and it charges us $0.001 per kWh of nuclear generation. See Note 12 for information about spent nuclear fuel disposal. In addition, Note 13 has information on nuclear decommissioning costs. REACQUIRED DEBT COSTS When we incur gains or losses on debt that we retire prior to maturity, we amortize those gains and losses over the remaining original life of the debt. In accordance with the 1996 regulatory agreement (see Note 3), the ACC accelerated our amortization of the regulatory asset for reacquired debt costs to an eight-year period that will end June 30, 2004. The accelerated portion of the regulatory asset amortization is included in depreciation and amortization expense in the Statements of Income. CASH AND CASH EQUIVALENTS For purposes of reporting cash flows, we define cash equivalents as highly liquid debt instruments that will mature in three months or less. RECLASSIFICATIONS We have reclassified certain prior year amounts for comparison purposes with 1998. 2. ACCOUNTING MATTERS In 1998 we adopted SFAS No. 130, "Reporting Comprehensive Income." This standard changes the reporting of certain items previously reported in the common stock equity section of the balance sheet. The effects of adopting SFAS No. 130 were not material to our financial statements. In November 1998, the Financial Accounting Standards Board's Emerging Issues Task Force issued EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," which is effective for us in 1999. EITF 98-10 requires energy trading contracts to be measured at fair value as of the balance sheet date with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes. We have evaluated the impact of this rule and believe the effects are not material to our financial statements. In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which is effective for us in 2000. 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. The standard also provides specific guidance for accounting for derivatives designated as hedging instruments. We are currently evaluating what impact this standard will have on our financial statements. 37 APS NOTES TO FINANCIAL STATEMENTS 3. REGULATORY MATTERS ELECTRIC INDUSTRY RESTRUCTURING STATE In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition in Arizona. The rules, as amended, became effective on August 10, 1998, and on December 10, 1998, the ACC adopted the amended rules without any modifications that would have a significant impact on us. We believe that certain provisions of the 1996 ACC rules and the amended rules are deficient and we have filed lawsuits to protect our legal rights regarding the 1996 rules and the amended rules. These lawsuits are pending but two related cases filed by other utilities have been partially decided in a manner adverse to those utilities' positions. On January 11, 1999, the ACC issued an order which stayed the amended rules, granted reconsideration of the decision to make the rules permanent, and directed the hearing division of the ACC to establish a procedural order for further action on these rules. The order also granted waivers from compliance with the rules for us, and all affected utilities. On February 5, 1999, the ACC Hearing Division issued recommendations for changes to the amended rules. The recommended changes to the amended rules were further modified by a Procedural Order of the ACC Hearing Division dated March 12, 1999. The recommended rules include the following major provisions: + They would apply to virtually all Arizona electric utilities regulated by the ACC, including APS. + Each utility must make at least 20% of its 1995 retail peak demand available for competitive generation supply. + The rules become effective when the ACC makes a final decision on each utility's stranded costs and unbundled rates (Final Decision Date) or January 1, 2001, whichever comes first. + Subject to the 20% requirement, all utility customers with single premise loads of one megawatt or greater will be eligible for competitive electric services on the Final Decision Date. Customers with single premise loads of 40 kilowatts or greater may aggregate loads to meet this one megawatt requirement. + When effective, residential customers will be phased in at 1 1/4% per quarter calculated beginning on January 1, 1999, subject to the 20% requirement above. + Electric service providers that get Certificates of Convenience and Necessity (CC&Ns) from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution. + Affected utilities must file ACC tariffs with separate pricing for electric services provided for noncompetitive services. + ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs (see "Stranded Costs" below). 38 APS NOTES TO FINANCIAL STATEMENTS + Absent an ACC waiver, prior to January 1, 2001, each affected utility must transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate. + Affiliate transaction rules prohibit a utility and its competitive electric affiliates from sharing certain assets, employees, and information. If approved by the ACC, the rules would be subject to the formal rulemaking process under Arizona statute. In compliance with statutory procedural requirements, ACC oral proceedings on the matter would be scheduled no sooner than 30 days after the proposed rules are published by the Secretary of State. We cannot currently predict when or if the amended rules will be further modified, when the stay of the amended rules will be lifted, or when retail electric competition will be introduced in Arizona. STRANDED COSTS On June 22, 1998, the ACC issued an Order on stranded cost determination and recovery. We believe that certain provisions of the stranded cost order are deficient and in August 1998, we filed two lawsuits to protect our legal rights relating to the order. On February 5, 1999, the ACC Hearing Division issued recommended changes to the June 1998 stranded cost order. These recommended changes were further amended by an ACC Procedural Order dated March 12, 1999. The recommended changes to the stranded cost order would be effective upon approval of the ACC. The recommended order, as amended on March 12, 1999, allows each affected utility to choose from five options for the recovery of stranded costs: + Net Revenues Lost Methodology is the difference between generation revenues under traditional regulation and generation revenues under competition. This option provides for declining recovery percentages for stranded costs over a five-year recovery period. Regulatory assets are to be fully recovered under their presently authorized amortization schedule. In accordance with a 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that ends June 30, 2004. + Divestiture/Auction Methodology allows a utility to divest all or substantially all of its generating assets, including regulatory assets associated with generation, in order to collect 100 percent of the difference between net sales price and book value of generating assets divested over a ten-year period, with no return on the unamortized balance. + Financial Integrity Methodology allows a utility "sufficient revenues to meet minimum financial ratios" for a period of ten years. + Settlement Methodology allows a settlement to be agreed upon by the ACC and a utility. + Any combination of the above if shown to be in the best interests of all affected parties. LEGISLATIVE INITIATIVES An Arizona joint legislative committee studied electric utility industry restructuring issues in 1996 and 1997. In conjunction with that study, the Arizona legislative counsel prepared memoranda in late 1997 related to the legal authority of the ACC to deregulate the Arizona electric utility industry. The memoranda raise a question as to the degree to which the ACC may, under the Arizona Constitution, deregulate any portion of the electric utility industry and allow rates to be determined by market forces. This latter 39 APS NOTES TO FINANCIAL STATEMENTS issue has been subsequently decided by lower courts in favor of the ACC in four separate lawsuits, two of which are unrelated. In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona. The law includes the following major provisions: + Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition; + describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; and + metering and meter reading services must be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one megawatt (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation. In addition, the Arizona legislature will review and make recommendations for the 1999 legislature on certain competitive issues. AGREEMENT WITH SALT RIVER PROJECT On April 25, 1998, we entered into a Memorandum of Agreement with Salt River Project in anticipation of, and to facilitate, the opening of the Arizona electric industry. The Agreement contains the following major components: + Both parties would amend the Territorial Agreement to remove any barriers to the provision of competitive electricity supply and non-distribution services. + Both parties would amend the Power Coordination Agreement to lower the price that we will pay Salt River Project for purchased power by approximately $17 million (pretax) during the first full year that the Agreement is effective and by lesser annual amounts during the next seven years. + Both parties agreed on certain legislative positions regarding electric utility restructuring at the state and federal level. Certain provisions of the Agreement (including those relating to the amendments of the Territorial Agreement and the Power Coordination Agreement) are affected by the timing of the introduction of competition. See "ACC Rules" above. On February 18, 1999, the ACC approved the Agreement. GENERAL We believe that further ACC decisions, legislation at the Arizona and federal levels, and perhaps amendments to the Arizona Constitution (which would require a vote of the people) will ultimately be required before significant implementation of retail electric competition can lawfully occur in Arizona. Until the manner of implementation of competition, including addressing stranded costs, is determined, we cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operation. 40 APS NOTES TO FINANCIAL STATEMENTS 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. FEDERAL The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. We do not expect these rules to have a material impact on our financial statements. Several electric utility reform bills have been introduced during recent congressional sessions, which as currently written would allow consumers to choose their electricity suppliers by 2000 or 2003. These bills, other bills that are expected to be introduced, and ongoing discussions at the federal level suggest a wide range of opinion that will need to be narrowed before any substantial restructuring of the electric utility industry can occur. 1996 REGULATORY AGREEMENT In April 1996, the ACC approved a regulatory agreement between the ACC Staff and us. The major provisions of this agreement are: + An annual rate reduction of approximately $48.5 million ($29 million after income taxes), or 3.4% on average for all customers except certain contract customers, effective July 1, 1996. + Recovery of substantially all of our present regulatory assets through accelerated amortization over an eight-year period that will end June 30, 2004, increasing annual amortization by approximately $120 million ($72 million after income taxes). See Note 1. + A formula for sharing future cost savings between customers and shareholders (price reduction formula), referencing a return on equity (as defined) of 11.25%. + A moratorium on filing for permanent rate changes prior to July 2, 1999, except under the price reduction formula and under certain other limited circumstances. + Infusion of $200 million of common equity into us by Pinnacle West, in annual payments of $50 million starting in 1996. Based on the price reduction formula, the ACC approved retail price decreases of approximately $17.6 million ($10.5 million after income taxes), or 1.2%, effective July 1, 1997, and approximately $17 million ($10 million after income taxes), or 1.1%, effective July 1, 1998. We expect to file with the ACC for another retail price decrease of approximately $10.8 million annually ($6.5 million after income taxes) to become effective July 1, 1999. The amount and timing of the price decrease are subject to ACC approval. This will be the last price decrease under the 1996 regulatory agreement. 41 APS NOTES TO FINANCIAL STATEMENTS 4. COMMON AND PREFERRED STOCKS On March 1, 1999, we redeemed all of our preferred stock. Common and preferred stock balances at December 31, 1998 and 1997 are shown below:
NUMBER OF SHARES PAR PAR VALUE CALL OUTSTANDING VALUE OUTSTANDING PRICE ----------------------- PER --------------------- PER AUTHORIZED 1998 1997 SHARE 1998 1997 SHARE(A) ---------- ---------- ---------- -------- --------- --------- --------- (THOUSANDS OF DOLLARS) Common Stock .......... 100,000,000 71,264,947 71,264,947 $ 2.50 $ 178,162 $ 178,162 -- ========== ========== ========= ========= Preferred Stock: Non-Redeemable: $1.10 ................ 160,000 139,030 145,559 $ 25.00 $ 3,476 $ 3,639 $ 27.50 $2.50 ................ 105,000 86,440 97,252 50.00 4,322 4,863 51.00 $2.36 ................ 120,000 32,520 38,506 50.00 1,626 1,925 51.00 $4.35 ................ 150,000 62,986 68,386 100.00 6,299 6,839 102.00 Serial preferred ..... 1,000,000 $2.40 Series A ..... 200,587 234,839 50.00 10,029 11,742 50.50 $2.625 Series C .... 214,895 231,572 50.00 10,745 11,579 51.00 $2.275 Series D .... 90,691 164,101 50.00 4,534 8,205 50.50 $3.25 Series E ..... 304,475 312,991 50.00 15,224 15,649 51.00 Serial preferred ..... 4,000,000(b) Adjustable rate -- Series Q ......... 295,851 352,851 100.00 29,585 35,285 (c) Serial preferred ..... 10,000,000 $1.8125 Series W ... -- 1,693,016 25.00 -- 42,325 ---------- ---------- --------- --------- Total ............ 1,427,475 3,339,073 $ 85,840 $ 142,051 ========== ========== ========= ========= Redeemable: Serial preferred: $10.00 Series U .... 94,011 291,098 $ 100.00 $ 9,401 $ 29,110 ========== ========== ========= =========
- ---------- (a) The actual call price per share is the indicated amount plus any accrued dividends. (b) This authorization also covers all outstanding redeemable preferred stock. (c) Dividend rate adjusted quarterly to 2% below that of certain United States Treasury securities, but in no event less than 6% or greater than 12% per annum. Redeemable at par. 42 APS NOTES TO FINANCIAL STATEMENTS We cannot pay common stock dividends or acquire shares of common stock if preferred stock dividends or sinking fund requirements are in arrears. Redeemable preferred stock transactions during each of the three years in the period ended December 31, 1998 are as follows:
NUMBER OF SHARES PAR VALUE OUTSTANDING OUTSTANDING ----------------------------- ------------------------------ (THOUSANDS OF DOLLARS) DESCRIPTION 1998 1997 1996 1998 1997 1996 - -------------------- -------- -------- -------- -------- -------- -------- Balance, January 1...... 291,098 530,000 750,000 $ 29,110 $ 53,000 $ 75,000 Retirements: $10.00 Series U...... (197,087) (118,902) (90,000) (19,709) (11,890) (9,000) $7.875 Series V...... -- (120,000) (130,000) -- (12,000) (13,000) -------- -------- -------- -------- -------- -------- Balance, December 31.... 94,011 291,098 530,000 $ 9,401 $ 29,110 $ 53,000 ======== ======== ======== ======== ======== ========
43 APS NOTES TO FINANCIAL STATEMENTS 5. LONG-TERM DEBT The following table presents long-term debt outstanding: DECEMBER 31 MATURITY INTEREST ----------------------- DATES (a) RATES 1998 1997 --------- ----- ---- ---- (THOUSANDS OF DOLLARS) First mortgage bonds 1998 7.625% $ -- $100,000 1999 7.625% 100,000 100,000 2000 5.75% 100,000 100,000 2002 8.125% 125,000 125,000 2004 6.625% 85,000 85,000 2020 10.25% 100,550 109,550 2021 9.5% 45,140 45,140 2021 9% 72,370 72,370 2023 7.25% 91,900 97,150 2024 8.75% 121,668 121,918 2025 8% 88,300 88,500 2028 5.5% 25,000 25,000 2028 5.875% 154,000 154,000 Unamortized discount and premium (6,482) (7,033) Pollution control bonds 2024-2033 Adjustable 456,860 439,990 rate (b) Collateralized loan 1999-2000 5.375% - 20,000 10,000 6.125% Unsecured note 2005 6.25% 100,000 -- Senior notes(c) 1999 6.72% 50,000 50,000 Senior notes(c) 2006 6.75% 100,000 100,000 Debentures 2025 10% 75,000 75,000 Bank loans 2003 Adjustable 125,000 150,000 rate (d) Capitalized lease obligation 1998-2001 7.48% (e) 11,612 15,645 ---------- ---------- Total long-term debt 2,040,918 2,057,230 Less current maturities 164,378 104,068 ---------- ---------- Total long-term debt less current maturities $1,876,540 $1,953,162 ========== ========== - ---------- (a) This schedule does not reflect the timing of redemptions that may occur prior to maturity. (b) The weighted-average rate for the years ended December 31, 1998 was 3.39% and for December 31, 1997 was 3.62%. Changes in short-term interest rates would affect the costs associated with this debt. 44 APS NOTES TO FINANCIAL STATEMENTS (c) We issued $150 million of first mortgage bonds ("senior note mortgage bonds") to the senior note trustee as collateral for the senior notes. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity, and redemption provisions as the senior notes. Our payments of principal, premium, and/or interest on the senior notes satisfy our corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When we repay all of our first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding. (d) The weighted-average rate at December 31, 1998 was 5.69% and at December 31, 1997 was 6.25%. Changes in short-term interest rates would affect the costs associated with this debt. (e) Represents the present value of future lease payments (discounted at an interest rate of 7.48%) on a combined cycle plant that was sold and leased back (see Note 9). Principal payments due on total long-term debt and sinking fund requirements over the next five years are: + $164.4 million in 1999 + $114.7 million in 2000 + $2.5 million in 2001 + $125 million in 2002 and + $125 million in 2003. First mortgage bondholders have a lien on substantially all utility plant assets (other than nuclear fuel, transportation equipment, and the combined cycle plant). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. These conditions did not exist at December 31, 1998. 6. LINES OF CREDIT We had committed lines of credit with various banks of $400 million at December 31, 1998 and 1997, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees at December 31, 1998 and 1997 for these lines of credit ranged from .07% to .15% per annum. We had long-term bank borrowings of $125 million outstanding at December 31, 1998, and $150 million outstanding at December 31, 1997. Our commercial paper borrowings outstanding were $178.8 million at December 31, 1998, and $130.8 million at December 31, 1997. The weighted average interest rate on commercial paper borrowings was 6.21% on December 31, 1998 and 6.27% on December 31, 1997. By Arizona statute, our short-term borrowings cannot exceed 7% of our total capitalization unless approved by the ACC. 7. 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, 1998 and 1997 due to their short maturities. We hold investments in debt and equity securities for purposes other than trading. The December 31, 1998 and 1997 fair values of these investments, which we determine by using quoted market values or by discounting cash flows at rates equal to our cost of capital, approximate their carrying amounts. 45 APS NOTES TO FINANCIAL STATEMENTS The carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.03 billion on December 31, 1998, with an estimated fair value of $2.11 billion. On December 31, 1997, the carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.04 billion, with an estimated fair value of $2.08 billion. The fair value estimates are based on quoted market prices of the same or similar issues. 8. JOINTLY-OWNED FACILITIES We share ownership of some of our generating and transmission facilities with other companies. The following table shows our interest in those jointly-owned facilities at December 31, 1998. Our share of operating and maintaining these facilities is included in the income statement in operations and maintenance expense. PERCENT CONSTRUCTION OWNED BY PLANT IN ACCUMULATED WORK IN COMPANY SERVICE DEPRECIATION PROGRESS -------- -------- ------------ ------------ (THOUSANDS OF DOLLARS) Generating Facilities: Palo Verde Nuclear Generating Station Units 1 and 3 29.1% $1,821,620 $670,403 $20,152 Palo Verde Nuclear Generating Station Unit 2 (see Note 9) 17.0% 568,184 224,502 9,839 Four Corners Steam Generating Station Units 4 and 5 15.0% 150,165 69,764 312 Navajo Steam Generating Station Units 1, 2, and 3 14.0% 203,356 90,237 25,560(a) Cholla Steam Generating Station Common Facilities (b) 62.8%(c) 67,513 37,096 267 Transmission Facilities: ANPP 500KV System 35.8%(c) 66,547 20,282 1,384 Navajo Southern System 31.4%(c) 26,918 17,285 21 Palo Verde-Yuma 500KV System 23.9%(c) 11,376 4,215 - Four Corners Switchyards 27.5%(c) 3,071 1,780 143 Phoenix-Mead System 17.1%(c) 36,324 536 - - ---------- (a) The construction costs at Navajo are primarily related to the installation of scrubbers required by environmental legislation. (b) Pacificorp owns Cholla Unit 4 and we operate the unit for them. The common facilities at the Cholla Plant are jointly-owned. (c) Weighted average of interests. 46 APS NOTES TO FINANCIAL STATEMENTS 9. LEASES In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. We account for these leases as operating leases. The gain of approximately $140.2 million was deferred and is being amortized to operations 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, an amount equal to the annual lease payments is included in rent expense. A regulatory asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis. The average amounts to be paid for the Palo Verde Unit 2 leases are as follows: YEAR (IN MILLIONS) - ---- 1999 $40.1 2000 46.3 2001-2015 49.0 In accordance with the 1996 regulatory agreement (see Note 3), the ACC accelerated our amortization of the regulatory asset for leases to an eight-year period that will end June 30, 2004. The accelerated amortization is included in depreciation and amortization expense on the Statements of Income. The balance of this regulatory asset at December 31, 1998 was $48.5 million. Lease expense was approximately $42 million in each of the years 1996 through 1998. We have a capital lease on a combined cycle plant, which we sold and leased back. The lease requires semiannual payments of $2.6 million through June 2001, and includes renewal and purchase options based on fair market value. The plant is included in plant in service at its original cost of $54.4 million; accumulated amortization at December 31, 1998 was $48.6 million. In addition, we lease certain land, buildings, equipment, and miscellaneous other items through operating rental agreements with varying terms, provisions, and expiration dates. Approximate miscellaneous lease expense was: + $9.6 million in 1998 + $7.8 million in 1997 and + $9.7 million in 1996. 47 APS NOTES TO FINANCIAL STATEMENTS Estimated future minimum lease commitments, excluding the Palo Verde and combined cycle leases, are as follows: YEAR (IN MILLIONS) - ---- 1999 $ 13 2000 13 2001 14 2002 14 2003 13 Thereafter 91 ------- Total future commitments $ 158 ======= 10. INCOME TAXES We are included in Pinnacle West's consolidated tax return. However, when Pinnacle West allocates income taxes to us, it does so based on our taxable income or loss alone. Because of a 1994 rate settlement agreement, we are amortizing almost all of our investment tax credits (ITCs) over 5 years (1995-1999). Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates. We have recorded a regulatory asset on our Balance Sheet in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily AFUDC equity. We amortize this amount as the differences reverse. We have been able to accelerate the amortization of the regulatory asset for income taxes to an eight-year period that will end June 30, 2004. This is a result of a 1996 regulatory agreement with the ACC. We are including this accelerated amortization in depreciation and amortization expense on the Statements of Income. The components of income tax expense are as follows: YEAR ENDED DECEMBER 31, ----------------------------------- 1998 1997 1996 --------- --------- --------- (THOUSANDS OF DOLLARS) Current: Federal .............................. $ 170,806 $ 187,701 $ 137,531 State ................................ 42,652 48,531 35,777 --------- --------- --------- Total current ...................... 213,458 236,232 173,308 Deferred ................................ (26,374) (55,278) (869) Change in valuation allowance ........... -- -- (11,848) Investment tax credit amortization ...... (27,628) (27,630) (27,630) --------- --------- --------- Total expense ...................... $ 159,456 $ 153,324 $ 132,961 ========= ========= ========= 48 APS NOTES TO FINANCIAL STATEMENTS Multiplying income before income taxes by the statutory federal income tax rate does not equal the amount recorded as income tax expense because of the following:
YEAR ENDED DECEMBER 31, -------------------------------- 1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Federal income tax expense at 35% statutory rate ....... $145,146 $141,686 $131,751 Increases (reductions) in tax expense resulting from: Tax under book depreciation ......................... 17,848 14,694 19,229 Investment tax credit amortization .................. (27,628) (27,630) (27,630) State income tax -- net of federal income tax benefit 23,024 23,160 20,790 Change in valuation allowance ....................... -- -- (10,269) Other ............................................... 1,066 1,414 (910) -------- -------- -------- Income tax expense ................................ $159,456 $153,324 $132,961 ======== ======== ========
The components of the net deferred income tax liability were as follows: DECEMBER 31, ----------------------- 1998 1997 ---------- ---------- (THOUSANDS OF DOLLARS) Deferred tax assets: Deferred gain on Palo Verde Unit 2 sale/leaseback $ 31,285 $ 33,257 Other ........................................... 74,292 77,412 ---------- ---------- Total deferred tax assets ..................... 105,577 110,669 ---------- ---------- Deferred tax liabilities: Plant related ................................... 1,112,897 1,096,222 Regulatory asset for income taxes ............... 161,836 185,084 Rate synchronization deferrals .................. 122,130 144,908 Other ........................................... 16,722 26,136 ---------- ---------- Total deferred tax liabilities ................ 1,413,585 1,452,350 ---------- ---------- Deferred income taxes -- net ....................... $1,308,008 $1,341,681 ========== ========== 11. RETIREMENT PLANS AND OTHER BENEFITS VOLUNTARY SEVERANCE PLAN We sponsored a voluntary severance plan in 1996. There was a pretax charge of $31.7 million in 1996 recorded mostly as operations and maintenance expense. This pretax charge included additional pension and postretirement benefit expense. Employees who participated in the plan were credited with an additional year of age and service when their pension and postretirement benefits were calculated. The additional expenses recorded in 1996 for this plan were $2.3 million for pension and $5.4 million for postretirement benefits. PENSION PLAN We sponsor a defined benefit pension plan for our employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The plan covers nearly all APS employees. Our employees do not contribute to this plan. Generally, we calculate the benefits under this 49 APS NOTES TO FINANCIAL STATEMENTS plan based on age, years of service, and pay. We fund the plan by contributing at least the minimum amount required under Internal Revenue Service regulations but no more than the maximum tax-deductible amount. The assets in the plan at December 31, 1998 were mostly domestic and international common stocks and bonds and real estate. Pension expense, including administrative and severance costs, was: + $9.8 million in 1998 + $8.7 million in 1997 and + $14.9 million in 1996. The following table shows the components of net pension cost before consideration of amounts capitalized or billed to others and excluding severance costs of $2.9 million in 1996: 1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Service cost -- benefits earned during the period................................ $ 24,126 $ 19,881 $ 22,861 Interest cost on projected benefit obligation ............................... 50,863 47,824 44,602 Expected return on plan assets ............. (53,883) (47,422) (41,958) Amortization of: Transition asset ...................... (3,216) (3,216) (3,216) Prior service cost .................... 2,063 2,063 1,727 Net actuarial losses .................. -- -- 721 -------- -------- -------- Net periodic pension cost .................. $ 19,953 $ 19,130 $ 24,737 ======== ======== ======== The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the balance sheets: 1998 1997 -------- -------- (THOUSANDS OF DOLLARS) Funded status -- Pension plan assets less than projected benefit obligation .................... $(38,957) $(87,208) Unrecognized net transition asset ................. (23,159) (26,376) Unrecognized prior service cost ................... 22,562 24,625 Unrecognized net actuarial losses/(gains) ......... (38,916) 16,989 -------- -------- Net pension amount recognized in the balance sheets........................................... $(78,470) $(71,970) ======== ======== 50 APS NOTES TO FINANCIAL STATEMENTS The following table sets forth the defined benefit pension plan's change in projected benefit obligation for the plan years 1998 and 1997: 1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Projected pension benefit obligation at beginning of year ............................ $ 699,600 $ 601,094 Service cost ...................................... 24,126 19,881 Interest cost ..................................... 50,863 47,824 Benefit payments .................................. (29,384) (29,741) Plan amendments ................................... -- 5,537 Actuarial losses/(gains) .......................... (23,976) 55,005 --------- --------- Projected pension benefit obligation at end of year................................... $ 721,229 $ 699,600 ========= ========= The following table sets forth the defined benefit pension plan's change in the fair value of plan assets for the plan years 1998 and 1997: 1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Fair value of pension plan assets at beginning of year ............................ $ 612,392 $ 533,444 Actual return on plan assets ...................... 85,764 87,583 Employer contributions ............................ 13,500 21,106 Benefit payments .................................. (29,384) (29,741) --------- --------- Fair value of pension plan assets at end of year .................................. $ 682,272 $ 612,392 ========= ========= We made the assumptions below to calculate the pension liability: Discount rate .................................. 7.00% 7.25% Rate of increase in compensation levels ........ 3.50% 4.50% Expected long-term rate of return on assets..... 10.00% 9.00% EMPLOYEE SAVINGS PLAN BENEFITS We also sponsor a defined contribution savings plan that is offered to nearly all APS employees. In a defined contribution plan, the benefits a participant is to receive result from regular contributions to a participant account. Under this plan, we make matching contributions to participant accounts. We recorded expenses for this plan of: + $3.9 million in 1998 + $3.7 million in 1997 and + $3.4 million in 1996. POSTRETIREMENT PLANS 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, 51 APS NOTES TO FINANCIAL STATEMENTS retirees do not make contributions to cover a portion of the plan costs. 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 postretirement benefit expense was: + $8.7 million for 1998 + $9.4 million for 1997 and + $15.8 million for 1996. The following table shows the components of net periodic postretirement benefit costs before consideration of amounts capitalized or billed to others and excluding severance costs of $9.6 million in 1996: 1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Service cost -- benefits earned during the period.................................. $ 7,676 $ 6,865 $ 7,974 Interest cost on accumulated benefit obligation ................................. 15,610 14,315 13,395 Expected return on plan assets ............... (12,001) (8,706) (6,696) Amortization of: Transition obligation .................... 7,652 7,652 8,223 Net actuarial gains ...................... (2,927) (2,647) (1,344) -------- -------- -------- Net periodic postretirement benefit cost ..... $ 16,010 $ 17,479 $ 21,552 ======== ======== ======== The following table shows a reconciliation of the funded status of the plan to the amounts recognized in the balance sheets: 1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Funded status -- postretirement plan assets less than accumulated benefit obligation ................ $ (21,912) $ (46,435) Unrecognized net obligation at transition ............ 107,134 114,787 Unrecognized net actuarial gains ..................... (86,131) (78,209) --------- --------- Net postretirement amount recognized in the balance sheets .............................. $ (909) $ (9,857) ========= ========= 52 APS NOTES TO FINANCIAL STATEMENTS The following table sets forth the postretirement benefit plan's change in accumulated benefit obligation for the plan years 1998 and 1997: 1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Accumulated postretirement benefit obligation at beginning of year ............................... $ 197,581 $ 179,550 Service cost ......................................... 7,676 6,865 Interest cost ........................................ 15,610 14,315 Benefit payments ..................................... (10,347) (6,732) Actuarial losses ..................................... 24,802 3,583 --------- --------- Accumulated postretirement benefit obligation at end of year ..................................... $ 235,322 $ 197,581 ========= ========= The following table sets forth the postretirement benefit plan's change in the fair value of plan assets for the plan years 1998 and 1997: 1998 1997 --------- --------- (THOUSANDS OF DOLLARS) Fair value of postretirement plan assets at beginning of year ............................... $ 151,146 $ 109,763 Actual return on plan assets ......................... 47,284 30,846 Employer contributions ............................... 25,327 17,269 Benefit payments ..................................... (10,347) (6,732) --------- --------- Fair value of postretirement plan assets at end of year ..................................... $ 213,410 $ 151,146 ========= ========= We made the assumptions below to calculate the postretirement liability: Discount rate ............................................ 7.00% 7.25% Expected long-term rate of return on assets - after tax .. 8.73% 7.75% Initial health care cost trend rate - under age 65........ 7.50% 8.00% Initial health care cost trend rate - age 65 and over..... 6.50% 7.00% Ultimate health care cost trend rate (reached in the year 2002) ............................. 5.00% 5.00% Assuming a 1% increase in the health care cost trend rate, the 1998 cost of postretirement benefits other than pensions would increase by approximately $5 million and the accumulated benefit obligation as of December 31, 1998 would increase by approximately $37 million. Assuming a 1% decrease in the health care cost trend rate, the 1998 cost of postretirement benefits other than pensions would decrease by approximately $4 million and the accumulated benefit obligations as of December 31, 1998 would decrease by approximately $32 million. 53 APS NOTES TO FINANCIAL STATEMENTS 12. COMMITMENTS AND CONTINGENCIES LITIGATION We are a party to various claims, legal actions, and complaints arising in the ordinary course of business. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial statements. PALO VERDE NUCLEAR GENERATING STATION Under the Nuclear Waste Policy Act, DOE was to develop the facilities necessary for the storage and disposal of spent fuel and to have the first such facility in operation by 1998. That facility was to be a permanent repository, but DOE has announced that such a repository now cannot be completed before 2010. In response to lawsuits filed over DOE's obligation to accept used nuclear fuel, the United States Court of Appeals for the D.C. Circuit has ruled that DOE had an obligation to begin accepting used nuclear fuel in 1998. However, the Court refused to issue an order compelling DOE to begin moving used fuel. Instead, the Court ruled that any damages to utilities should be sought under the standard contract signed between DOE and utilities, including APS. The United States Supreme Court has refused to grant review of the D.C. Circuit's decision. In July 1998, we filed a Petition for Review regarding DOE's obligation to begin accepting spent nuclear fuel. We have capacity in existing fuel storage pools at Palo Verde which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of Palo Verde through about 2002, and believe we could augment that wet storage with new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. We currently estimate that we will incur $113 million (in 1998 dollars) over the life of Palo Verde for our share of the costs related to the on-site interim storage of spent nuclear fuel. Beginning in 1999, we will accrue these costs as a component of fuel expense, meaning the charges will be accrued as the fuel is burned. During 1998, we recorded a liability and a regulatory asset of $35 million for on-site interim nuclear fuel storage costs related to nuclear fuel burned prior to 1999. We currently believe that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation beyond 2002. 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 and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per incident. Based upon our 29.1% interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $77 million, with an annual payment limitation of approximately $9 million. The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. FUEL AND PURCHASED POWER COMMITMENTS We are a party to various fuel and purchased power contracts with terms expiring from 1999 through 2020 that include required purchase provisions. We estimate our 1999 contract requirements to be about $132 million. However, this amount may vary significantly pursuant to certain provisions in such contracts that permit us to decrease our required purchases under certain circumstances. 54 APS NOTES TO FINANCIAL STATEMENTS We must reimburse certain coal providers for amounts incurred for coal mine reclamation. We estimate our share of the total obligation to be about $103 million. The portion of the coal mine reclamation obligation related to coal already burned is about $62 million at December 31, 1998 and is included in "Deferred Credits -- Other" in the Balance Sheet. A regulatory asset has been established for amounts not yet recovered from ratepayers. In accordance with the 1996 regulatory agreement (see Note 3), the ACC began accelerated amortization of our regulatory asset for coal mine reclamation costs over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the Statements of Income. The balance of the regulatory asset at December 31, 1998 was about $51 million. CONSTRUCTION PROGRAM Total capital expenditures in 1999 are estimated at $328 million. 13. NUCLEAR DECOMMISSIONING COSTS We recorded $11.4 million for decommissioning expense in each of the years 1998, 1997, and 1996. We estimate it will cost about $1.8 billion ($452 million in 1998 dollars) to decommission our 29.1% share of the three Palo Verde units. The decommissioning costs are expected to be incurred over a 14-year period beginning in 2024. We charge decommissioning costs to expense over each unit's operating license term and include them in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are recovered in rates. Our current estimates are based on a 1998 site-specific study for Palo Verde that assumes the prompt removal/dismantlement method of decommissioning. An independent consultant prepared this study for us. We are required to update the study every three years. To fund the costs we expect to incur to decommission the plant, we established external trusts in accordance with Nuclear Regulatory Commission (NRC) regulations. The trust accounts are reported in "Investments and Other Assets" in our Balance Sheets at their market value of $145.6 million at December 31, 1998 and $124.6 million at December 31, 1997. We invest the trust funds primarily in fixed-income securities and domestic stock and classify them as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation. In February 1996, the FASB issued an exposure draft, "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." This proposed standard would require the estimated present value of the cost of decommissioning and certain other removal costs to be recorded as a liability, along with an offsetting plant asset when a decommissioning or other removal obligation is incurred. The FASB has indicated that a revised exposure draft will be issued in 1999. 55 APS NOTES TO FINANCIAL STATEMENTS 14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) Quarterly financial information for 1998 and 1997 is as follows: ELECTRIC EARNINGS OPERATING OPERATING NET FOR QUARTER ENDED REVENUES INCOME(a) INCOME COMMON STOCK - ------------- --------- --------- ------ ------------ (THOUSANDS OF DOLLARS) 1998 March 31 $380,423 $ 63,541 $ 31,935 $ 29,057 June 30 441,715 81,299 52,184 49,749 September 30 740,734 155,079 133,193 130,846 December 31 443,526 70,892 37,935 35,892 1997 March 31 $379,021 $61,439 $28,645 $25,019 June 30 458,751 99,706 69,493 66,298 September 30 632,821 150,892 129,699 126,715 December 31 407,960 59,788 23,656 20,658 - ---------- (a) Our utility business is seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations. 56 APS NOTES TO FINANCIAL STATEMENTS 15. STOCK OPTIONS Our parent company, Pinnacle West Capital Corporation, offers several stock incentive plans for our officers, our parent company's officers, and key employees. The plans provide for the granting of new options or awards of up to 3.5 million shares at a price per option not less than fair market value on the date the option is granted. The plans also provide for the granting of any combination of stock appreciation rights or dividend equivalents. The awards outstanding under the various incentive plans at December 31, 1998 approximate 1,497,012 non-qualified stock options, 158,121 restricted shares, and no dividend equivalent shares, incentive stock options, or stock appreciation rights. The FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation," which was effective beginning in 1996. This statement encourages, but does not require, that a company record compensation expense based on the fair value method. We continue to recognize expense based on Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." If we had recorded compensation expense based on the fair value method, our net income would have been reduced to the following pro forma amounts: 1998 1997 1996 -------- -------- -------- (THOUSANDS OF DOLLARS) Net income As reported....................... $255,247 $251,493 $243,471 Pro forma (fair value method)..... $254,640 $251,142 $243,291 We did not consider compensation costs for stock options granted before January 1, 1995. Therefore, future reported net income may not be representative of this compensation cost calculation. In order to present 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: 1998 1997 1996 ------ ------ ------- Risk-free interest rate............. 4.54% 5.66% 5.77% Dividend growth..................... 3.03% 4.50% 4.50% Volatility.......................... 18.80% 15.63% 17.10% Expected life (months).............. 60 60 58 57 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Not applicable. ITEM 11. EXECUTIVE COMPENSATION Not applicable. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Not applicable. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Not applicable. 58 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K FINANCIAL STATEMENTS See the Index to Financial Statements in Part II, Item 8 on page 28. EXHIBITS FILED EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.1(a) -- 1999 Management Variable Incentive Plan 10.2(a) -- 1999 Senior Management Variable Incentive Plan 10.3(a) -- 1999 Officers Variable Incentive Plan 23.1 -- Consent of Deloitte & Touche LLP 27.1 -- Financial Data Schedule In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below:
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96 February 20, 1996 Report 3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95 Directors temporarily Report suspending Bylaws in part 3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93 restated as of May 25, 1988 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report 3.4 Certificates pursuant to 4.3 to Form S-3 1-4473 9-29-93 Sections 10-152.01 and Registration Nos. 10-016, Arizona Revised 33-33910 and 33-55248 by Statutes, establishing Series A means of September 24, through V of the Company's 1993 Form 8-K Report Serial Preferred Stock
59
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 3.5 Certificate pursuant to 4.4 to Form S-3 1-4473 9-29-93 Section 10-016, Arizona Registration Nos. Revised Statutes, establishing 33-33910 and 33-55248 by Series W of the Company's means of September 24, Serial Preferred Stock 1993 Form 8-K Report 4.1 Mortgage and Deed of Trust 4.1 to September 1992 1-4473 11-9-92 Relating to the Company's Form 10-Q Report First Mortgage Bonds, together with forty-eight indentures supplemental thereto 4.2 Forty-ninth Supplemental 4.1 to 1992 Form 10-K 1-4473 3-30-93 Indenture Report 4.3 Fiftieth Supplemental 4.2 to 1993 Form 10-K 1-4473 3-30-94 Indenture Report 4.4 Fifty-first Supplemental 4.1 to August 1, 1993 1-4473 9-27-93 Indenture Form 8-K Report 4.5 Fifty-second Supplemental 4.1 to September 30, 1993 1-4473 11-15-93 Indenture Form 10-Q Report 4.6 Fifty-third Supplemental 4.5 to Registration 1-4473 3-1-94 Indenture Statement No. 33-61228 by means of February 23, 1994 Form 8-K Report 4.7 Fifty-fourth Supplemental 4.1 to Registration 1-4473 11-22-96 Indenture Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report 4.8 Fifty-fifth Supplemental 4.8 to Registration 1-4473 4-9-97 Indenture Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report 4.9 Agreement, dated March 21, 4.1 to 1993 Form 10-K 1-4473 3-30-94 1994, relating to the filing of Report instruments defining the rights of holders of long-term debt not in excess of 10% of the Company's total assets
60
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 4.10 Indenture dated as of January 4.6 to Registration 1-4473 1-11-95 1, 1995 among the Company Statement Nos. 33-61228 and The Bank of New York, and 33-55473 by means of as Trustee January 1, 1995 Form 8-K Report 4.11 First Supplemental Indenture 4.4 to Registration 1-4473 1-11-95 dated as of January 1, 1995 Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report 4.12 Indenture dated as of 4.5 to Registration 1-4473 11-22-96 November 15, 1996 among Statements Nos. 33-61228, the Company and The Bank 33-55473, 33-64455 and of New York, as Trustee 333-15379 by means of November 19, 1996 Form 8-K Report 4.13 First Supplemental Indenture 4.6 to Registration 1-4473 11-22-96 Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report 4.14 Second Supplemental Indenture 4.10 to Registration 1-4473 4-9-97 dated as of April 1, 1997 Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report 4.15 Indenture dated as of January 4.10 to Registration 1-4473 1-16-98 15, 1998 among the Company Statement Nos. 333-15379 and The Chase Manhattan and 333-27551 by means Bank, as Trustee of January 13, 1998 Form 8-K Report 4.16 First Supplemental Indenture 4.3 to Registration 1-4473 1-16-98 dated as of January 15, 1998 Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report 4.17 Second Supplemental 4.3 to Registration 1-4473 2-22-99 Indenture dated as of Statement Nos. 333-27551 February 15, 1999 and 333-58445 by means of February 18, 1999 Form 8-K Report
61
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 4.18 Agreement of Resignation, 4.1 to September 25, 1995 1-4473 10-24-95 Appointment, Acceptance and Form 8-K Report Assignment dated as of August 18, 1995 by and among the Company, Bank of America National Trust and Savings Association and The Bank of New York 10.4 Two separate 10.2 to September 1991 1-4473 11-14-91 Decommissioning Trust Form 10-Q Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between the Company and Mellon Bank, N.A., as Decommissioning Trustee 10.5 Amendment No. 1 to 10.1 to 1994 Form 10-K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 1) dated as of December 1, 1994 10.6 Amendment No. 2 to 10.4 to 1996 Form 10-K 1-4473 3-28-97 Decommissioning Trust Report Agreement (PVNGS Unit 1) dated as of July 1, 1991 10.7 Amendment No. 1 to 10.2 to 1994 Form 10-K 1-4473 3-30-95 Decommissioning Trust Report Agreement (PVNGS Unit 3) dated as of December 1, 1994 10.8 Amendment No. 2 to 10.6 to 1996 Form 10-K 1-4473 3-28-97 Decommissioning Trust Report Agreement (PVNGS Unit 3) dated as of July 1, 1991
62
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.9 Amended and Restated 10.1 to Pinnacle West 1-8962 3-26-92 Decommissioning Trust 1991 Form 10-K Report Agreement (PVNGS Unit 2) dated as of January 31, 1992, among the Company, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2 10.10 First Amendment to Amended 10.2 to 1992 Form 10-K 1-4473 3-30-93 and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992 10.11 Amendment No. 2 to Amended 10.3 to 1994 Form 10-K 1-4473 3-30-95 and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of November 1, 1994 10.12 Amendment No. 3 to Amended 10.1 to June 1996 Form 1-4473 8-9-96 and Restated 10-Q Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 10.13 Amendment No. 4 to Amended 10.5 to 1996 Form 10-K 1-4473 3-28-97 and Restated Report Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992 10.14 Asset Purchase and Power 10.1 to June 1991 Form 1-4473 8-8-91 Exchange Agreement dated 10-Q Report September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991
63
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.15 Long-Term Power 10.2 to June 1991 Form 1-4473 8-8-91 Transactions Agreement dated 10-Q Report September 21, 1990 between the Company and PacifiCorp, as amended as of October 11, 1990 and as of July 8, 1991 10.16 Contract, dated July 21, 1984, 10.31 to Pinnacle West's 2-96386 3-13-85 with DOE providing for the Form S-14 Registration disposal of nuclear fuel and/or Statement high-level radioactive waste, ANPP 10.17 Amendment No. 1 dated 10.3 to 1995 Form 10-K 1-4473 3-29-96 April 5, 1995 to the Long-Term Report Power Transactions Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and the Company 10.18 Restated Transmission 10.4 to 1995 Form 10-K 1-4473 3-29-96 Agreement between PacifiCorp Report and the Company dated April 5, 1995 10.19 Contract among PacifiCorp, 10.5 to 1995 Form 10-K 1-4473 3-29-96 the Company and United Report States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995 10.20 Reciprocal Transmission 10.6 to 1995 Form 10-K 1-4473 3-29-96 Service Agreement between Report the Company and PacifiCorp dated as of March 2, 1994 10.21 Indenture of Lease with 5.01 to Form S-7 2-59644 9-1-77 Navajo Tribe of Indians, Four Registration Statement Corners Plant 10.22 Supplemental and Additional 5.02 to Form S-7 2-59644 9-1-77 Indenture of Lease, including Registration Statement amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant
64
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.23 Amendment and Supplement 10.36 to Registration 1-8962 7-25-85 No. 1 to Supplemental and Statement on Form 8-B of Additional Indenture of Lease, Pinnacle West Four Corners, dated April 25, 1985 10.24 Application and Grant of 5.04 to Form S-7 2-59644 9-1-77 multi-party rights-of-way and Registration Statement easements, Four Corners Plant Site 10.25 Application and Amendment 10.37 to Registration 1-8962 7-25-85 No. 1 to Grant of multi-party Statement on Form 8-B of rights-of-way and easements, Pinnacle West Four Corners Power Plant Site, dated April 25, 1985 10.26 Application and Grant of 5.05 to Form S-7 2-59644 9-1-77 Arizona Public Service Registration Statement Company rights-of-way and easements, Four Corners Plant Site 10.27 Application and Amendment 10.38 to Registration 1-8962 7-25-85 No. 1 to Grant of Arizona Statement on Form 8-B of Public Service Company Pinnacle West rights-of-way and easements, Four Corners Power Plant Site, dated April 25, 1985 10.28 Indenture of Lease, Navajo 5(g) to Form S-7 2-36505 3-23-70 Units 1, 2, and 3 Registration Statement 10.29 Application and Grant of 5(h) to Form S-7 2-36505 3-23-70 rights-of-way and easements, Registration Statement Navajo Plant 10.30 Water Service Contract 5(l) to Form S-7 2-39442 3-16-71 Assignment with the United Registration Statement States Department of Interior, Bureau of Reclamation, Navajo Plant
65
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.31 Arizona Nuclear Power 10.1 to 1988 Form 10-K 1-4473 3-8-89 Project Participation Report Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto 10.32 Amendment No. 13 dated as 10.1 to March 1991 Form 1-4473 5-15-91 of April 22, 1991, to Arizona 10-Q Report Nuclear Power Project Participation Agreement, dated August 23, 1973, among the Company, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles 10.33(c) Facility Lease, dated as of 4.3 to Form S-3 33-9480 10-24-86 August 1, 1986, between Registration Statement State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee
66
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.34(c) Amendment No. 1, dated as of 10.5 to September 1986 1-4473 12-4-86 November 1, 1986, to Facility Form 10-Q Report by Lease, dated as of August 1, means of Amendment No. 1986, between State Street 1 on December 3, 1986 Bank and Trust Company, as Form 8 successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee 10.35(c) Amendment No. 2 dated as of 10.3 to 1988 Form 10-K 1-4473 3-8-89 June 1, 1987 to Facility Lease Report 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 10.36(c) Amendment No. 3, dated as of 10.3 to 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 the Company, as Lessee 10.37 Facility Lease, dated as of 10.1 to November 18, 1986 1-4473 1-20-87 December 15, 1986, between Form 8-K Report State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and the Company, as Lessee 10.38 Amendment No. 1, dated as of 4.13 to Form S-3 1-4473 8-24-87 August 1, 1987, to Facility Registration Statement Lease, dated as of December No. 33-9480 by means of 15, 1986, between State Street August 1, 1987 Form 8-K Bank and Trust Company, as Report successor to The First National Bank of Boston, as Lessor, and the Company, as Lessee
67
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.39 Amendment No. 2, dated as of 10.4 to 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 the Company, as Lessee 10.40(a) Directors' Deferred 10.1 to June 1986 Form 1-4473 8-13-86 Compensation Plan, as 10-Q Report restated, effective January 1, 1986 10.41(a) Second Amendment to the 10.2 to 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Directors' Deferred Compensation Plan, effective as of January 1, 1993 10.42(a) Third Amendment to the 10.1 to September 1994 1-4473 11-10-94 Arizona Public Service Form 10-Q Company Directors' Deferred Compensation Plan effective as of May 1, 1993 10.43(a) Arizona Public Service 10.4 to 1988 Form 10-K 1-4473 3-8-89 Company Deferred Report Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively 10.44(a) Third Amendment to the 10.3 to 1993 Form 10-K 1-4473 3-30-94 Arizona Public Service Report Company Deferred Compensation Plan, effective as of January 1, 1993 10.45(a) Fourth Amendment to the 10.2 to September 1994 1-4473 11-10-94 Arizona Public Service Form 10-Q Report Company Deferred Compensation Plan effective as of May 1, 1993
68
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.46(a) Fifth Amendment to the 10.3 to 1997 Form 10-K 1-4473 3-28-97 Arizona Public Service Report Company Deferred Compensation Plan 10.47(a) Pinnacle West Capital 10.10 to 1995 Form 10-K 1-4473 3-29-96 Corporation, Arizona Public Report Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996 10.48(a) Arizona Public Service 10.11 to 1995 Form 10-K 1-4473 3-29-96 Company Supplemental Report Excess Benefit Retirement Plan as amended and restated on December 20, 1995 10.49(a) Pinnacle West Capital 10.7 to 1994 Form 10-K 1-4473 3-30-95 Corporation and Arizona Report Public Service Company Directors' Retirement Plan effective as of January 1, 1995 10.50(a) Arizona Public Service 10.1 to September 1997 1-4473 11-12-97 Company Director Form 10-K Report Equity Plan 10.51(a) Letter Agreement dated 10.6 to 1994 Form 10-K 1-4473 3-30-95 December 21, 1993, between Report the Company and William L. Stewart 10.52(a) Letter Agreement dated 10.8 to 1996 Form 10-K 1-4473 3-28-97 August 16, 1996 between Report the Company and William L. Stewart 10.53(a) Letter Agreement between 10.2 to September 1997 1-4473 11-12-97 the Company and Form 10-Q Report William L. Stewart
69
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.54(a) Letter Agreement, dated April 10.7 to 1988 Form 10-K 1-4473 3-8-89 3, 1978, between the Company Report and O. Mark DeMichele, regarding certain retirement benefits granted to Mr. DeMichele 10.55(a) Letter Agreement dated 10.9 to 1996 Form 10-K 1-4473 3-28-97 November 27, 1996 between Report the Company and George A. Schreiber, Jr. 10.56(a) Letter Agreement dated as 10.8 to 1995 Form 10-K 1-4473 3-29-96 of January 1, 1996 between Report the Company and Robert G. Matlock & Associates, Inc. for consulting services 10.57(a)(d) Key Executive Employment 10.3 to 1989 Form 10-K 1-4473 3-8-90 and Severance Agreement Report between the Company and certain executive officers of the Company 10.58(a)(d) Revised form of Key Executive 10.5 to 1993 Form 10-K 1-4473 3-30-94 Employment and Severance Report Agreement between the Company and certain executive officers of the Company 10.59(a)(d) Second revised form of Key 10.9 to 1994 Form 10-K 1-4473 3-30-95 Executive Employment and Report Severance Agreement between the Company and certain executive officers of the Company 10.60(a)(d) Key Executive Employment 10.4 to 1989 Form 10-K 1-4473 3-8-90 and Severance Agreement Report between the Company and certain managers of the Company
70
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.61(a)(d) Revised form of Key Executive 10.4 to 1993 Form 10-K 1-4473 3-30-94 Employment and Severance Report Agreement between the Company and certain key employees of the Company 10.62(a)(d) Second revised form of Key 10.8 to 1994 Form 10-K 1-4473 3-30-95 Executive Employment and Report Severance Agreement between the Company and certain key employees of the Company 10.63(a) Pinnacle West Capital 10.1 to 1992 Form 10-K 1-4473 3-30-93 Corporation Stock Option and Report Incentive Plan 10.64(a) Pinnacle West Capital A to the Proxy Statement 1-8962 4-16-94 Corporation 1994 Long-Term for the Plan Report Incentive Plan effective as of Pinnacle West 1994 March 23, 1994 Annual Meeting of Shareholders 10.65 Agreement No. 13904 (Option 10.3 to 1991 Form 10-K 1-4473 3-19-92 and Purchase of Effluent) Report with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23, 1973 10.66 Agreement for the Sale and 10.4 to 1991 Form 10-K 1-4473 3-19-92 Purchase of Wastewater Report Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981, including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4, 1986 10.67 Territorial Agreement 10.1 to March 1998 1-4473 5-15-98 between the Company Form 10-Q Report and Salt River Project
71
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 10.68 Power Coordination 10.2 to March 1998 1-4473 5-15-98 Agreement between Form 10-Q Report the Company and Salt River Project 10.69 Memorandum of Agreement 10.3 to March 1998 1-4473 5-15-98 between the Company and Form 10-Q Report Salt River Project 10.70 Addendum to Memorandum of 10.2 to May 19, 1998 1-4473 6-26-98 Agreement between the Form 8-K Report Company and Salt River Project dated as of May 19, 1998 99.1 Collateral Trust Indenture 4.2 to 1992 Form 10-K 1-4473 3-30-93 among PVNGS II Funding Report Corp., Inc., the Company and Chemical Bank, as Trustee 99.2 Supplemental Indenture to 4.3 to 1992 Form 10-K 1-4473 3-30-93 Collateral Trust Indenture Report among PVNGS II Funding Corp., Inc., the Company and Chemical Bank, as Trustee 99.3(c) Participation Agreement, 28.1 to September 1992 1-4473 11-9-92 dated as of August 1, 1986, Form 10-Q Report among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein
72
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.4(c) Amendment No. 1 dated as of 10.8 to September 1986 1-4473 12-4-86 November 1, 1986, to Form 10-Q Report by Participation Agreement, means of Amendment No. dated as of August 1,1986, 1, on December 3, 1986 among PVNGS Funding Form 8 Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, the Company, and the Equity Participant named therein 99.5(c) Amendment No. 2, dated as of 28.4 to 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, the Company, and the Equity Participant named therein 99.6(c) Trust Indenture, Mortgage, 4.5 to Form S-3 33-9480 10-24-86 Security Agreement and Registration Statement Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee
73
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.7(c) Supplemental Indenture No. 10.6 to September 1986 1-4473 12-4-86 1, dated as of November 1, Form 10-Q Report by 1986 to Trust Indenture, means of Amendment No. Mortgage, Security Agreement 1 on December 3, 1986 and Assignment of Facility Form 8 Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.8(c) Supplemental Indenture No. 2 4.4 to 1992 Form 10-K 1-4473 3-30-93 to Trust Indenture, Mortgage, Report Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.9(c) Assignment, Assumption and 28.3 to Form S-3 33-9480 10-24-86 Further Agreement, dated as Registration Statement of August 1, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.10(c) Amendment No. 1, dated as of 10.10 to September 1986 1-4473 12-4-86 November 1, 1986, to Form 10-Q Report by Assignment, Assumption and means of Amendment No. Further Agreement, dated as 1 on December 3, 1986 of August 1, 1986, between Form 8 the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee
74
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.11(c) Amendment No. 2, dated as of 28.6 to 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 the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.12 Participation Agreement, 28.2 to September 1992 1-4473 11-9-92 dated as of December 15, Form 10-Q Report 1986, among PVNGS Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, the Company, and the Owner Participant named therein 99.13 Amendment No. 1, dated as of 28.20 to Form S-3 1-4473 8-10-87 August 1, 1987, to Registration Statement Participation Agreement, No. 33-9480 by means of a dated as of December 15, November 6, 1986 Form 1986, among PVNGS Funding 8-K Report Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, the Company, and the Owner Participant named therein
75
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.14 Amendment No. 2, dated as of 28.5 to 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, the Company, and the Owner Participant named therein 99.15 Trust Indenture, Mortgage, 10.2 to November 18, 1986 1-4473 1-20-87 Security Agreement and Form 8-K Report Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.16 Supplemental Indenture No. 4.13 to Form S-3 1-4473 8-24-87 1, dated as of August 1, 1987, Registration Statement to Trust Indenture, Mortgage, No. 33-9480 by means of Security Agreement and August 1, 1987 Form 8-K Assignment of Facility Lease, Report 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
76
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.17 Supplemental Indenture No. 2 4.5 to 1992 Form 10-K 1-4473 3-30-93 to Trust Indenture, Mortgage, Report Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee 99.18 Assignment, Assumption and 10.5 to November 18, 1986 1-4473 1-20-87 Further Agreement, dated as Form 8-K Report of December 15, 1986, between the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.19 Amendment No. 1, dated as of 28.7 to 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 the Company and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee 99.20(c) Indemnity Agreement dated 28.3 to 1992 Form 10-K 1-4473 3-30-93 as of March 17, 1993 by the Report Company 99.21 Extension Letter, dated as of 28.20 to Form S-3 1-4473 8-10-87 August 13, 1987, from the Registration Statement signatories of the No. 33-9480 by means of a Participation Agreement to November 6, 1986 Form Chemical Bank 8-K Report 99.22 Arizona Corporation 28.1 to 1991 Form 10-K 1-4473 3-19-92 Commission Order dated Report December 6, 1991 99.23 Arizona Corporation 10.1 to June Form 10-Q 1-4473 8-12-94 Commission Order dated Report June 1, 1994
77
Exhibit No. Description Originally Filed as Exhibit: File No.(b) Date Effective - ----------- ----------- ---------------------------- ----------- -------------- 99.24 Rate Reduction Agreement 10.1 to December 4, 1995 1-4473 12-14-95 dated December 4, 1995 Form 8-K Report between the Company and the ACC Staff 99.25 Arizona Corporation 10.1 to March 1996 1-4473 5-14-96 Commission Order Form 10-Q Report dated April 24, 1996 99.26 Arizona Corporation 99.1 to 1996 Form 10-K 1-4473 3-28-97 Commission Order, Report Decision No. 59943, dated December 26, 1996, including the Rules regarding the introduction of retail competition in Arizona 99.27 Retail Electric Competition 10.1 to June 1998 1-4473 8-14-98 Rules Form 10-Q Report
78 - --------------- (a) Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. (b) Reports filed under File No. 1-4473 were filed in the office of the Securities and Exchange Commission located in Washington, D.C. (c) An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit. (d) Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional officers and key employees of the Company. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit. REPORTS ON FORM 8-K During the quarter ended December 31, 1998 and the period ended March 30, 1999, the Company filed the following Report on Form 8-K: Report dated December 1, 1998 relating to an order by the Arizona Supreme Court staying ACC hearings regarding our settlement agreement with the ACC Staff. Report dated December 9, 1998 relating to (1) a Notice of Withdrawal of Settlement filed by the ACC Staff, (2) terms of expiration of a memorandum of understanding, (3) ACC adoption of the amended rules, and (4) issues affecting the agreement with Salt River Project. Report dated January 11, 1999 relating to (i) the ACC hearing officers' recommended changes to the amended rules regarding the introduction of retail electric competition in Arizona and to the June 1998 stranded cost order and (ii) action by the Arizona Supreme Court vacating its order staying ACC hearings on the proposed settlement agreement and dismissing the Attorney General's action. Report dated February 18, 1999 comprised of Exhibits to the Company's Registration Statements (Registration Nos. 333-27551 and 333-58445) relating to the Company's offering of $125 million of Notes. 79 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Date: March 30, 1999 WILLIAM J. POST ------------------------------------------ (William J. Post, 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 30, 1999 - ----------------------------------------- and Director (William J. Post, Chief Executive Officer) GEORGE A SCHREIBER, JR. Principal Accounting Officer, March 30, 1999 - ----------------------------------------- Principal Financial Officer (George A. Schreiber, Jr.) and Director JACK E. DAVIS President and Director March 30, 1999 - ----------------------------------------- (Jack E. Davis) O. MARK DEMICHELE Director March 30, 1999 - ----------------------------------------- (O. Mark DeMichele) MICHAEL L. GALLAGHER Director March 30, 1999 - ----------------------------------------- (Michael L. Gallagher) MARTHA O. HESSE Director March 30, 1999 - ----------------------------------------- (Martha O. Hesse) MARIANNE M. JENNINGS Director March 30, 1999 - ----------------------------------------- (Marianne M. Jennings) ROBERT E. KEEVER Director March 30, 1999 - ----------------------------------------- (Robert E. Keever)
80 ROBERT G. MATLOCK Director March 30, 1999 - ----------------------------------------- (Robert G. Matlock) BRUCE J. NORDSTROM Director March 30, 1999 - ----------------------------------------- (Bruce J. Nordstrom) JOHN R. NORTON III Director March 30, 1999 - ----------------------------------------- (John R. Norton III) DONALD M. RILEY Director March 30, 1999 - ----------------------------------------- (Donald M. Riley) QUENTIN P. SMITH, JR. Director March 30, 1999 - ----------------------------------------- (Quentin P. Smith, Jr.) WILLIAM L. STEWART President and Director March 30, 1999 - ----------------------------------------- (William L. Stewart) RICHARD SNELL Director March 30, 1999 - ----------------------------------------- (Richard Snell) DIANNE C. WALKER Director March 30, 1999 - ----------------------------------------- (Dianne C. Walker) BEN F. WILLIAMS JR. Director March 30, 1999 - ----------------------------------------- (Ben F. Williams, Jr.)
81 Commission File Number 1-4473 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------------- EXHIBITS TO FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 ----------------- Arizona Public Service Company (Exact name of registrant as specified in charter) - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- INDEX TO EXHIBITS Exhibit No. Description - ----------- ----------- 10.1a ___ 1999 Management Variable Incentive Plan 10.2a ___ 1999 Senior Management Variable Incentive Plan 10.3a ___ 1999 Officers Variable Incentive Plan 23.1 ___ Consent of Deloitte & Touche LLP 27.1 ___ Financial Data Schedule - --------------- (a) Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14. EX-10.1.A 2 1999 MANAGEMENT VARIABLE INCENTIVE PLAN Exhibit 10.1a Under the Company's 1999 Management Variable Incentive Plan, the Chief Executive Officer of the Company, with the approval of the Human Resources Committee of the Board of Directors, annually designates employees to participate in the program, establishes their participation level, and establishes certain financial and operational goals for the Company which must be satisfied in order for variable pay awards to be made. The impact, if any, of each employee's performance on his or her variable pay award is determined by his or her officer. Subject to final approval by the Human Resources Committee of the Board of Directors, the Chief Executive Officer of the Company also determines at year-end the degree to which those goals have been satisfied and the amount of variable pay to be awarded to participating employees, if any. EX-10.2.A 3 1999 SR. MANAGEMENT VARIABLE INCENTIVE PLAN Exhibit 10.2a Under the Company's 1999 Senior Management Variable Incentive Plan, the Chief Executive Officer of the Company, with the approval of the Human Resources Committee of the Board of Directors, annually designates employees to participate in the program, establishes their participation level, and establishes certain financial and operational goals for the Company which must be satisfied in order for variable pay awards to be made. The impact, if any, of each employee's performance on his or her variable pay award is determined by his or her officer. Subject to final approval by the Human Resources Committee of the Board of Directors, the Chief Executive Officer of the Company also determines at year-end the degree to which those goals have been satisfied and the amount of variable pay to be awarded to participating employees, if any. EX-10.3.A 4 1999 OFFICERS VARIABLE INCENTIVE PLAN Exhibit 10.3a Under the Company's 1999 Officers Variable Incentive Plan, the Chief Executive Officer of the Company, with the approval of the Human Resources Committee of the Board of Directors, annually designates the officers who will participate in the program, establishes their participation level, and establishes certain financial and operational goals for the Company which must be satisfied in order for variable pay awards to be made. The impact, if any, of each officer's performance on his or her variable pay award is determined by the Chief Executive Officer of the Company, with the approval of the Human Resources Committee. Subject to final approval by the Human Resources Committee of the Board of Directors, the Chief Executive Officer also determines at year-end the degree to which those goals have been satisfied and the amount of variable pay to be awarded to participating officers, if any. EX-23.1 5 CONSENT OF DELOITTE & TOUCHE LLP INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-51085, 33-57822, 333-27551 and 333-58445 of Arizona Public Service Company on Form S-3 and in Registration Statement No. 333-46161 of Arizona Public Service Company on Form S-8 of our report dated March 4, 1999, appearing in this Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 1998. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona March 26, 1999 EX-27.1 6 FINANCIAL DATA SCHEDULE
UT 1,000 U.S. DOLLARS 12-MOS DEC-31-1998 JAN-01-1998 DEC-31-1998 1 PER-BOOK 4,730,563 183,549 414,531 1,064,656 0 6,393,299 178,162 1,195,625 601,968 1,975,755 9,401 85,840 1,876,540 0 0 178,830 164,378 0 0 0 2,102,555 6,393,299 2,006,398 192,207 1,443,380 1,635,587 370,811 20,448 391,259 136,012 255,247 9,703 245,544 170,000 116,213 512,976 0 0
-----END PRIVACY-ENHANCED MESSAGE-----