ITEM 1. BUSINESS
THE COMPANY
The Company was incorporated in 1920 under the laws of Arizona and is engaged principally in serving electricity in the State of Arizona. The principal executive offices of the Company are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000). The Company currently employs approximately 7,050 persons, which includes employees assigned to joint projects where the Company is project manager.
The Company serves approximately 654,000 customers in an area that includes all or part of 11 of Arizona's 15 counties. During 1993, no single purchaser or user of energy accounted for more than 3% of total electric revenues.
Pinnacle West owns all of the outstanding shares of the Company's common stock. Pursuant to a Pledge Agreement, dated as of January 31, 1990, between Pinnacle West and Citibank, N.A., as Collateral Agent (the "Pledge Agreement"), and as part of a restructuring of substantially all of its outstanding indebtedness, Pinnacle West granted certain of its lenders a security interest in all of the Company's outstanding common stock. Until the Collateral Agent and Pinnacle West receive notice of the occurrence and continuation of an Event of Default (as defined in the Pledge Agreement), Pinnacle West is entitled to exercise or refrain from exercising any and all voting and other consensual rights pertaining to the common stock. As to matters other than the election of directors, Pinnacle West agreed not to exercise or refrain from exercising any such rights if, in the Collateral Agent's judgment, such action would have a material adverse effect on the value of the common stock. After notice of an Event of Default, the Collateral Agent would have the right to vote the common stock.
INDUSTRY AND COMPANY ISSUES
The utility industry continues to experience a number of challenges. Depending on the circumstances of a particular utility, these may include (i) competition in general from numerous sources; (ii) effects of the National Energy Policy Act of 1992 (the "Energy Act"); (iii) difficulties in meeting government imposed environmental requirements; (iv) the necessity to make substantial capital outlays for transmission and distribution facilities; (v) uncertainty regarding projected electrical demand growth; (vi) controversies over electromagnetic fields; (vii) controversies over the safety and use of nuclear power; (viii) issues related to spent fuel and low level waste (see "Generating Fuel" below); and (ix) increasing costs of wages and materials.
The impact on the Company of other utility industry problems is discussed in this Item under "Environmental Matters." Also see "Water Supply" in this Item with respect to certain problems specific to the Company and other utilities.
COMPETITION
Certain territory adjacent to or within areas served by the Company is served by other investor-owned utilities (notably Tucson Electric Power Company serving electricity in the Tucson area, Southwest Gas Corporation serving gas throughout the state, and Citizens Utilities Company serving electricity and gas in various locations throughout the state) and a number of cooperatives, municipalities, electrical districts, and similar types of governmental organizations (principally SRP serving electricity in various areas in and around Phoenix).
The Company expects increased competition in the future, mostly with respect to large customers, from entities offering alternative sources of energy. In recent years, changing laws and governmental regulations, interest in self-generation, competition from nonregulated energy suppliers, and aggressive marketing from the gas industry are providing some utility customers with alternative sources to satisfy their energy needs. This may be increased as a result of the Energy Act which, among other things, removes certain previously existing barriers to entry into electric generation. The Energy Act also permits certain other parties to compete for resale customers currently served by a particular utility and to use that utility's transmission facilities in order to do so. The requirements with respect to implementation of the Energy Act have not yet been completely determined, so the Company cannot currently predict its impact on the Company's business and operations.
In order to remain competitive in this changing environment, the Company has determined that it must be a cost-effective supplier, provide excellent service, and be knowledgeable about its customers' businesses. The Company is concentrating on several areas which are key to the success of this strategy, including effectively managing its operating and maintenance expenses; reinforcing the importance of customer needs among Company employees; and working with customers to evaluate, recommend, and provide services which will optimize their efficiency.
CAPITAL STRUCTURE
The capital structure of the Company (which, for this purpose, includes short-term borrowings and current maturities of long-term debt) as of December 31, 1993 is tabulated below.
Amount Percentage ---------- ---------- (Thousands of Dollars) Long-Term Debt Less Current Maturities: First mortgage bonds................................ $1,729,070 Other............................................... 395,584 ---------- Total long-term debt less current maturities...... 2,124,654 50.7% ---------- Non-Redeemable Preferred Stock........................ 193,561 4.6 ---------- Redeemable Preferred Stock............................ 197,610 4.7 ---------- Common Stock Equity: Common stock, $2.50 par value, 100,000,000 shares authorized; 71,264,947 shares outstanding......... 178,162 Premiums and expenses............................... 1,037,681 Retained earnings................................... 307,098 ---------- Total common stock equity......................... 1,522,941 36.4 ---------- Total capitalization............................ 4,038,766 Current Maturities of Long-Term Debt.................. 3,179 .1 Short-Term Borrowings................................. 148,000 3.5 ---------- --------
Total........................................... $4,189,945 100.0% ========== ========
See Notes 3, 4, and 5 of Notes to Financial Statements in Item 8.
On March 1, 1994 the Company redeemed all of the outstanding shares of its $8.80 Cumulative Preferred Stock, Series K ($100 par value), in the amount of $14.21 million. On March 2, 1994, the Company issued $100 million of its First Mortgage Bonds, 65/8% Series due 2004 and applied the net proceeds to the repayment of short-term debt that had been incurred for the redemption of preferred stock and for general corporate purposes.
So long as any of the Company's first mortgage bonds are outstanding, the Company is required for each calendar year to deposit with the trustee under its Mortgage cash in a formularized amount related to net additions to the Company's mortgaged utility plant; however, the Company may satisfy all or any part of this "replacement fund" requirement by utilizing redeemed or retired bonds, net property additions, or property retirements. For 1993, the replacement fund requirement amounted to approximately $122 million. Many, though not all, of the bonds issued by the Company under the Mortgage are redeemable at their par value plus accrued interest with cash deposited by the Company in the replacement fund, subject in many cases to a period of time after the original issuance of the bonds during which they may not be so redeemed and/or to other restrictions on any such redemption. The cash deposited with the trustee by the Company in partial satisfaction of its 1993 replacement fund requirements will be used to redeem $60.264 million in aggregate principal amount of the Company's First Mortgage Bonds, 103/4% Series due 2019, at their principal amount plus accrued interest, on April 4, 1994.
RATES
STATE. The ACC has regulatory authority over the Company in matters relating to retail electric rates and the issuance of securities. See "Rate Case Settlement" in Note 2 of Notes to Financial Statements in Item 8 for a discussion of the December 1991 settlement of the Company's most recent retail rate case before the ACC.
FEDERAL. The Company's rates for wholesale power sales and transmission services are subject to regulation by the FERC. During 1993, approximately 8% of the Company's electric operating revenues resulted from such sales and charges. For most wholesale transactions regulated by the FERC, a fuel adjustment clause results in monthly adjustments for changes in the actual cost of fuel for generation and in the fuel component of purchased power expense.
ARIZONA CORPORATION COMMISSION PETITION
On May 1, 1990, the ACC approved the filing of a petition with the SEC requesting the SEC to revoke or modify the exemption of Pinnacle West under the Public Utility Holding Company Act of 1935 (the "Holding Company Act"). Pinnacle West and its subsidiaries, including the Company, are currently exempt from registration under the Holding Company Act. The SEC has the power to terminate Pinnacle West's exemption upon thirty days notice to Pinnacle West if it determines that a question exists as to whether the exemption may be detrimental to the public interest or the interests of investors or consumers. In the event of the exercise of such power by the SEC, if Pinnacle West were to file an application with the SEC during such thirty day period requesting an exemption order, Pinnacle West's exemption would remain in place until the SEC ruled on such application. If Pinnacle West ultimately were to have its exemption modified, conditioned, or revoked, the Company could be subject to SEC regulation in many aspects of its business, including those relating to securities issuances, diversification, and transactions among affiliates. In a series of responses to the ACC's petition and subsequent ACC letters to the SEC, Pinnacle West has asked the SEC to refuse to take the action requested by the ACC. The Company cannot predict what action, if any, the SEC may take with respect to the ACC petition. The Company does not believe that the revocation or modification of the Pinnacle West exemption under the Holding Company Act, if acted on by the SEC, would have a material adverse effect on the operations or financial position of the Company.
CONSTRUCTION PROGRAM
Although its plans are subject to change, the Company does not presently intend to construct any new major baseload generating units for at least the next ten years. Utility construction expenditures for the years 1994 through 1996 are therefore expected to be primarily for expanding transmission and distribution capabilities to meet customer growth, upgrading existing facilities, and environmental purposes. Construction expenditures, including expenditures for environmental control facilities, for the years 1994 through 1996 have been estimated as follows:
(MILLIONS OF DOLLARS)
BY YEAR BY MAJOR FACILITIES - ---------------------------- ---------------------------------------------- 1994 $279 Electric generation $271 1995 302 Electric transmission 92 1996 293 Electric distribution 390 ---- General facilities 121 $874 ---- ==== $874 ====
The amounts for 1994 through 1996 include expenditures for nuclear fuel but exclude capitalized interest costs and capitalized property taxes. The Company conducts a continuing review of its construction program. This program and the above estimates are subject to periodic revisions based upon changes in assumptions as to system reliability, system load growth, rates of inflation, the availability and timing of environmental and other regulatory approvals, the availability and costs of outside sources of capital, and changes in project construction schedules. During the years 1991 through 1993, the Company incurred approximately $641 million in construction expenditures and approximately $31 million in additional capitalized items.
ENVIRONMENTAL MATTERS
Pursuant to the Clean Air Act, the EPA has adopted regulations, applicable to certain federally-protected areas, that address visibility impairment that can be reasonably attributed to specific sources. In September 1991, the EPA issued a final rule that would limit sulfur dioxide emissions at NGS. Compliance with the emission limitation becomes applicable to NGS Units 1, 2, and 3 in 1997, 1998, and 1999, respectively. SRP, the NGS operating agent, has estimated a capital cost of $530 million, most of which will be incurred from 1995 through 1998, and annual operations and maintenance costs of approximately $10 million per unit, for NGS to meet these requirements. The Company will be required to fund 14% of these expenditures.
The Clean Air Act Amendments of 1990 (the "Amendments") became effective on November 15, 1990. The Amendments address, among other things, "acid rain," visibility in certain specified areas, toxic air pollutants, and the nonattainment of 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." On March 5, 1993, the EPA promulgated rules listing allowance allocations applicable to Company-owned plants, which allocations will begin in the year 2000. Based on those allocations, the Company will have sufficient allowances to permit continued operation of its plants at current levels without installing additional equipment. In addition, the Amendments require the EPA to set nitrogen oxides emissions limitations which would require certain plants to install additional pollution control equipment. On March 22, 1994, the EPA issued rules for nitrogen oxide emissions limitations which will require the Company to install additional pollution control equipment at Four Corners. In the year 2000 Four Corners must comply with either these or more stringent requirements which might be promulgated by the EPA. The EPA has until 1997 to set more stringent requirements. However, if Four Corners accelerates to 1997 compliance with these March 22 requirements, it can delay until 2008 compliance with any more stringent requirements which the EPA may set. The Company has not yet determined how it will proceed; however, the Company currently estimates the capital cost of complying by 1997 with the specified requirements will be approximately $16 million.
With respect to protection of visibility in certain specified areas, the Amendments require the EPA to complete a study by November 1995 concerning visibility impairment in those areas and identification of sources contributing to such impairment. Interim findings of this study have indicated that any beneficial effect on visibility as a result of the Amendments would be offset by expected population and industry growth. The EPA has established a "Grand Canyon Visibility Transport Commission" to complete a study by November 1995 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." Based on the recommendations of the Commission, the EPA may require additional emissions controls at various sources causing visibility impairment in the "Golden Circle of National Parks" and may limit economic development in several western states. The Company cannot currently estimate the capital expenditures, if any, which may be required as a result of the EPA studies and the Commission's recommendations.
With respect to hazardous air pollutants emitted by electric utility steam generating units, the Amendments require two studies. First, there will be a study to be completed by November 1994 of potential impacts of mercury emissions from such units and various other sources on public health and on the environment, including available control technologies. Second, the EPA will complete a general study by November 1995 concerning the necessity of regulating such units under the Amendments. Due to the lack of historical data, and because the Company cannot speculate as to the ultimate requirements by the EPA, the Company 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 related expenditures by the Company, such as permit fees, none of which the Company expects to have a material impact on its financial position.
GENERATING FUEL
Coal, nuclear, gas, and other contributions to total net generation of electricity by the Company in 1993, 1992, and 1991, and the average cost to the Company of those fuels (in dollars per MWh), were as follows:
Other includes oil and hydro generation.
The Company believes that Cholla has sufficient reserves of low sulfur coal committed to that plant for the next six years, the term of the existing coal contract, and sufficient reserves of low sulfur coal available for use to continue operating it for its useful life. The Company also believes that Four Corners and NGS have sufficient reserves of low sulfur coal available for use by those plants to continue operating them for at least thirty years. The current sulfur content of coal being used at Four Corners, NGS, and Cholla is 0.8%, 0.6%, and 0.4%, respectively. In 1993, average prices paid for coal supplied from reserves dedicated under the existing contracts were relatively stable, although applicable contract clauses permit escalations under certain conditions. 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 Tribe. See "Properties" in Item 2.
ITEM 2. PROPERTIES
The Company's present generating facilities have an accredited capacity aggregating 4,022,410 kw, comprised as follows:
Capacity(kw) ------------ Coal: Units 1, 2, and 3 at Four Corners, aggregating........... 560,000 15% owned Units 4 and 5 at Four Corners, representing.... 222,000 Units 1, 2, and 3 at Cholla Plant, aggregating........... 590,000 14% owned Units 1, 2, and 3 at the Navajo Plant, representing........................................... 315,000 ----------- 1,687,000 ===========
Gas or Oil: Two steam units at Ocotillo, two steam units at Saguaro, and one steam unit at Yucca, aggregating............... 468,400(1) Eleven combustion turbine units, aggregating............. 500,600 Three combined cycle units, aggregating.................. 253,500 ----------- 1,222,500 ===========
Nuclear: 29.1% owned or leased Units 1, 2, and 3 at Palo Verde, representing........................................... 1,108,710 =========== Other........................................................ 4,200 =========== - ---------- (1) West Phoenix steam units (96,300 kw) are currently mothballed. --------------
The Company's peak one-hour demand on its electric system was recorded on August 2, 1993 at 3,802,300 kw, compared to the 1992 peak of 3,796,400 kw recorded on August 17. Taking into account additional capacity then available to it under purchase power contracts as well as its own generating capacity, the Company's capability of meeting system demand on August 2, 1993, computed in accordance with accepted industry practices, amounted to 4,505,000 kw, for an installed reserve margin of 16.7%. The power actually available to the Company from its resources fluctuates from time to time due in part to planned outages and technical problems. The available capacity from sources actually operable at the time of the 1993 peak amounted to 4,099,500 kw, for a margin of 13.4%.
NGS and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Tribe. The risk with respect to enforcement of these easements and leases is not deemed by the Company to be material. The Company is dependent, however, in some measure upon the willingness and ability of the Navajo Tribe to honor its commitments. Certain of the Company's transmission lines and almost all of its contracted coal sources are also located on Indian reservations. See "Generating Fuel" in Item 1.
Operation of each of the three Palo Verde units requires an operating license from the NRC. Full power operating licenses for Units 1, 2, and 3 were issued by the NRC in June 1985, April 1986, and November 1987, respectively. The full power operating licenses, each valid for a period of approximately 40 years, authorize the Company, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.
On August 18, 1986 and December 19, 1986, the Company entered into a total of three sale and leaseback transactions under which it sold and leased back approximately 42% of its 29.1% ownership interest in Palo Verde Unit 2. The leases under each of the sale and leaseback transactions have initial lease terms expiring on December 31, 2015. Each of the leases also allows the Company to extend the term of the lease and/or to repurchase the leased Unit 2 interest under certain circumstances at fair market value. The leases in the aggregate require annual payments of approximately $40 million through 1999, approximately $46 million in 2000, and approximately $49 million through 2015 (see Note 7 of Notes to Financial Statements in Item 8).
See "Water Supply" in Item 1 with respect to matters having possible impact on the operation of certain of the Company's power plants, including Palo Verde.
The Company's construction plans are susceptible to changes in forecasts of future demand on its electric system and in its ability to finance its construction program. Although its plans are subject to change, the Company does not presently intend to construct any new major baseload generating units for at least the next ten years. Important factors affecting the Company's ability to delay the construction of new major generating units are continuing efforts to upgrade and improve the reliability of existing generating stations, system load diversity with other utilities, and continuing efforts in customer demand-side conservation and load management programs.
In addition to that available from its own generating capacity, the Company purchases electricity from other utilities under various arrangements. One of the most important of these is a long-term contract with SRP which may be canceled by SRP on three years' notice and which requires SRP to make available, and the Company to pay for, certain amounts of electricity that are based in large part on customer demand within certain areas now served by the Company pursuant to a related territorial agreement. The Company believes that the prices payable by it under the contract are fair to both parties. The generating capacity available to the Company pursuant to the contract was 302,000 kw until May 1993, at which time the capacity increased to 304,000 kw. In 1993, the Company received approximately 840,000 MWh of energy under the contract and paid approximately $40 million for capacity availability and energy received.
In September 1990, the Company and PacifiCorp entered into certain agreements relating principally to sales and purchases of electric power and electric utility assets, and in July 1991, after regulatory approvals, the Company sold Cholla 4 to PacifiCorp for approximately $230 million. As part of the transaction, PacifiCorp agreed to make a firm system sale to the Company for thirty years during the Company's summer peak season in the amount of 175 megawatts for the first five years, increasing thereafter, at the Company's option, up to a maximum amount equal to the rated capacity of Cholla 4. After the first five years, all or part of the sale may be converted to a one-for- one seasonal capacity exchange. PacifiCorp has the right to purchase from the Company up to 125 average megawatts of energy per year for thirty years. PacifiCorp and the Company also entered into a 100 megawatt one-for-one seasonal capacity exchange to be effective upon the latter of January 1, 1996 or the completion of certain new transmission projects. In addition, PacifiCorp agreed to pay the Company (i) $20 million upon commercial operation of 150 megawatts of peaking capacity constructed by the Company and (ii) $19 million in connection with the construction of transmission lines and upgrades that will afford PacifiCorp 150 megawatts of northbound transmission rights. In addition, PacifiCorp secured additional firm transmission capacity of 30 megawatts over the Company's system. In 1993, the Company received 401,475 MWh of energy from PacifiCorp under these transactions and paid approximately $19 million for capacity availability and the energy received, and PacifiCorp paid approximately $2.7 million for 144,171 MWh.
See "El Paso Electric Company Bankruptcy" in Note 10 of Notes to Financial Statements in Item 8 for a discussion of the filing by EPEC of a voluntary petition to reorganize under Chapter 11 of the Bankruptcy Code. EPEC has a joint ownership interest with the Company and others in Palo Verde and Four Corners Units 4 and 5.
See Notes 4 and 7 of Notes to Financial Statements in Item 8 with respect to property of the Company not held in fee or held subject to any major encumbrance.
GRAPHIC - ------- 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. SEE APPENDIX FOR DETAILED DESCRIPTION.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
PROPERTY TAXES
On June 29, 1990, a new Arizona state tax law was enacted, effective as of December 31, 1989, which adversely impacted the Company's earnings in tax years 1990 through 1993 by an aggregate amount of approximately $82 million, before income taxes. On December 20, 1990, the Palo Verde participants, including the Company, filed a lawsuit in the Arizona Tax Court, a division of the Maricopa County Superior Court, against the Arizona Department of Revenue, the Treasurer of the State of Arizona, and various Arizona counties, claiming, among other things, that portions of the new tax law are unconstitutional. (Arizona Public Service Company, et al. v. Apache County, et al., No. TX 90-01686 (Consol.), Maricopa County Superior Court). In December 1992, the court granted summary judgment to the taxing authorities, holding that the law is constitutional. The Company has appealed this decision to the Arizona Court of Appeals. The Company cannot currently predict the ultimate outcome of this matter.
See "Water Supply" and "Palo Verde Nuclear Generating Station" in Item 1 and "El Paso Electric Company Bankruptcy" in Note 10 of Notes to Financial Statements in Item 8 in regard to pending or threatened litigation and other disputes.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report, through the solicitation of proxies or otherwise.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE REGISTRANT
The Company's executive officers are as follows:
AGE AT NAME MARCH 1, 1994 POSITION(S) AT MARCH 1, 1994 - ---- ------------- ---------------------------- Richard Snell 63 Chairman of the Board of Directors (1) O. Mark De Michele 59 President and Chief Executive Officer(1) Jaron B. Norberg 56 Executive Vice President and Chief Financial Officer(1) William F. Conway 63 Executive Vice President, Nuclear Shirley A. Richard 46 Executive Vice President, Customer Service, Marketing and Corporate Relations William J. Post 43 Senior Vice President, Planning, Information and Financial Services Jan H. Bennett 46 Vice President, Customer Service Jack E. Davis 47 Vice President, Generation and Transmission Armando B. Flores 50 Vice President, Human Resources James M. Levine 44 Vice President, Nuclear Production Richard W. MacLean 47 Vice President, Environmental, Health and Safety E. C. Simpson 45 Vice President, Nuclear Support Jack A. Bailey 40 Assistant Vice President, Nuclear Engineering and Projects William J. Hemelt 40 Controller Nancy C. Loftin 40 Secretary and Corporate Counsel Nancy E. Newquist 42 Treasurer - ---------- (1) Member of the Board of Directors. ----------------------------------------
The executive officers of the Company 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 and exclusive of directorships) 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. Previously, he was Chairman of the Board (1989- 1992) and Chief Executive Officer (1989-1990) of Aztar Corporation and Chairman of the Board, President, and Chief Executive Officer of Ramada Inc. (1981-1989).
Mr. De Michele was elected President in September 1982 and became Chief Executive Officer as of January 1988.
Mr. Norberg was elected to his present position in July 1986.
Mr. Conway was elected to his present position in May 1989. Prior to that time he was Senior Vice President -- Nuclear of Florida Power & Light Company (1988-1989).
Ms. Richard was elected to her present position in January 1989.
Mr. Post was elected to his present position in June 1993. Prior to that time he was Vice President, Finance & Rates (since April 1987).
Mr. Bennett was elected to his present position in May 1991. Prior to that time he was Director, Customer Service (September 1990 to May 1991), and Manager, State Region -- Customer Service (January 1988 to September 1990).
Mr. Davis was elected to his present position in June 1993. Prior to that time he was Director, Transmission Systems (January 1993-June 1993); Director, Fossil Generation (June 1992-December 1992); Director, System Development and Power Operations (May 1990-May 1992); and Manager, Power Contracts (March 1979-May 1990).
Mr. Flores was elected to his present position in December 1991. Prior to that time, he was Director -- Human Resources (1990 to 1991) and Manager -- Employment (1989 to 1990) of GENCORP, Propulsion Division, Aerojet Group. He had previously held the position of Vice President -- Human Resources, AMFAC (1985 to 1988).
Mr. Levine was elected to his present position in September 1989. Prior to that time he was Executive Director, Operations Support, System Energy Resources, Inc. (June 1989-September 1989) and Executive Director, Nuclear Operations (January 1988-June 1989) of Arkansas Nuclear One, Arkansas Power and Light Company.
Mr. MacLean was elected to his present position in December 1991. Prior to that time he held the following positions at General Electric (General Electric's Corporate Environmental Programs): Manager, EHS Resource Development (January to December 1991); and Manager, Environmental Protection (February 1986 to January 1991).
Mr. Simpson was elected to his present position in February 1990. Prior to that time he was Director, Nuclear Operations Engineering and Projects (1988- 1990) at Florida Power Corporation.
Mr. Bailey was elected to his present position in July 1993. Prior to that time he was Director, Nuclear Engineering (1991-1993) and Assistant Plant Manager (1989 to 1991) at Palo Verde. Mr. Bailey was Superintendent of Operations of Virginia Electric and Power Company from 1986 to 1989.
Mr. Hemelt was elected to his present position in June 1993. Prior to that time he was Treasurer and Assistant Secretary.
Ms. Loftin was elected Secretary in April 1987 and became Corporate Counsel in February 1989.
Ms. Newquist was elected to her present position in June 1993. Prior to that time she was Assistant Treasurer (since October 1992). She is also Treasurer (since June 1990) and Vice President (since February 1994) of Pinnacle West. From May 1987 to June 1990, Ms. Newquist served as Pinnacle West's Director of Finance.
PART II
ITEM 5.
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. See "The Company" in Part I, Item 1 for information regarding the Pledge Agreement to which the common stock is subject.
The chart below sets forth the dividends declared on the Company's common stock for each of the four quarters for 1993 and 1992.
COMMON STOCK DIVIDENDS (THOUSANDS OF DOLLARS)
------------------------------------------------- Quarter 1993 1992 ------------------------------------------------- 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 3 and 4 of Notes to Financial Statements in Item 8 for restrictions on retained earnings available for the payment of dividends.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital needs consist primarily of construction expenditures and required repayments or redemptions of long-term debt and preferred stock. The capital resources available to meet these requirements include funds provided by operations and external financings.
Present construction plans exclude any major baseload generating plants for at least the next ten years. In general, most of the construction expenditures are for expanding transmission and distribution capabilities to meet customer growth, upgrading existing facilities, and environmental purposes. Construction expenditures are anticipated to be $279 million, $302 million, and $293 million for 1994, 1995, and 1996, respectively. These amounts include nuclear fuel expenditures, but exclude capitalized property taxes and capitalized interest costs.
In the 1991 through 1993 period, the Company funded all of its capital expenditures (construction expenditures and capitalized property taxes) with internally generated funds, after the payment of dividends. For the period 1994 through 1996, the Company currently estimates that it will fund substantially all of its capital expenditures with internally generated funds, after the payment of dividends.
During 1993, the Company redeemed or repurchased approximately $637 million of long-term debt and preferred stock, of which approximately $527 million was optional. Refunding obligations for preferred stock, long-term debt, a capitalized lease obligation, and certain anticipated early redemptions are expected to total approximately $187 million, $135 million, and $4 million for the years 1994, 1995, and 1996, respectively.
The Company currently expects to issue in 1994 a total of approximately $125 million of long-term debt (primarily first mortgage bonds) and approximately $125 million of preferred stock. Of this, the Company issued on March 2, 1994, $100 million of its First Mortgage Bonds, 65/8% Series due 2004, and applied the net proceeds to the repayment of short-term debt that had been incurred for the redemption of preferred stock and for general corporate purposes. The Company expects that substantially all of the net proceeds of the balance of the securities to be issued during 1994 will be used for the retirement of outstanding debt and preferred stock. On March 1, 1994, the Company redeemed all of the outstanding shares of its $8.80 Cumulative Preferred Stock, Series K ($100 Par Value) in the amount of $14.21 million. As of April 4, 1994, the Company will be redeeming all $60.264 million of its outstanding First Mortgage Bonds, 103/4% Series due 2019.
Provisions in the Company's mortgage bond indenture and articles of incorporation require certain coverage ratios to be met before the Company can issue additional first mortgage bonds or preferred stock. In addition, the mortgage bond indenture limits the amount of additional bonds which may be issued to a percentage of net property additions, to property previously pledged as security for certain bonds that have been redeemed or retired, and/ or to cash deposited with the mortgage bond trustee. After giving effect to the transactions described in the preceding paragraph, as of December 31, 1993, the Company estimates that the mortgage bond indenture and the articles of incorporation would have allowed it to issue up to approximately $1.20 billion and $986 million of additional first mortgage bonds and preferred stock, respectively.
The ACC has authority over the Company with respect to the issuance of long-term debt and equity securities. Existing ACC orders allow the Company to have up to approximately $2.6 billion in long-term debt and approximately $501 million of preferred stock outstanding at any one time.
Management does not expect any of the foregoing restrictions to limit the Company's ability to meet its capital requirements.
As of December 31, 1993, the Company had credit commitments from various banks totalling approximately $302 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. Commercial paper borrowings totalling $148 million were outstanding at the end of 1993.
OPERATING RESULTS
1993 Compared to 1992
Earnings in 1993 were $219.5 million compared to $214.3 million in 1992 for an increase of $5.2 million. The primary factor contributing to this increase was lower interest expense. Interest costs in 1993 were $18.3 million lower than 1992 due to the Company refinancing debt at lower rates, lower average debt balances, and lower interest rates on variable-rate debt. Partially offsetting the lower interest expense were increased taxes and higher operating expenses.
Operating revenues were up $16.6 million in 1993 on sales volumes of 20.1 million MWh compared to 20.6 million MWh in 1992. Although revenues increased $45.3 million due to customer growth in the residential and business classes, these increases were largely offset by milder than normal weather and reduced interchange sales to other utilities. Fuel and purchased power costs increased $15.5 million in 1993 due to Palo Verde outages and reduced power operations (see Note 10 of Notes to Financial Statements). Partially offsetting the $15.5 million increase were other miscellaneous items resulting in a net increase of $13.3 million over 1992. These increases are reflected currently in earnings because the Company does not have a fuel adjustment clause as part of its retail rate structure. The net result of operating revenues less fuel and purchased power expense was an increase of $3.3 million comparing 1993 to 1992.
Operations expense for 1993 increased $11.8 million over 1992 levels primarily due to the implementation of SFAS No. 106 and SFAS No. 112, which added $17.0 million to expense in 1993. Partially offsetting these factors were lower power plant operating costs, lower rent expense, and lower costs for an employee gainsharing plan.
1992 Compared to 1991
Earnings in 1992 were $214.3 million compared with a loss in 1991 of $256.1 million. This was primarily due to the after-tax write-offs of $407 million in 1991 resulting from a rate case settlement with the ACC (see "Rate Case Settlement" in Note 2 of Notes to Financial Statements). Excluding the effects of the write-offs, earnings increased by $63.4 million over 1991 earnings as a result of several factors, including higher revenues, lower interest costs, and lower operating expenses. Partially offsetting these factors were higher fuel and purchased power costs and higher maintenance expense.
Operating revenues were up $154.4 million during 1992 on sales volumes of 20.6 million MWh compared to 20.0 million MWh in 1991. The volume increase of $48.6 million was largely due to customer growth in residential and business customer classes and increased sales due to more normal weather as compared to 1991. A price-related increase of $85.9 million was largely due to an increase in retail base rates effective December 6, 1991 and a higher average price for interchange sales to other utilities. Also contributing to the increase in 1992 was $19.9 million reversal of a non-cash refund obligation recorded in December, 1991 (see Note 2 of Notes to Financial Statements).
Interest costs were $34.9 million lower in 1992 as compared to 1991 due to lower average debt balances resulting from the redemptions of outstanding debt in 1991 with proceeds from the sale of Cholla 4 and lower interest rates on both variable-rate debt and refinancings.
Fuel expenses increased in 1992 over 1991 by $13.4 million as a result of increased generation due to increased retail and interchange sales, and increased gas prices. These increases were partially offset by lower prices for coal and uranium. The increase in the purchased power component of fuel expenses was due to favorable market prices.
Operations expense was $15.3 million lower in 1992 as compared to 1991 primarily due to lower operating costs at Palo Verde, lower fossil plant overhaul costs, and other miscellaneous cost reductions. Partially offsetting these were an obligation recorded for an employee gainsharing plan and higher nuclear refueling outage costs.
Other Income
Net income reflects accounting practices required for regulated public utilities and represents a composite of cash and noncash items, including AFUDC, accretion income on Palo Verde Unit 3, and the reversal of a refund obligation related to the Palo Verde write-off, (see "Statement of Cash Flows" and Note 2 of Notes to Financial Statements). The Company recorded after-tax accretion income of $45.3 million, $40.7 million and $3.2 million in 1993, 1992 and 1991, respectively. The Company also recorded refund obligation reversals in electric operating revenues of $12.9 million after tax in each of the years 1993 and 1992, and $0.9 million in 1991. The Company will record the remaining after-tax accretion income and refund obligation reversal of $20.3 million and $5.6 million, respectively, by June 5, 1994.
PALO VERDE NUCLEAR GENERATING STATION
As the Company continues its investigation and analysis of the Palo Verde steam generators, certain corrective actions are being taken. These include chemical cleaning, operating the units at reduced temperatures, and for some periods, operating the units at 86% power. So long as three units are involved in mid-cycle outages and are operated at 86%, the Company will incur an average of approximately $2 million per month (before income taxes) for additional fuel and purchased power costs. See "Palo Verde Tube Cracks" in Note 10 of Notes to Financial Statements for a more detailed discussion.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Page -------- Report of Management................................................... 20
Independent Auditors' Report........................................... 21
Statements of Income for each of the three years in the period ended December 31, 1993.................................................... 22
Balance Sheets -- December 31, 1993 and 1992........................... 23
Statements of Retained Earnings for each of the three years in the period ended December 31, 1993........................................ 25
Statements of Cash Flows for each of the three years in the period ended December 31, 1993...................................................... 26
Notes to Financial Statements............................................ 27
Financial Statement Schedules for each of the three years in the period ended December 31, 1993
Schedule V -- Property, Plant and Equipment.......................... 41
Schedule VI -- Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment................................... 44
Schedule IX -- Short-Term Borrowings................................. 47
See Note 12 of Notes to Financial Statements for the selected quarterly financial data required to be presented in this Item.
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, based on management's best estimates and judgments, and giving due consideration to materiality. These financial statements have been audited by independent auditors and their report is included.
Management maintains and relies upon systems of internal accounting controls, which are periodically 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 Committee of the Board of Directors and the independent auditors on a timely basis.
The Audit 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 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.
O. MARK DE MICHELE JARON B. NORBERG O. Mark De Michele Jaron B. Norberg President and Executive Vice President and Chief Executive Officer Chief Financial Officer
INDEPENDENT AUDITORS' REPORT
Arizona Public Service Company:
We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 1993 and 1992 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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, 1993 and 1992 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth herein.
As discussed in Note 8 to the Financial Statements, the Company changed its method of accounting for income taxes effective January 1, 1993 to conform with Statement of Financial Accounting Standards No. 109.
Deloitte & Touche Phoenix, Arizona February 21, 1994
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
a. Accounting Records -- The accounting records are maintained in accordance with generally accepted accounting principles applicable to rate- regulated enterprises. The Company is regulated by the ACC and the FERC and the accompanying financial statements reflect the rate-making policies of these commissions.
b. Common Stock -- All of the outstanding shares of common stock of the Company are owned by Pinnacle West.
c. Cash and Cash Equivalents -- For purposes of the statements of cash flows, the Company considers all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.
d. Utility Plant and Depreciation -- Utility plant represents the buildings, equipment and other facilities used to provide electric service. The cost of utility plant includes labor, materials, contract services, other related items and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus costs of removal minus salvage realized, is charged to accumulated depreciation.
Depreciation on utility property is recorded on a straight-line basis. The applicable ACC approved rates for 1991 through 1993 ranged from 0.84% to 15.00% which resulted in annual composite rates of 3.37%.
e. Nuclear Decommissioning Costs -- In 1993, the Company recorded $6.5 million for decommissioning expense. Based on a more recent site-specific study to completely remove all facilities, the Company expects to record $11.4 million for decommissioning expense in 1994. The Company estimates it will cost approximately $2.1 billion ($407 million in 1993 dollars), over a thirteen year period beginning in 2023, to decommission its 29.1% interest in Palo Verde. Decommissioning costs are charged to expense over the respective unit's operating license term and included in the accumulated depreciation balance until Palo Verde is retired from service.
As required by the ACC, the Company has established external trust accounts into which quarterly deposits are made for decommissioning. As of December 31, 1993, the Company has deposited a total of $35.0 million. The trust accounts are included in "Investments and Other Assets" on the Company's balance sheet and have accumulated, with interest, a $44.7 million balance at December 31, 1993.
f. Revenues -- Revenues are recognized on the accrual basis and include estimated amounts for service rendered but unbilled at the end of each accounting period.
g. Allowance for Funds Used During Construction -- AFUDC represents the cost of debt and equity funds used to finance construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through related depreciation when completed projects are placed into commercial operation. AFUDC does not represent current cash earnings.
AFUDC has been calculated using composite rates of 7.20% for 1993; 10.00% for 1992; and 10.15% for 1991. The Company compounds AFUDC semiannually and ceases to accrue AFUDC when construction is completed and the property is placed in service.
h. Reacquired Debt Costs -- Gains and losses on reacquired debt are deferred and amortized over the remaining original life of the debt, consistent with ratemaking.
i. Nuclear Fuel -- Nuclear fuel cost is amortized to fuel expense based on the relationship of the quantity of heat produced in the current period to the total quantity of heat expected to be produced over the remaining life of the fuel.
Under Federal law, the DOE is responsible for the permanent disposal of spent nuclear fuel. The DOE assesses $.001 per kilowatt-hour of nuclear generation. This amount is charged to nuclear fuel expense and recovered through rates.
j. Palo Verde Cost Deferrals -- As authorized by the ACC, the Company deferred operating costs (excluding fuel) and financing costs for Palo Verde Units 2 and 3 (including their share of facilities common to all units) from the commercial operation date (September 1986 and January 1988, respectively) until the date the units
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
were included in a rate order (April 1988 and December 1991, respectively). The deferrals are being amortized and recovered in rates over thirty-five year periods.
k. Reclassification -- certain prior year balances have been reclassified to conform to the 1993 presentation.
2. REGULATORY MATTERS
RATE CASE SETTLEMENT
In December 1991, the Company and the ACC reached a settlement in a retail rate case that had been pending before the ACC since January 1990. The ACC authorized an annual net revenue increase of $66.5 million, or approximately 5.2%. In turn, the Company wrote off $577.1 million of costs associated with Palo Verde and recorded a refund obligation of $53.4 million. The after-tax impact of these adjustments reduced 1991 net income by $407 million. A discussion of the components of the disallowance follows.
Prudence Audit
The ACC closed its prudence audit of Palo Verde and the Company wrote off $142 million ($101.3 million after tax) of construction costs relating to Palo Verde Units 1, 2, and 3 and $13.3 million ($8.6 million after tax) of deferred costs relating to the prudence audit.
Interim or Temporary Revenues
The ACC removed the interim and temporary designation on $385 million of revenues collected by the Company from 1986 through 1991 that had been previously authorized for Palo Verde Units 1 and 2. The Company recorded a refund obligation to customers of $53.4 million ($32.3 million after tax) related to the Palo Verde write-off discussed above. The refund obligation has been used to reduce the amount of annual rate increase granted rather than require specific customer refunds and is being reversed over thirty months beginning December 1991. The after-tax refund obligation reversals recorded as electric operating revenue by the Company amounted to $0.9 million in 1991 and $12.9 million in each of the years 1992 and 1993 and will amount to $5.6 million after tax in 1994.
Temporary Excess Capacity -- Palo Verde Unit 3
The ACC deemed a portion of Palo Verde Unit 3 to be excess capacity and, accordingly, did not recognize the related Unit 3 costs for ratemaking purposes. This action effectively disallows for thirty months a return on approximately $475 million of the Company's investment in Unit 3. The Company recognized a charge of $181.2 million ($109.5 million after tax), representing the present value of the lost cash flow and to that extent temporarily discounted the carrying value of Unit 3.
In accordance with generally accepted accounting principles, the Company is recording over the thirty-month period accretion income on Unit 3 in the aggregate amount of the discount. The Company recorded after-tax accretion income of $3.2 million, $40.7 million, and $45.3 million in 1991, 1992, and 1993, respectively, and will record after-tax accretion income of $20.3 million in 1994.
In December 1991, the Company stopped deferring Unit 3 costs and recorded a $240.6 million ($155.3 million after tax) write-off of Unit 3 cost deferrals due to Unit 3 being deemed excess capacity. At that time the Company began amortizing to expense and recovering in rates the remaining $320 million balance of deferrals over a thirty-five year period as approved by the ACC.
Future Retail Rate Increase
The Company agreed not to file a new rate application before December 1993 and the ACC agreed to expedite the processing of a future rate application. The Company and the ACC also agreed on an average unit sales price ceiling of 9.585 cents per kilowatt-hour in this future rate application, if filed prior to January 1,
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
1995. The Company's 1993 average unit sales price was approximately 9 cents per kilowatt-hour. This ceiling may be adjusted for the effects of significant changes in laws, regulatory requirements, or the Company's cost of equity capital. Management believes that the unit sales price ceiling will not adversely impact the Company's future earnings and has not yet determined when a rate case may be filed.
Dividend Payments
The Company agreed to limit its annual common stock dividends to Pinnacle West to $170 million through December 1993.
SALE OF CHOLLA UNIT 4
In July 1991, the Company sold Cholla 4 to PacifiCorp for approximately $230 million. The resulting after-tax gain of approximately $20 million was deferred and is being amortized as a reduction to operations expense over a four year period in accordance with an ACC order. The transaction also provides for transmission access and electrical energy sales and exchanges between the Company and PacifiCorp.
If there were to be any arrearage in dividends on any of the Company's preferred stock or in the sinking fund requirements applicable to any of its redeemable preferred stock, the Company could not pay dividends on its common stock or acquire any shares thereof for consideration.
The redemption requirements for the above issues for the next five years are: 1994, $65,775,000; 1995, $13,525,000; 1996, $13,525,000; 1997, $13,525,000; and 1998, $13,525,000.
Aggregate annual payments due on long-term debt and for sinking fund requirements through 1998 are as follows: 1994, $3,179,000; 1995, $3,408,000; 1996, $3,512,000; 1997, $153,780,000; and 1998, $109,068,000.
The Company had approximately $370 million of variable-rate long-term debt outstanding at December 31, 1993. Changes in interest rates would affect the costs associated with this debt.
Substantially all utility plant (other than nuclear fuel, transportation equipment, and the combined cycle plant) is subject to the lien of the first mortgage bond indenture. The first mortgage bond indenture includes provisions which would restrict the payment of common stock dividends under certain conditions which did not exist at December 31, 1993.
5. LINES OF CREDIT
APS had committed lines of credit with various banks of $302 million at December 31, 1993 and 1992 which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees on these lines were 0.1875% per annum through April 29, 1992 and 0.25% thereafter through December 31, 1993. The Company had commercial paper borrowings outstanding of $148 million at December 31, 1993 and bank borrowings of $130 million at December 31, 1992.
In 1992, the Company also had a $70 million letter of credit commercial paper program. Under this program, which expired in November, 1993, the Company had $65 million of borrowings outstanding at December 31, 1992. The commitment fees for this program were 0.30% per year.
By Arizona statute, the Company's short-term borrowings cannot exceed 7% of total capitalization without the consent of the ACC.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
6. JOINTLY-OWNED FACILITIES
At December 31, 1993, the Company owned interests in the following jointly-owned electric generating and transmission facilities. The Company's share of related operating and maintenance expenses is included in Operating Expenses.
7. LEASES
In 1986, the Company entered into sale and leaseback transactions under which it sold approximately 42% of its share of Palo Verde Unit 2. The gain of approximately $140,220,000 has been deferred and is being amortized to operations expense over the original lease term. The leases are being accounted for as operating leases. The amounts paid each year approximate $40,134,000 through December 1999, $46,285,000 through December 2000 and $48,982,000 through December 2015. The leases include options to renew for two additional years and to purchase the property at 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 (totalling approximately $49 million at December 31, 1993) has been established for the difference between lease payments and rent expense calculated on a straight-line basis. Lease expense for 1993, 1992 and 1991 was $41,750,000, $45,838,000 and $45,633,000, respectively.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
The Company has a capital lease on a combined cycle plant which it sold and leased back. The lease requires semiannual payments of $2,582,000 through June 2001 and includes renewal and purchase options based on fair market value. This plant is included in plant in service at its original cost of $54,405,000; accumulated depreciation at December 31, 1993 was $37,315,000.
In addition, the Company also leases certain land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. Rent expense for 1993, 1992, and 1991 were approximately $11,096,000, $14,733,000 and $16,046,000, respectively. Annual future minimum rental commitments, excluding the Palo Verde and combined cycle leases, for the period 1994 through 1998 range between $11 million and $13 million. Total rental commitments after 1998 are estimated at $129 million.
8. INCOME TAXES
The Company is included in the consolidated income tax returns of Pinnacle West. Income taxes are allocated to the Company based on its separate company taxable income or loss. Approximately $17.3 million of income taxes were payable to Pinnacle West at December 31, 1993. Investment tax credits were deferred and are being amortized to other income over the estimated life of the related assets as directed by the ACC.
Effective January 1, 1993, the Company adopted the provisions of SFAS No. 109, which requires the use of the liability method in accounting for income taxes. Upon adoption the Company recorded deferred income tax liabilities related to the equity component of AFUDC, the debt component of AFUDC recorded net of tax, and other temporary differences for which deferred income taxes had not been provided. Deferred income tax balances were also adjusted for changes in tax rates. The adoption of SFAS No. 109 had no material effect on net income but increased deferred income tax liabilities by $585.3 million at December 31, 1993. Historically the FERC and ACC have allowed revenues sufficient to pay for these deferred tax liabilities, and, in accordance with SFAS No. 109, a regulatory asset has been established in a corresponding amount.
The components of income tax expense (benefit) are:
Year Ended December 31, -------------------------------- 1993 1992 1991 --------- --------- ---------- (Thousands of Dollars) Current: Federal................................... $ 69,243 $ 80,921 $ 39,446 State..................................... 23,915 23,141 11,010 --------- --------- ---------- Total current........................... 93,158 104,062 50,456 --------- --------- ---------- Deferred: Depreciation -- net....................... 58,844 75,931 56,478 Palo Verde cost deferral.................. (5,015) (5,015) 46,004 Alternative minimum tax................... 13,661 7,732 (10,565) Disallowed Palo Verde costs (including ITC).................................... -- -- (202,416) Refund obligation......................... 8,454 8,454 (20,591) Palo Verde accretion income............... 29,618 26,668 2,099 Loss on reacquired debt................... 4,288 10,266 (1,032) Palo Verde start-up costs................. (1,335) (28,976) (1,337) Investment tax credit -- net.............. (6,948) (6,804) (11,117) Other -- net.............................. (5,818) (10,963) (2,729) --------- --------- ---------- Total deferred.......................... 95,749 77,293 (145,206) --------- --------- ---------- Total................................. $ 188,907 $ 181,355 $ (94,750) ========= ========= ==========
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
Total income tax expense (benefit) differed from the amount computed by multiplying income before income taxes by the statutory federal income tax rate due to the following:
Year Ended December 31, -------------------------------- 1993 1992 1991 --------- --------- ---------- (Thousands of Dollars) Federal income tax expense (benefit) at statutory rate (35% in 1993, 34% in 1992 and 1991)................................. $ 153,753 $ 145,574 $(107,916) Increase (reductions) in tax expense resulting from: Tax under book depreciation............... 17,671 17,465 21,776 Palo Verde cost deferral.................. -- -- (4,063) Disallowed Palo Verde costs (including ITC).................................... -- -- 22,236 Investment tax credit amortization........ (6,922) (7,036) (11,117) State income tax -- net of federal income tax benefit............................. 27,005 27,036 (9,820) Other..................................... (2,600) (1,684) (5,846) --------- --------- ---------- Total................................. $ 188,907 $ 181,355 $ (94,750) ========= ========= ==========
The components of the net deferred income tax liability at December 31, 1993, were as follows (in thousands of dollars):
Deferred tax assets: Deferred gain on Palo Verde Unit 2 sale/leaseback.............. $ 66,754 Alternative minimum tax (can be carried forward indefinitely).. 35,514 Other.......................................................... 86,745 Valuation allowance............................................ (15,413) ----------- Total deferred tax assets.................................. 173,600 -----------
Deferred tax liabilities: Plant related.................................................. 751,520 Income taxes recoverable through future rates -- net........... 585,294 Palo Verde deferrals........................................... 158,424 Other.......................................................... 40,429 ----------- Total deferred tax liabilities............................. 1,535,667 -----------
Accumulated deferred income taxes -- net......................... $1,362,067 ===========
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
9. PENSION PLAN AND OTHER BENEFITS
Pension Plan
The Company has a defined benefit pension plan covering substantially all employees. Benefits are based on years of service and compensation using a final average pay plan benefit formula. The plan is funded on a current basis to the extent deductible under existing tax regulation. Plan assets consist primarily of domestic and international common stocks and bonds, and real estate. Pension cost, including administrative cost, for 1993, 1992 and 1991 was approximately $13,950,000, $14,022,000 and $10,590,000, respectively, of which approximately $6,516,000, $3,917,000 and $4,939,000, respectively, was charged to expense; the remainder was either capitalized as a component of construction costs or billed to owners of facilities for which the Company is operating agent.
The components of net periodic pension costs are as follows (in thousands of dollars):
A reconciliation of the funded status of the plan to the amounts recognized in the balance sheet is presented below (in thousands of dollars):
1993 1992 --------- --------- Plan assets at fair value............................... $ 417,938 $ 388,790 --------- --------- Less actuarial present value of benefit obligation: Accumulated benefit obligation, including vested benefits of $347,603 and $286,588................. 372,364 307,003 Effect of projected future compensation increases... 127,388 105,027 --------- --------- Total projected benefit obligation.............. 499,752 412,030 --------- --------- Plan assets less than projected benefit obligation...... (81,814) (23,240) Plus: Unrecognized net loss from past experience different from that assumed..................... 51,361 8,288 Unrecognized prior service cost................... 14,717 15,733 Unrecognized net transition asset................. (39,242) (42,458) --------- --------- Accrued pension liability included in other deferred credits............................................... $ (54,978) $ (41,677) ========= ========= Principal actuarial assumptions used were:
Discount rate....................................... 7.50% 8.25% Rate of increase in compensation levels............. 5.00% 5.00% Expected long-term rate of return on assets......... 9.50%(a) 9.50%
(a) The Company will assume a 9% rate of return on plan assets for computing the net periodic pension cost in 1994.
In addition to the defined benefit pension plan described above, the Company also sponsors two qualified defined contribution plans. Substantially all employees are eligible to participate in one or the other of these two
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
plans. Both plans provide for employee contributions and partial employer matching contributions after certain eligibility requirements are met. The cost of these plans for 1993, 1992 and 1991 was $6,283,000, $5,311,000 and $2,708,000, of which $3,006,000, $2,514,000 and $1,344,000 was charged to expense.
Postretirement Plans
The Company provides medical and life insurance benefits to its retired employees. Employees may become eligible for these retirement benefits based on years of service and age. The retiree medical insurance plan is contributory; the retiree life insurance plan is noncontributory. In accordance with the governing plan documents, the Company retains the right to change or eliminate these benefits.
During 1993, the Company adopted SFAS No. 106, which requires that the cost of postretirement benefits be accrued during the years that the employees render service. Prior to 1993, the costs of retiree benefits were recognized as expense when claims were paid. This change had the effect of increasing 1993 retiree benefit costs from approximately $6 million to $34 million; the amount charged to expense increased from approximately $2 million to $17 million for an increase of $15 million, including the amortization (over 20 years) of the initial postretirement benefit obligation estimated at January 1, 1993 to be $183 million. Funding is based upon actuarially determined contributions that take into account the tax consequences.
The components of the postretirement benefit costs for 1993 are as follows (in thousands of dollars):
Service cost -- benefits earned during the period........... $ 9,510 Interest cost on accumulated benefit obligation............. 15,630 Net amortization and deferral............................... 9,146 ------------ Net periodic postretirement benefit cost.................... $ 34,286 ============
A reconciliation of the funded status of the plan to the amounts recognized in the balance sheet is presented below (in thousands of dollars):
Plan assets at fair value, funded at December 31, 1993........ $ 28,154 ------------ Less accumulated postretirement benefit obligation: Retirees.................................................. 49,296 Fully eligible plan participants.......................... 13,504 Other active plan participants............................ 137,113 ------------ Total accumulated postretirement benefit obligation... 199,913 ------------ Plan assets less than accumulated benefit obligation.......... (171,759) Plus: Unrecognized transition obligation...................... 173,773 Unrecognized net gain from past experience different from that assumed and from changes in assumptions..... (2,072) ------------ Accrued postretirement liability included in other deferred credits................................................... $ (58) ============
Principal actuarial assumptions used were: Discount rate............................................. 7.50% Initial health care cost trend rate -- under age 65....... 12.00% Initial health care cost trend rate -- age 65 and over.... 9.00% Ultimate health care cost trend rate (reached in the year 2003)........................... 5.50% Annual Salary increase for life insurance obligation...... 5.00%
Assuming a one percent increase in the health care cost trend rate, the Company's 1993 cost of postretirement benefits other than pensions would increase by $6.8 million and the accumulated benefit obligation as of December 31, 1993 would increase by $40.6 million.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
In 1993, the Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits." The new standard requires a change from a cash method to an accrual method in accounting for benefits (such as long-term disability) provided to former or inactive employees after employment but before retirement. The adoption of this new standard resulted in an increase in 1993 postemployment benefit costs of approximately $2 million.
10. COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
The Palo Verde participants have insurance for public liability payments 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 industrywide retrospective assessment program. The maximum assessment per reactor under the retrospective rating program for each nuclear incident is approximately $79 million, subject to an annual limit of $10 million per incident. Based upon the Company's 29.1% interest in the three Palo Verde units, the Company's maximum potential assessment per incident is approximately $69 million, with an annual payment limitation of $8.73 million. The insureds under this liability insurance include the Palo Verde participants and "any other person or organization with respect to his legal responsibility for damage caused by the nuclear energy hazard."
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. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
El Paso Electric Company Bankruptcy
The other joint owners in the Palo Verde and Four Corners facilities (see Note 6) include El Paso Electric Company, which currently is operating under Chapter 11 of the Bankruptcy Code. A plan whereby EPEC would become a wholly- owned subsidiary of Central and South West Corporation would resolve certain issues to which the Company could be exposed by the bankruptcy, including EPEC allegations regarding the 1989-90 Palo Verde outages. The plan has been confirmed by the bankruptcy court, but cannot become fully effective until several additional or related approvals are obtained. If they are not obtained, the plan could be withdrawn or terminate, thereby reintroducing the Company's exposures.
Palo Verde Tube Cracks
Tube cracking in the Palo Verde steam generators adversely affected operations in 1993, and will continue to do so in 1994 and probably into 1995, because of the cost of replacement power and maintenance expense associated with unit outages and corrective actions required to deal with the issue.
The operation of Palo Verde Unit 2 has been particularly affected by this issue. The Company has encountered axial tube cracking in the upper regions of the two steam generators in Unit 2. This form of tube degradation is uncommon in the industry and, in March 1993, led to a tube rupture and an outage of the unit that extended to September 1993, during which the unit was refueled. Unit 2 is currently completing a mid-cycle inspection outage which revealed further tube degradation. Unit 2 will have another mid-cycle inspection outage later in 1994.
The steam generators of Units 1 and 3 were inspected late in 1993, but did not show signs of axial cracking in their upper regions. All three units have, however, experienced cracking in the bottom of the steam generators of the types which are common in the industry.
Although its analysis is not yet completed, the Company believes that the axial cracking in Unit 2 is due to deposits on the tubes and to the relatively high temperatures at which all three units are now designed to
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
operate. The Company also believes that it can retard further tube degradation to acceptable levels by remedial actions which include chemically cleaning the generators and performing analyses and adjustments that will allow the units to be operated at lower temperatures without appreciably reducing their output. The temperature analyses should be concluded within the next several months. In the meantime, the lower temperatures will be achieved by operating the units at less than full power (86%).
Chemical cleaning was performed during Unit 2's current mid-cycle outage, and will be performed in the next refueling outage of Unit 3 (which will begin shortly) and of Unit 1 (which is scheduled for March 1995). The Company has concluded that Unit 1 can be safely operated until the 1995 outage and has submitted its supporting analysis to the NRC, but a mid-cycle inspection later in 1994 is possible.
As a result of these corrective actions, all three units should be returned to full power by mid-1995, and one or more of the units could be returned to full power during 1994. So long as the three units are involved in mid-cycle outages and are operated at 86%, the Company will incur additional fuel and purchased power costs averaging approximately $2 million per month (before income taxes).
Because of schedule changes associated with the tube issues and other circumstances, it now appears that all three units will be down for refueling outages at various times during 1995.
When significant cracks are detected during any outage, the affected tubes are taken out of service by plugging. That has occurred in a number of tubes in Unit 2, which is by far the most affected by cracking and plugging. The Company expects that this will slow considerably because of the foregoing remedial actions and that, while it may ultimately reach some limit on plugging, it can operate the present steam generators over a number of years.
Litigation
The Company is a party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the operations or financial position of the Company.
Construction Program
Expenditures in 1994 for the Company's continuing construction program have been estimated at $279 million, excluding capitalized property taxes and capitalized interest.
Fuel and Purchased Power Commitments
The Company is a party to various fuel and purchased power contracts with terms expiring from 1994 through 2020 that include required purchase provisions. The Company estimates its contract requirements during 1994 to be approximately $136 million. However, this amount may vary significantly pursuant to certain provisions in such contracts which permit the Company to decrease its required purchases under certain circumstances.
11. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Other taxes charged to operations during each of the three years in the period ended December 31, 1993 are as follows:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
ELECTRIC OPERATING OPERATING NET EARNINGS FOR QUARTER(a) REVENUES INCOME INCOME COMMON STOCK - ---------------- ------------ ------------ ------------ ---------------- (THOUSANDS OF DOLLARS) First $371,303 $ 79,441 $ 47,166 $ 39,277 Second 407,375 92,264 61,364 53,716 Third 524,483 132,639 102,911 95,617 Fourth 383,129 68,144 38,945 30,936
First $344,947 $ 70,867 $ 30,911 $ 22,587 Second 409,012 101,222 62,773 54,680 Third 516,960 138,947 108,158 100,048 Fourth 398,760 81,222 44,963 37,038
(a) The Company's operations are subject to seasonal fluctuations with variations occurring in energy usage by customers from season to season and from month to month within a season, primarily as a result of weather conditions. For this and other reasons, the results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company estimates that the carrying amounts of its cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 1993 and 1992 due to their short maturities. The December 31, 1993 and 1992 fair values of debt and equity investments, determined by using quoted market values or by discounting cash flows at rates equal to its cost of capital, approximate their carrying amounts.
On December 31, 1993 the carrying amount of long-term debt liabilities (excluding $30 million of capital lease obligations) was $2.098 billion and its estimated fair value was approximately $2.257 billion. On December 31, 1992 the carrying amount of long-term debt (excluding $32 million of capital lease obligations) was $2.115 billion and its estimated fair value was approximately $2.226 billion. The fair value estimates were determined by independent sources using quoted market rates where available. Where market prices were not available, the fair values were estimated by discounting future cash flows using rates available for debt of similar terms and remaining maturities. The carrying amounts of long-term debt bearing variable interest rates approximate their fair values at December 31, 1993 and 1992, respectively.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" in the Company's Proxy Statement relating to the annual meeting of shareholders to be held on April 19, 1994 (the "1994 Proxy Statement") and to the Supplemental Item -- "Executive Officers of the Registrant" in Part I of this report. During 1993, Mr. Woods, a Director of the Company, transferred shares of the Company's $2.625 Series C Preferred Stock directly owned by him to a trust under which he is a beneficiary and a trustee. This transfer technically required Mr. Woods to file with the SEC an amended securities ownership report (reflecting his indirect, rather than direct, ownership of the shares) and a new ownership report in his capacity as trustee under the trust. These reports were filed, but not within the required timeframe.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to the fourth paragraph under the heading "The Board and its Committees," and to "Executive Compensation," "Report of the Human Resources Committee," and "Performance Graphs" in the 1994 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Principal Holders of Voting Securities" and "Ownership of Pinnacle West Securities by Management" in the 1994 Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is hereby made to the last paragraph under the heading "The Board and its Committees" in the 1994 Proxy Statement.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See the Index to Financial Statements and Financial Statement Schedules in Part II, Item 8 on page 19.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital needs consist primarily of construction expenditures and required repayments or redemptions of long-term debt and preferred stock. The capital resources available to meet these requirements include funds provided by operations and external financings.
Present construction plans exclude any major baseload generating plants for at least the next ten years. In general, most of the construction expenditures are for expanding transmission and distribution capabilities to meet customer growth, upgrading existing facilities, and environmental purposes. Construction expenditures are anticipated to be $279 million, $302 million, and $293 million for 1994, 1995, and 1996, respectively. These amounts include nuclear fuel expenditures, but exclude capitalized property taxes and capitalized interest costs.
In the 1991 through 1993 period, the Company funded all of its capital expenditures (construction expenditures and capitalized property taxes) with internally generated funds, after the payment of dividends. For the period 1994 through 1996, the Company currently estimates that it will fund substantially all of its capital expenditures with internally generated funds, after the payment of dividends.
During 1993, the Company redeemed or repurchased approximately $637 million of long-term debt and preferred stock, of which approximately $527 million was optional. Refunding obligations for preferred stock, long-term debt, a capitalized lease obligation, and certain anticipated early redemptions are expected to total approximately $187 million, $135 million, and $4 million for the years 1994, 1995, and 1996, respectively.
The Company currently expects to issue in 1994 a total of approximately $125 million of long-term debt (primarily first mortgage bonds) and approximately $125 million of preferred stock. Of this, the Company issued on March 2, 1994, $100 million of its First Mortgage Bonds, 65/8% Series due 2004, and applied the net proceeds to the repayment of short-term debt that had been incurred for the redemption of preferred stock and for general corporate purposes. The Company expects that substantially all of the net proceeds of the balance of the securities to be issued during 1994 will be used for the retirement of outstanding debt and preferred stock. On March 1, 1994, the Company redeemed all of the outstanding shares of its $8.80 Cumulative Preferred Stock, Series K ($100 Par Value) in the amount of $14.21 million. As of April 4, 1994, the Company will be redeeming all $60.264 million of its outstanding First Mortgage Bonds, 103/4% Series due 2019.
Provisions in the Company's mortgage bond indenture and articles of incorporation require certain coverage ratios to be met before the Company can issue additional first mortgage bonds or preferred stock. In addition, the mortgage bond indenture limits the amount of additional bonds which may be issued to a percentage of net property additions, to property previously pledged as security for certain bonds that have been redeemed or retired, and/ or to cash deposited with the mortgage bond trustee. After giving effect to the transactions described in the preceding paragraph, as of December 31, 1993, the Company estimates that the mortgage bond indenture and the articles of incorporation would have allowed it to issue up to approximately $1.20 billion and $986 million of additional first mortgage bonds and preferred stock, respectively.
The ACC has authority over the Company with respect to the issuance of long-term debt and equity securities. Existing ACC orders allow the Company to have up to approximately $2.6 billion in long-term debt and approximately $501 million of preferred stock outstanding at any one time.
Management does not expect any of the foregoing restrictions to limit the Company's ability to meet its capital requirements.
As of December 31, 1993, the Company had credit commitments from various banks totalling approximately $302 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. Commercial paper borrowings totalling $148 million were outstanding at the end of 1993.
OPERATING RESULTS
1993 Compared to 1992
Earnings in 1993 were $219.5 million compared to $214.3 million in 1992 for an increase of $5.2 million. The primary factor contributing to this increase was lower interest expense. Interest costs in 1993 were $18.3 million lower than 1992 due to the Company refinancing debt at lower rates, lower average debt balances, and lower interest rates on variable-rate debt. Partially offsetting the lower interest expense were increased taxes and higher operating expenses.
Operating revenues were up $16.6 million in 1993 on sales volumes of 20.1 million MWh compared to 20.6 million MWh in 1992. Although revenues increased $45.3 million due to customer growth in the residential and business classes, these increases were largely offset by milder than normal weather and reduced interchange sales to other utilities. Fuel and purchased power costs increased $15.5 million in 1993 due to Palo Verde outages and reduced power operations (see Note 10 of Notes to Financial Statements). Partially offsetting the $15.5 million increase were other miscellaneous items resulting in a net increase of $13.3 million over 1992. These increases are reflected currently in earnings because the Company does not have a fuel adjustment clause as part of its retail rate structure. The net result of operating revenues less fuel and purchased power expense was an increase of $3.3 million comparing 1993 to 1992.
Operations expense for 1993 increased $11.8 million over 1992 levels primarily due to the implementation of SFAS No. 106 and SFAS No. 112, which added $17.0 million to expense in 1993. Partially offsetting these factors were lower power plant operating costs, lower rent expense, and lower costs for an employee gainsharing plan.
1992 Compared to 1991
Earnings in 1992 were $214.3 million compared with a loss in 1991 of $256.1 million. This was primarily due to the after-tax write-offs of $407 million in 1991 resulting from a rate case settlement with the ACC (see "Rate Case Settlement" in Note 2 of Notes to Financial Statements). Excluding the effects of the write-offs, earnings increased by $63.4 million over 1991 earnings as a result of several factors, including higher revenues, lower interest costs, and lower operating expenses. Partially offsetting these factors were higher fuel and purchased power costs and higher maintenance expense.
Operating revenues were up $154.4 million during 1992 on sales volumes of 20.6 million MWh compared to 20.0 million MWh in 1991. The volume increase of $48.6 million was largely due to customer growth in residential and business customer classes and increased sales due to more normal weather as compared to 1991. A price-related increase of $85.9 million was largely due to an increase in retail base rates effective December 6, 1991 and a higher average price for interchange sales to other utilities. Also contributing to the increase in 1992 was $19.9 million reversal of a non-cash refund obligation recorded in December, 1991 (see Note 2 of Notes to Financial Statements).
Interest costs were $34.9 million lower in 1992 as compared to 1991 due to lower average debt balances resulting from the redemptions of outstanding debt in 1991 with proceeds from the sale of Cholla 4 and lower interest rates on both variable-rate debt and refinancings.
Fuel expenses increased in 1992 over 1991 by $13.4 million as a result of increased generation due to increased retail and interchange sales, and increased gas prices. These increases were partially offset by lower prices for coal and uranium. The increase in the purchased power component of fuel expenses was due to favorable market prices.
Operations expense was $15.3 million lower in 1992 as compared to 1991 primarily due to lower operating costs at Palo Verde, lower fossil plant overhaul costs, and other miscellaneous cost reductions. Partially offsetting these were an obligation recorded for an employee gainsharing plan and higher nuclear refueling outage costs.
Other Income
Net income reflects accounting practices required for regulated public utilities and represents a composite of cash and noncash items, including AFUDC, accretion income on Palo Verde Unit 3, and the reversal of a refund obligation related to the Palo Verde write-off, (see "Statement of Cash Flows" and Note 2 of Notes to Financial Statements). The Company recorded after-tax accretion income of $45.3 million, $40.7 million and $3.2 million in 1993, 1992 and 1991, respectively. The Company also recorded refund obligation reversals in electric operating revenues of $12.9 million after tax in each of the years 1993 and 1992, and $0.9 million in 1991. The Company will record the remaining after-tax accretion income and refund obligation reversal of $20.3 million and $5.6 million, respectively, by June 5, 1994.
PALO VERDE NUCLEAR GENERATING STATION
As the Company continues its investigation and analysis of the Palo Verde steam generators, certain corrective actions are being taken. These include chemical cleaning, operating the units at reduced temperatures, and for some periods, operating the units at 86% power. So long as three units are involved in mid-cycle outages and are operated at 86%, the Company will incur an average of approximately $2 million per month (before income taxes) for additional fuel and purchased power costs. See "Palo Verde Tube Cracks" in Note 10 of Notes to Financial Statements for a more detailed discussion.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Page -------- Report of Management................................................... 20
Independent Auditors' Report........................................... 21
Statements of Income for each of the three years in the period ended December 31, 1993.................................................... 22
Balance Sheets -- December 31, 1993 and 1992........................... 23
Statements of Retained Earnings for each of the three years in the period ended December 31, 1993........................................ 25
Statements of Cash Flows for each of the three years in the period ended December 31, 1993...................................................... 26
Notes to Financial Statements............................................ 27
Financial Statement Schedules for each of the three years in the period ended December 31, 1993
Schedule V -- Property, Plant and Equipment.......................... 41
Schedule VI -- Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment................................... 44
Schedule IX -- Short-Term Borrowings................................. 47
See Note 12 of Notes to Financial Statements for the selected quarterly financial data required to be presented in this Item.
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, based on management's best estimates and judgments, and giving due consideration to materiality. These financial statements have been audited by independent auditors and their report is included.
Management maintains and relies upon systems of internal accounting controls, which are periodically 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 Committee of the Board of Directors and the independent auditors on a timely basis.
The Audit 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 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.
O. MARK DE MICHELE JARON B. NORBERG O. Mark De Michele Jaron B. Norberg President and Executive Vice President and Chief Executive Officer Chief Financial Officer
INDEPENDENT AUDITORS' REPORT
Arizona Public Service Company:
We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 1993 and 1992 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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, 1993 and 1992 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth herein.
As discussed in Note 8 to the Financial Statements, the Company changed its method of accounting for income taxes effective January 1, 1993 to conform with Statement of Financial Accounting Standards No. 109.
Deloitte & Touche Phoenix, Arizona February 21, 1994
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
a. Accounting Records -- The accounting records are maintained in accordance with generally accepted accounting principles applicable to rate- regulated enterprises. The Company is regulated by the ACC and the FERC and the accompanying financial statements reflect the rate-making policies of these commissions.
b. Common Stock -- All of the outstanding shares of common stock of the Company are owned by Pinnacle West.
c. Cash and Cash Equivalents -- For purposes of the statements of cash flows, the Company considers all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents.
d. Utility Plant and Depreciation -- Utility plant represents the buildings, equipment and other facilities used to provide electric service. The cost of utility plant includes labor, materials, contract services, other related items and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus costs of removal minus salvage realized, is charged to accumulated depreciation.
Depreciation on utility property is recorded on a straight-line basis. The applicable ACC approved rates for 1991 through 1993 ranged from 0.84% to 15.00% which resulted in annual composite rates of 3.37%.
e. Nuclear Decommissioning Costs -- In 1993, the Company recorded $6.5 million for decommissioning expense. Based on a more recent site-specific study to completely remove all facilities, the Company expects to record $11.4 million for decommissioning expense in 1994. The Company estimates it will cost approximately $2.1 billion ($407 million in 1993 dollars), over a thirteen year period beginning in 2023, to decommission its 29.1% interest in Palo Verde. Decommissioning costs are charged to expense over the respective unit's operating license term and included in the accumulated depreciation balance until Palo Verde is retired from service.
As required by the ACC, the Company has established external trust accounts into which quarterly deposits are made for decommissioning. As of December 31, 1993, the Company has deposited a total of $35.0 million. The trust accounts are included in "Investments and Other Assets" on the Company's balance sheet and have accumulated, with interest, a $44.7 million balance at December 31, 1993.
f. Revenues -- Revenues are recognized on the accrual basis and include estimated amounts for service rendered but unbilled at the end of each accounting period.
g. Allowance for Funds Used During Construction -- AFUDC represents the cost of debt and equity funds used to finance construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through related depreciation when completed projects are placed into commercial operation. AFUDC does not represent current cash earnings.
AFUDC has been calculated using composite rates of 7.20% for 1993; 10.00% for 1992; and 10.15% for 1991. The Company compounds AFUDC semiannually and ceases to accrue AFUDC when construction is completed and the property is placed in service.
h. Reacquired Debt Costs -- Gains and losses on reacquired debt are deferred and amortized over the remaining original life of the debt, consistent with ratemaking.
i. Nuclear Fuel -- Nuclear fuel cost is amortized to fuel expense based on the relationship of the quantity of heat produced in the current period to the total quantity of heat expected to be produced over the remaining life of the fuel.
Under Federal law, the DOE is responsible for the permanent disposal of spent nuclear fuel. The DOE assesses $.001 per kilowatt-hour of nuclear generation. This amount is charged to nuclear fuel expense and recovered through rates.
j. Palo Verde Cost Deferrals -- As authorized by the ACC, the Company deferred operating costs (excluding fuel) and financing costs for Palo Verde Units 2 and 3 (including their share of facilities common to all units) from the commercial operation date (September 1986 and January 1988, respectively) until the date the units
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
were included in a rate order (April 1988 and December 1991, respectively). The deferrals are being amortized and recovered in rates over thirty-five year periods.
k. Reclassification -- certain prior year balances have been reclassified to conform to the 1993 presentation.
2. REGULATORY MATTERS
RATE CASE SETTLEMENT
In December 1991, the Company and the ACC reached a settlement in a retail rate case that had been pending before the ACC since January 1990. The ACC authorized an annual net revenue increase of $66.5 million, or approximately 5.2%. In turn, the Company wrote off $577.1 million of costs associated with Palo Verde and recorded a refund obligation of $53.4 million. The after-tax impact of these adjustments reduced 1991 net income by $407 million. A discussion of the components of the disallowance follows.
Prudence Audit
The ACC closed its prudence audit of Palo Verde and the Company wrote off $142 million ($101.3 million after tax) of construction costs relating to Palo Verde Units 1, 2, and 3 and $13.3 million ($8.6 million after tax) of deferred costs relating to the prudence audit.
Interim or Temporary Revenues
The ACC removed the interim and temporary designation on $385 million of revenues collected by the Company from 1986 through 1991 that had been previously authorized for Palo Verde Units 1 and 2. The Company recorded a refund obligation to customers of $53.4 million ($32.3 million after tax) related to the Palo Verde write-off discussed above. The refund obligation has been used to reduce the amount of annual rate increase granted rather than require specific customer refunds and is being reversed over thirty months beginning December 1991. The after-tax refund obligation reversals recorded as electric operating revenue by the Company amounted to $0.9 million in 1991 and $12.9 million in each of the years 1992 and 1993 and will amount to $5.6 million after tax in 1994.
Temporary Excess Capacity -- Palo Verde Unit 3
The ACC deemed a portion of Palo Verde Unit 3 to be excess capacity and, accordingly, did not recognize the related Unit 3 costs for ratemaking purposes. This action effectively disallows for thirty months a return on approximately $475 million of the Company's investment in Unit 3. The Company recognized a charge of $181.2 million ($109.5 million after tax), representing the present value of the lost cash flow and to that extent temporarily discounted the carrying value of Unit 3.
In accordance with generally accepted accounting principles, the Company is recording over the thirty-month period accretion income on Unit 3 in the aggregate amount of the discount. The Company recorded after-tax accretion income of $3.2 million, $40.7 million, and $45.3 million in 1991, 1992, and 1993, respectively, and will record after-tax accretion income of $20.3 million in 1994.
In December 1991, the Company stopped deferring Unit 3 costs and recorded a $240.6 million ($155.3 million after tax) write-off of Unit 3 cost deferrals due to Unit 3 being deemed excess capacity. At that time the Company began amortizing to expense and recovering in rates the remaining $320 million balance of deferrals over a thirty-five year period as approved by the ACC.
Future Retail Rate Increase
The Company agreed not to file a new rate application before December 1993 and the ACC agreed to expedite the processing of a future rate application. The Company and the ACC also agreed on an average unit sales price ceiling of 9.585 cents per kilowatt-hour in this future rate application, if filed prior to January 1,
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
1995. The Company's 1993 average unit sales price was approximately 9 cents per kilowatt-hour. This ceiling may be adjusted for the effects of significant changes in laws, regulatory requirements, or the Company's cost of equity capital. Management believes that the unit sales price ceiling will not adversely impact the Company's future earnings and has not yet determined when a rate case may be filed.
Dividend Payments
The Company agreed to limit its annual common stock dividends to Pinnacle West to $170 million through December 1993.
SALE OF CHOLLA UNIT 4
In July 1991, the Company sold Cholla 4 to PacifiCorp for approximately $230 million. The resulting after-tax gain of approximately $20 million was deferred and is being amortized as a reduction to operations expense over a four year period in accordance with an ACC order. The transaction also provides for transmission access and electrical energy sales and exchanges between the Company and PacifiCorp.
If there were to be any arrearage in dividends on any of the Company's preferred stock or in the sinking fund requirements applicable to any of its redeemable preferred stock, the Company could not pay dividends on its common stock or acquire any shares thereof for consideration.
The redemption requirements for the above issues for the next five years are: 1994, $65,775,000; 1995, $13,525,000; 1996, $13,525,000; 1997, $13,525,000; and 1998, $13,525,000.
Aggregate annual payments due on long-term debt and for sinking fund requirements through 1998 are as follows: 1994, $3,179,000; 1995, $3,408,000; 1996, $3,512,000; 1997, $153,780,000; and 1998, $109,068,000.
The Company had approximately $370 million of variable-rate long-term debt outstanding at December 31, 1993. Changes in interest rates would affect the costs associated with this debt.
Substantially all utility plant (other than nuclear fuel, transportation equipment, and the combined cycle plant) is subject to the lien of the first mortgage bond indenture. The first mortgage bond indenture includes provisions which would restrict the payment of common stock dividends under certain conditions which did not exist at December 31, 1993.
5. LINES OF CREDIT
APS had committed lines of credit with various banks of $302 million at December 31, 1993 and 1992 which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees on these lines were 0.1875% per annum through April 29, 1992 and 0.25% thereafter through December 31, 1993. The Company had commercial paper borrowings outstanding of $148 million at December 31, 1993 and bank borrowings of $130 million at December 31, 1992.
In 1992, the Company also had a $70 million letter of credit commercial paper program. Under this program, which expired in November, 1993, the Company had $65 million of borrowings outstanding at December 31, 1992. The commitment fees for this program were 0.30% per year.
By Arizona statute, the Company's short-term borrowings cannot exceed 7% of total capitalization without the consent of the ACC.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
6. JOINTLY-OWNED FACILITIES
At December 31, 1993, the Company owned interests in the following jointly-owned electric generating and transmission facilities. The Company's share of related operating and maintenance expenses is included in Operating Expenses.
7. LEASES
In 1986, the Company entered into sale and leaseback transactions under which it sold approximately 42% of its share of Palo Verde Unit 2. The gain of approximately $140,220,000 has been deferred and is being amortized to operations expense over the original lease term. The leases are being accounted for as operating leases. The amounts paid each year approximate $40,134,000 through December 1999, $46,285,000 through December 2000 and $48,982,000 through December 2015. The leases include options to renew for two additional years and to purchase the property at 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 (totalling approximately $49 million at December 31, 1993) has been established for the difference between lease payments and rent expense calculated on a straight-line basis. Lease expense for 1993, 1992 and 1991 was $41,750,000, $45,838,000 and $45,633,000, respectively.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
The Company has a capital lease on a combined cycle plant which it sold and leased back. The lease requires semiannual payments of $2,582,000 through June 2001 and includes renewal and purchase options based on fair market value. This plant is included in plant in service at its original cost of $54,405,000; accumulated depreciation at December 31, 1993 was $37,315,000.
In addition, the Company also leases certain land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates. Rent expense for 1993, 1992, and 1991 were approximately $11,096,000, $14,733,000 and $16,046,000, respectively. Annual future minimum rental commitments, excluding the Palo Verde and combined cycle leases, for the period 1994 through 1998 range between $11 million and $13 million. Total rental commitments after 1998 are estimated at $129 million.
8. INCOME TAXES
The Company is included in the consolidated income tax returns of Pinnacle West. Income taxes are allocated to the Company based on its separate company taxable income or loss. Approximately $17.3 million of income taxes were payable to Pinnacle West at December 31, 1993. Investment tax credits were deferred and are being amortized to other income over the estimated life of the related assets as directed by the ACC.
Effective January 1, 1993, the Company adopted the provisions of SFAS No. 109, which requires the use of the liability method in accounting for income taxes. Upon adoption the Company recorded deferred income tax liabilities related to the equity component of AFUDC, the debt component of AFUDC recorded net of tax, and other temporary differences for which deferred income taxes had not been provided. Deferred income tax balances were also adjusted for changes in tax rates. The adoption of SFAS No. 109 had no material effect on net income but increased deferred income tax liabilities by $585.3 million at December 31, 1993. Historically the FERC and ACC have allowed revenues sufficient to pay for these deferred tax liabilities, and, in accordance with SFAS No. 109, a regulatory asset has been established in a corresponding amount.
The components of income tax expense (benefit) are:
Year Ended December 31, -------------------------------- 1993 1992 1991 --------- --------- ---------- (Thousands of Dollars) Current: Federal................................... $ 69,243 $ 80,921 $ 39,446 State..................................... 23,915 23,141 11,010 --------- --------- ---------- Total current........................... 93,158 104,062 50,456 --------- --------- ---------- Deferred: Depreciation -- net....................... 58,844 75,931 56,478 Palo Verde cost deferral.................. (5,015) (5,015) 46,004 Alternative minimum tax................... 13,661 7,732 (10,565) Disallowed Palo Verde costs (including ITC).................................... -- -- (202,416) Refund obligation......................... 8,454 8,454 (20,591) Palo Verde accretion income............... 29,618 26,668 2,099 Loss on reacquired debt................... 4,288 10,266 (1,032) Palo Verde start-up costs................. (1,335) (28,976) (1,337) Investment tax credit -- net.............. (6,948) (6,804) (11,117) Other -- net.............................. (5,818) (10,963) (2,729) --------- --------- ---------- Total deferred.......................... 95,749 77,293 (145,206) --------- --------- ---------- Total................................. $ 188,907 $ 181,355 $ (94,750) ========= ========= ==========
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
Total income tax expense (benefit) differed from the amount computed by multiplying income before income taxes by the statutory federal income tax rate due to the following:
Year Ended December 31, -------------------------------- 1993 1992 1991 --------- --------- ---------- (Thousands of Dollars) Federal income tax expense (benefit) at statutory rate (35% in 1993, 34% in 1992 and 1991)................................. $ 153,753 $ 145,574 $(107,916) Increase (reductions) in tax expense resulting from: Tax under book depreciation............... 17,671 17,465 21,776 Palo Verde cost deferral.................. -- -- (4,063) Disallowed Palo Verde costs (including ITC).................................... -- -- 22,236 Investment tax credit amortization........ (6,922) (7,036) (11,117) State income tax -- net of federal income tax benefit............................. 27,005 27,036 (9,820) Other..................................... (2,600) (1,684) (5,846) --------- --------- ---------- Total................................. $ 188,907 $ 181,355 $ (94,750) ========= ========= ==========
The components of the net deferred income tax liability at December 31, 1993, were as follows (in thousands of dollars):
Deferred tax assets: Deferred gain on Palo Verde Unit 2 sale/leaseback.............. $ 66,754 Alternative minimum tax (can be carried forward indefinitely).. 35,514 Other.......................................................... 86,745 Valuation allowance............................................ (15,413) ----------- Total deferred tax assets.................................. 173,600 -----------
Deferred tax liabilities: Plant related.................................................. 751,520 Income taxes recoverable through future rates -- net........... 585,294 Palo Verde deferrals........................................... 158,424 Other.......................................................... 40,429 ----------- Total deferred tax liabilities............................. 1,535,667 -----------
Accumulated deferred income taxes -- net......................... $1,362,067 ===========
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
9. PENSION PLAN AND OTHER BENEFITS
Pension Plan
The Company has a defined benefit pension plan covering substantially all employees. Benefits are based on years of service and compensation using a final average pay plan benefit formula. The plan is funded on a current basis to the extent deductible under existing tax regulation. Plan assets consist primarily of domestic and international common stocks and bonds, and real estate. Pension cost, including administrative cost, for 1993, 1992 and 1991 was approximately $13,950,000, $14,022,000 and $10,590,000, respectively, of which approximately $6,516,000, $3,917,000 and $4,939,000, respectively, was charged to expense; the remainder was either capitalized as a component of construction costs or billed to owners of facilities for which the Company is operating agent.
The components of net periodic pension costs are as follows (in thousands of dollars):
A reconciliation of the funded status of the plan to the amounts recognized in the balance sheet is presented below (in thousands of dollars):
1993 1992 --------- --------- Plan assets at fair value............................... $ 417,938 $ 388,790 --------- --------- Less actuarial present value of benefit obligation: Accumulated benefit obligation, including vested benefits of $347,603 and $286,588................. 372,364 307,003 Effect of projected future compensation increases... 127,388 105,027 --------- --------- Total projected benefit obligation.............. 499,752 412,030 --------- --------- Plan assets less than projected benefit obligation...... (81,814) (23,240) Plus: Unrecognized net loss from past experience different from that assumed..................... 51,361 8,288 Unrecognized prior service cost................... 14,717 15,733 Unrecognized net transition asset................. (39,242) (42,458) --------- --------- Accrued pension liability included in other deferred credits............................................... $ (54,978) $ (41,677) ========= ========= Principal actuarial assumptions used were:
Discount rate....................................... 7.50% 8.25% Rate of increase in compensation levels............. 5.00% 5.00% Expected long-term rate of return on assets......... 9.50%(a) 9.50%
(a) The Company will assume a 9% rate of return on plan assets for computing the net periodic pension cost in 1994.
In addition to the defined benefit pension plan described above, the Company also sponsors two qualified defined contribution plans. Substantially all employees are eligible to participate in one or the other of these two
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
plans. Both plans provide for employee contributions and partial employer matching contributions after certain eligibility requirements are met. The cost of these plans for 1993, 1992 and 1991 was $6,283,000, $5,311,000 and $2,708,000, of which $3,006,000, $2,514,000 and $1,344,000 was charged to expense.
Postretirement Plans
The Company provides medical and life insurance benefits to its retired employees. Employees may become eligible for these retirement benefits based on years of service and age. The retiree medical insurance plan is contributory; the retiree life insurance plan is noncontributory. In accordance with the governing plan documents, the Company retains the right to change or eliminate these benefits.
During 1993, the Company adopted SFAS No. 106, which requires that the cost of postretirement benefits be accrued during the years that the employees render service. Prior to 1993, the costs of retiree benefits were recognized as expense when claims were paid. This change had the effect of increasing 1993 retiree benefit costs from approximately $6 million to $34 million; the amount charged to expense increased from approximately $2 million to $17 million for an increase of $15 million, including the amortization (over 20 years) of the initial postretirement benefit obligation estimated at January 1, 1993 to be $183 million. Funding is based upon actuarially determined contributions that take into account the tax consequences.
The components of the postretirement benefit costs for 1993 are as follows (in thousands of dollars):
Service cost -- benefits earned during the period........... $ 9,510 Interest cost on accumulated benefit obligation............. 15,630 Net amortization and deferral............................... 9,146 ------------ Net periodic postretirement benefit cost.................... $ 34,286 ============
A reconciliation of the funded status of the plan to the amounts recognized in the balance sheet is presented below (in thousands of dollars):
Plan assets at fair value, funded at December 31, 1993........ $ 28,154 ------------ Less accumulated postretirement benefit obligation: Retirees.................................................. 49,296 Fully eligible plan participants.......................... 13,504 Other active plan participants............................ 137,113 ------------ Total accumulated postretirement benefit obligation... 199,913 ------------ Plan assets less than accumulated benefit obligation.......... (171,759) Plus: Unrecognized transition obligation...................... 173,773 Unrecognized net gain from past experience different from that assumed and from changes in assumptions..... (2,072) ------------ Accrued postretirement liability included in other deferred credits................................................... $ (58) ============
Principal actuarial assumptions used were: Discount rate............................................. 7.50% Initial health care cost trend rate -- under age 65....... 12.00% Initial health care cost trend rate -- age 65 and over.... 9.00% Ultimate health care cost trend rate (reached in the year 2003)........................... 5.50% Annual Salary increase for life insurance obligation...... 5.00%
Assuming a one percent increase in the health care cost trend rate, the Company's 1993 cost of postretirement benefits other than pensions would increase by $6.8 million and the accumulated benefit obligation as of December 31, 1993 would increase by $40.6 million.
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
In 1993, the Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits." The new standard requires a change from a cash method to an accrual method in accounting for benefits (such as long-term disability) provided to former or inactive employees after employment but before retirement. The adoption of this new standard resulted in an increase in 1993 postemployment benefit costs of approximately $2 million.
10. COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
The Palo Verde participants have insurance for public liability payments 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 industrywide retrospective assessment program. The maximum assessment per reactor under the retrospective rating program for each nuclear incident is approximately $79 million, subject to an annual limit of $10 million per incident. Based upon the Company's 29.1% interest in the three Palo Verde units, the Company's maximum potential assessment per incident is approximately $69 million, with an annual payment limitation of $8.73 million. The insureds under this liability insurance include the Palo Verde participants and "any other person or organization with respect to his legal responsibility for damage caused by the nuclear energy hazard."
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. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
El Paso Electric Company Bankruptcy
The other joint owners in the Palo Verde and Four Corners facilities (see Note 6) include El Paso Electric Company, which currently is operating under Chapter 11 of the Bankruptcy Code. A plan whereby EPEC would become a wholly- owned subsidiary of Central and South West Corporation would resolve certain issues to which the Company could be exposed by the bankruptcy, including EPEC allegations regarding the 1989-90 Palo Verde outages. The plan has been confirmed by the bankruptcy court, but cannot become fully effective until several additional or related approvals are obtained. If they are not obtained, the plan could be withdrawn or terminate, thereby reintroducing the Company's exposures.
Palo Verde Tube Cracks
Tube cracking in the Palo Verde steam generators adversely affected operations in 1993, and will continue to do so in 1994 and probably into 1995, because of the cost of replacement power and maintenance expense associated with unit outages and corrective actions required to deal with the issue.
The operation of Palo Verde Unit 2 has been particularly affected by this issue. The Company has encountered axial tube cracking in the upper regions of the two steam generators in Unit 2. This form of tube degradation is uncommon in the industry and, in March 1993, led to a tube rupture and an outage of the unit that extended to September 1993, during which the unit was refueled. Unit 2 is currently completing a mid-cycle inspection outage which revealed further tube degradation. Unit 2 will have another mid-cycle inspection outage later in 1994.
The steam generators of Units 1 and 3 were inspected late in 1993, but did not show signs of axial cracking in their upper regions. All three units have, however, experienced cracking in the bottom of the steam generators of the types which are common in the industry.
Although its analysis is not yet completed, the Company believes that the axial cracking in Unit 2 is due to deposits on the tubes and to the relatively high temperatures at which all three units are now designed to
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
operate. The Company also believes that it can retard further tube degradation to acceptable levels by remedial actions which include chemically cleaning the generators and performing analyses and adjustments that will allow the units to be operated at lower temperatures without appreciably reducing their output. The temperature analyses should be concluded within the next several months. In the meantime, the lower temperatures will be achieved by operating the units at less than full power (86%).
Chemical cleaning was performed during Unit 2's current mid-cycle outage, and will be performed in the next refueling outage of Unit 3 (which will begin shortly) and of Unit 1 (which is scheduled for March 1995). The Company has concluded that Unit 1 can be safely operated until the 1995 outage and has submitted its supporting analysis to the NRC, but a mid-cycle inspection later in 1994 is possible.
As a result of these corrective actions, all three units should be returned to full power by mid-1995, and one or more of the units could be returned to full power during 1994. So long as the three units are involved in mid-cycle outages and are operated at 86%, the Company will incur additional fuel and purchased power costs averaging approximately $2 million per month (before income taxes).
Because of schedule changes associated with the tube issues and other circumstances, it now appears that all three units will be down for refueling outages at various times during 1995.
When significant cracks are detected during any outage, the affected tubes are taken out of service by plugging. That has occurred in a number of tubes in Unit 2, which is by far the most affected by cracking and plugging. The Company expects that this will slow considerably because of the foregoing remedial actions and that, while it may ultimately reach some limit on plugging, it can operate the present steam generators over a number of years.
Litigation
The Company is a party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the operations or financial position of the Company.
Construction Program
Expenditures in 1994 for the Company's continuing construction program have been estimated at $279 million, excluding capitalized property taxes and capitalized interest.
Fuel and Purchased Power Commitments
The Company is a party to various fuel and purchased power contracts with terms expiring from 1994 through 2020 that include required purchase provisions. The Company estimates its contract requirements during 1994 to be approximately $136 million. However, this amount may vary significantly pursuant to certain provisions in such contracts which permit the Company to decrease its required purchases under certain circumstances.
11. SUPPLEMENTARY INCOME STATEMENT INFORMATION
Other taxes charged to operations during each of the three years in the period ended December 31, 1993 are as follows:
ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (CONTINUED)
12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
ELECTRIC OPERATING OPERATING NET EARNINGS FOR QUARTER(a) REVENUES INCOME INCOME COMMON STOCK - ---------------- ------------ ------------ ------------ ---------------- (THOUSANDS OF DOLLARS) First $371,303 $ 79,441 $ 47,166 $ 39,277 Second 407,375 92,264 61,364 53,716 Third 524,483 132,639 102,911 95,617 Fourth 383,129 68,144 38,945 30,936
First $344,947 $ 70,867 $ 30,911 $ 22,587 Second 409,012 101,222 62,773 54,680 Third 516,960 138,947 108,158 100,048 Fourth 398,760 81,222 44,963 37,038
(a) The Company's operations are subject to seasonal fluctuations with variations occurring in energy usage by customers from season to season and from month to month within a season, primarily as a result of weather conditions. For this and other reasons, the results of operations for interim periods are not necessarily indicative of the results to be expected for the full year.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company estimates that the carrying amounts of its cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 1993 and 1992 due to their short maturities. The December 31, 1993 and 1992 fair values of debt and equity investments, determined by using quoted market values or by discounting cash flows at rates equal to its cost of capital, approximate their carrying amounts.
On December 31, 1993 the carrying amount of long-term debt liabilities (excluding $30 million of capital lease obligations) was $2.098 billion and its estimated fair value was approximately $2.257 billion. On December 31, 1992 the carrying amount of long-term debt (excluding $32 million of capital lease obligations) was $2.115 billion and its estimated fair value was approximately $2.226 billion. The fair value estimates were determined by independent sources using quoted market rates where available. Where market prices were not available, the fair values were estimated by discounting future cash flows using rates available for debt of similar terms and remaining maturities. The carrying amounts of long-term debt bearing variable interest rates approximate their fair values at December 31, 1993 and 1992, respectively.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is hereby made to "Election of Directors" in the Company's Proxy Statement relating to the annual meeting of shareholders to be held on April 19, 1994 (the "1994 Proxy Statement") and to the Supplemental Item -- "Executive Officers of the Registrant" in Part I of this report. During 1993, Mr. Woods, a Director of the Company, transferred shares of the Company's $2.625 Series C Preferred Stock directly owned by him to a trust under which he is a beneficiary and a trustee. This transfer technically required Mr. Woods to file with the SEC an amended securities ownership report (reflecting his indirect, rather than direct, ownership of the shares) and a new ownership report in his capacity as trustee under the trust. These reports were filed, but not within the required timeframe.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to the fourth paragraph under the heading "The Board and its Committees," and to "Executive Compensation," "Report of the Human Resources Committee," and "Performance Graphs" in the 1994 Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Principal Holders of Voting Securities" and "Ownership of Pinnacle West Securities by Management" in the 1994 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is hereby made to the last paragraph under the heading "The Board and its Committees" in the 1994 Proxy Statement.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See the Index to Financial Statements and Financial Statement Schedules in Part II, Item 8 on page 19.