-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, qOZin5X68h0VTZfGyb0Kf7wvNG1f3X4lT5fXNUQYdLN33scIHFswbRI93rYELXx6 1/RrR3KkcGSo6lrKJHE9eg== 0000049648-94-000014.txt : 19940311 0000049648-94-000014.hdr.sgml : 19940311 ACCESSION NUMBER: 0000049648-94-000014 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940310 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: IDAHO POWER CO CENTRAL INDEX KEY: 0000049648 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 820130980 STATE OF INCORPORATION: ID FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-03198 FILM NUMBER: 94515440 BUSINESS ADDRESS: STREET 1: 1221 W IDAHO ST STREET 2: PO BOX 70 CITY: BOISE STATE: ID ZIP: 83707 BUSINESS PHONE: 2083832200 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1993 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from ............. to ................ Commission file number 1-3198 IDAHO POWER COMPANY (Exact name of registrant as specified in its charter) IDAHO 82-0130980 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1221 W. Idaho Street, Boise, Idaho 83702-5627 (Address of principal executive offices)(Zip Code) Registrant's telephone number, including area code (208)-383-2200 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Stock ($2.50 par value) New York and Pacific Securities registered pursuant to Section 12(g) of the Act: Preferred Stock (Title of Class) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Aggregate market value of voting stock held by nonaffiliates (January 31, 1994) $1,096,807,400 Number of shares of common stock outstanding at February 28, 1994 37,318,594 Documents Incorporated by Reference: Part III, Item 10 Portions of the definitive proxy statement of Item 11 the Registrant to be filed pursuant to Item 12 Regulation 14A for the 1994 Annual Meeting of Item 13 Shareowners to be held on May 4, 1994. The exhibit index is located on page 98. This document contains 104 pages. PART I ITEM 1. BUSINESS THE COMPANY General - Idaho Power Company (Company) is an electric public utility incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. The Company is engaged in the generation, purchase, transmission, distribution and sale of electric energy in an approximate 20,000- square-mile area in southern Idaho, eastern Oregon and northern Nevada, with an estimated population of 670,000 people. The Company holds franchises in approximately 70 cities in Idaho and 10 cities in Oregon, and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 28 counties in Idaho, 3 counties in Oregon and 1 county in Nevada. The Company's results of operations, like those of certain other utilities in the Northwest, can be significantly affected by weather and streamflow conditions. Variations in energy usage by ultimate customers occur from year to year, from season to season and from month to month within a season, primarily as a result of weather conditions. With the recent implementation of a power cost adjustment mechanism in the Idaho jurisdiction, which includes a major portion of the operating expenses with the largest variation potential (net power supply costs), the Company's future operating results will be more dependent upon general regulatory, economic, and temperature conditions and less on precipitation and streamflow conditions. As of December 31, 1993, the Company supplied electric energy to 317,772 general business customers and employed 1,729 people in its operations (1,654 full-time). The Company operates 17 hydro power plants and shares ownership in three coal-fired generating plants (see Item 2-"Properties"). The Company relies heavily on hydroelectric power for its generating needs and is one of the nation's few investor-owned utilities with a predominantly hydro base. The Company has participated in the development of thermal generation in the neighboring states of Wyoming, Oregon and Nevada using low-sulfur coal from Wyoming and Utah. For the twelve months ended December 31, 1993, total system electric revenues from residential customers accounted for 34 percent of the Company's total operating revenues. Commercial and industrial customers with less than 750 KW demand including street lighting customers accounted for 18 percent, commercial and industrial customers with 750 KW demand and over accounted for 18 percent and irrigation customers accounted for 9 percent. Public utilities and interchange arrangements accounted for 16 percent and other operating revenues accounted for 5 percent. The Company's principal commercial and industrial revenues are from sales of electric power to customers involved in elemental phosphorus production; food processing, preparation and freezing plants; phosphate fertilizer production; electronics and general manufacturing facilities; lumber; beet sugar refining; and electric loads associated with the year-round recreational business, such as lodges, condominiums, ski lifts and other related facilities, including those at the Sun Valley resort area. The Company has three large long-term special contract customers in its Idaho retail jurisdiction - the Idaho Engineering Laboratory (INEL), the J. R. Simplot Company and FMC Corporation (FMC). The rates charged these customers under their contracts are subject to the jurisdiction of the Idaho Public Utilities Commission (IPUC). The Company has contracts to supply up to 45 megawatts of capacity and energy to the INEL in eastern Idaho and up to 38 megawatts of capacity and energy to the J. R. Simplot Company for its chemical fertilizer operations plant near Pocatello, Idaho. Since 1948, the Company has supplied capacity and energy to FMC for its elemental phosphorus production plant near Pocatello, Idaho. Under an agreement effective on January 1, 1974, the maximum amount of power that FMC may schedule is 250 megawatts. The agreement is subject to renewal every two years as to one- fourth of the power deliveries and contains annual minimum payment guarantees giving consideration to FMC's ability to decrease its electric demands during periods in which the Company may request reductions specified in the agreement. Revenues from FMC were approximately $30.7 million for 1.4 million megawatt- hours (MWH) of energy supplied during the twelve months ended December 31, 1993. Competition - The electric utility industry in general has become, and is expected to be, increasingly competitive due to a variety of regulatory, economic and technological developments. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale electric market (a) through amendments to the Public Utility Holding Company Act of 1935, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Federal Power Act, authorizing the FERC under certain conditions to order utilities owning transmission facilities to provide wholesale transmission services to or for other utilities and other entities generating electric energy for sale or resale. With the passage of the Energy Policy Act and the advent of a more competitive electric utility environment, the Company has intensified its ongoing strategic planning process. The Company's goal is to anticipate and fully integrate into its operations any legislative, regulatory, environmental, competitive and technological changes. The Company is well positioned to succeed in a more competitive environment with its low cost of energy production and its strategic geographic location which provides excellent opportunities to purchase, sell, exchange and transmit Northwest energy coupled with historically providing open access to its transmission system. With its predominantly hydro base and low-cost thermal plants, the Company is the lowest cost producer of electric energy in the nation among investor-owned utilities. With its interconnections and transmission line capacity agreements with BPA and other Northwest investor-owned utilities, the Company has access to all the major electric systems in the West. These interconnections allowed the Company to generate $86.5 million in wholesale revenues (16 percent of its total revenues) in 1993 (see "Power Supply"). Some industrial and large commercial customers have the ability to own and operate facilities to generate their own electric energy and if such facilities are qualifying facilities, can require the displaced electric utility to purchase the output of such facilities at a state regulatory commission established "avoided cost" rate (see "Power Supply"). With the Company's rates for its large (750 kW and over) industrial customers, excluding special contracts, averaging approximately 2.8 cents per kilowatt hour (see "Power Supply"), these customers are converting waste heat to electricity for added revenues and not displacing the Company's electric service. The Company's rates for its small (under 750 kW) commercial and industrial customers average approximately 4.2 cents per kilowatt hour. The legislatures and/or the regulatory commissions in several states have considered or are considering "retail wheeling." Retail wheeling means the movement of electric energy produced by another entity over an electric utility's transmission and distribution system, to a retail customer in the utilities service territory. A requirement to transmit directly to retail customers would permit retail customers to purchase electric capacity and energy from the electric utility in whose service area they are located or from any other electric utility or independent power producer. The Idaho Legislature and the IPUC have not yet addressed retail wheeling. However, the Company believes it is well positioned with its low-cost energy production to provide energy to retail customers in other utility service areas if retail wheeling is adopted by one or more of the Western states (see "Regulation"). Subsidiaries - The Company has four wholly-owned subsidiary companies: Ida-West Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo), Idaho Utility Products Company (IUPCo) and IDACORP, INC. Ida-West was formed in 1989 to participate through partnership interests in cogeneration and small power production (CSPP) projects. Ida-West, through various partnerships, completed construction in 1993 of the Hazelton B, Wilson Lake and Falls River Projects as well as acquiring in 1992 an existing operating facility (South Forks Project). All of the projects are "qualified facilities" under the Public Utility Regulatory Policies Act of 1978 (PURPA) with the energy from the facilities being sold to the Company under IPUC approved firm energy sales agreements. Power purchased from these facilities amounted to approximately $6.0 million in 1993. As part of its Resource Contingency Program, the Bonneville Power Administration (BPA) requested proposals to provide up to 800 average megawatts of energy options. A partnership including Ida- West submitted a proposal for a 227-megawatt gas-fired cogeneration project to be located near Hermiston, Oregon. On June 4, 1993, BPA selected the partnership's project, together with two other projects, to participate in the program. The partnership and BPA have signed an option development agreement which grants BPA an option to acquire energy from the project at any time during a five year option hold period after all option development period tasks, including permitting, have been completed. If BPA does not elect to begin construction or decides to cancel the project, a termination payment will be made to the partnership as defined in the option development agreement. In addition, the agreement states that BPA will reimburse the partnership for certain development tasks as defined in the agreement. The partnership expects these development period tasks to be completed by year-end 1995. The Company made an additional investment of $8.0 million in Ida- West during 1993 bringing its total equity investment to $20 million. Ida-West continues to actively seek or develop new projects. IERCo has been in operation since 1974. Its primary purpose is to participate as a joint venturer in the Bridger Coal Company, which operates the mine supplying coal to the Jim Bridger plant near Rock Springs, Wyoming (see "Fuel"). As of December 31, 1993, the Company's total investment in IERCo was $5.2 million. IUPCo was formed in 1983 to develop and market products to the utility industry. IDACORP, INC. was organized in 1986 to commence an exempt non-regulated diversification program. No material activity occurred in either of these subsidiaries in 1993. As of December 31, 1993, the combined total investment in these subsidiaries was $3.4 million. Research and Development - In 1992, the Company joined Southern California Edison, the U. S. Department of Energy and others in retrofitting an existing 10- megawatt solar thermal experimental power plant called Solar Two. The project will use hundreds of sun-tracking mirrors to collect the sun's heat and a molten-salt fluid to store and transfer the heat. The molten-salt, which is environmentally safe, will retain heat longer and more efficiently than the original oil and rock heat storage system, allowing the plant to generate electricity during periods of cloud cover or at night. The Company will contribute $630,500 over the next three years and the Electric Power Research Institute (EPRI), of which the Company is a member, will contribute an additional $630,500 of matching funds, bringing the Company's credited contribution to approximately $1.3 million. The project is located near Barstow, California, and should begin generating electricity in 1995. Parts of the Company's service territory show a strong potential for solar power. Research into efficiencies and costs at the Solar Two power plant will help determine whether the Company can effectively pursue solar power. This renewable energy resource could serve a part of the Company's needs through the next century. During 1993, the Company spent approximately $2.1 million on research and development of which $1.8 million was the Company's membership in EPRI. This matches the 1992 amount. EPRI's mission is to discover, develop and deliver advances in science and technology for the benefit of society. Some of the projects of benefit to the Company include: electrification technologies, power quality, electric transportation systems, EMF assessment/risk management and air quality issues. Energy Efficiency - The Company continues to promote the efficient use of electrical energy, recognizing the associated long-term benefits to customers and the Company. The IPUC and Oregon Public Utility Commission (OPUC) both emphasize the need for cost-effective conservation resources as well as the identification of potential conservation measures which can be utilized in the future. The Company now has active conservation programs in both Idaho and Oregon for the efficient use of energy in residential manufactured homes, commercial, agricultural and industrial sectors along with a weatherization program operating in conjunction with an established state program providing energy conservation measures to eligible low-income families. The Company plans to apply in 1994 for approval of a program that will encourage both energy and water use efficiency in the residential sector by changing to flow efficient showerheads. The Company supported legislation in Idaho that established energy-efficient building codes for new home construction and continues to support the adoption of even more stringent energy codes by local government jurisdictions. In 1993, the Company expended $8.0 million on its various energy-efficiency programs and continues to evaluate programs to encourage the efficient use of energy. POWER SUPPLY The Company is a dual-peaking system, with the larger energy peak generally occurring in the summer. This complements the winter peaking utilities which predominate the Pacific Northwest. Even though its significant hydroelectric generation can operate to meet demand peaks, seasonal energy requirements are important to the Company because its seasonal energy capability is determined in part by the availability of water. Heavy spring precipitation and cool summer temperatures in the Company's service territory coupled with near-normal accumulations of snow in the winter propelled the 1993 water year to more than three times that of 1992. Even though streamflows were much improved, hydro generation did not fully return to normal levels during 1993. The major adverse factors were the carryover effects of six years of drought on reservoirs and ground water supplies and the inability to fully utilize hydro generation capability during the first few months of 1993 as the Company restored and then maintained Brownlee reservoir levels for later use. The 1993 general business (retail) demand for energy nearly reached 1992's record, reflecting continued growth in the economy of the Company's service territory. Revenues from sales to other utilities increased $8.2 million in 1991, decreased $10.6 million in 1992 but increased $44.5 million in 1993. Revenues from firm sales to other utilities amounted to $41.5 million in 1991, $37.5 million in 1992 and $45.4 million in 1993. Revenues from opportunity sales to other utilities amounted to $11.0 million for 1991, decreased to $4.5 million in 1992 but increased to $41.1 million in 1993. For the years 1991 and 1992, the drought's adverse effect on the Company's hydrogeneration resulted in reduced sales, while in 1993 the return to more normal hydro conditions increased dramatically the volume of sales and revenues. The system peak demand for 1993 was 2,154 megawatts set on February 17, 1993, which was 5.0 percent below the 1992 peak demand and 7.4 percent below the record demand of 2,327 megawatts set during unusually cold weather on February 7, 1989. The following table sets forth the total energy sources of the Company for the last five years: Total Energy Sources (000's of MWH) 1993 1992 1991 1990 1989 Generation - net station output - Hydro 8,361.7 4,990.3 5,819.2 6,108.8 7,443.6 Coal-fired 6,485.5 7,295.6 5,833.7 5,957.0 6,017.4 Purchased and interchange 1,273.8 2,102.8 2,583.1 1,936.7 1,496.8 Total 16,121.0 14,388.7 14,236.0 14,002.5 14,957.8 Purchased power expenses were high and fluctuated during the last three years reflecting necessity purchases from neighboring utilities during the drought and increased purchases from CSPP projects during 1993 as a result of improved hydro conditions. The Company increased utilization of its thermal facilities by operating at high capacity factors during the drought which increased fuel expense for 1992 by $21.5 million. In 1993 fuel expense decreased $8.9 million as a direct result of increased availability of hydro facilities to meet customer demand. During 1993, approximately 52 percent of the Company's load requirements were met with the Company's hydroelectric generating plants, 40 percent from the thermal generating plants and the remaining 8 percent was purchased from or exchanged with neighboring utilities or from CSPP facilities. By comparison, hydroelectric generation met 35 percent of load requirements in 1992, 41 percent in 1991, 44 percent in 1990 and 50 percent in 1989. In a normal water year this source contributes approximately 58 percent of the total system requirements. Although it is too early to predict with certainty what hydroelectric conditions will be during 1994, preliminary reports indicate the mountain snowpack is below normal. However, the carryover reservoir storage is above average throughout the Snake River Basin. The Company expects to meet projected energy loads during the coming year by utilizing its hydro and coal-fired facilities and strategic geographic location - which provides excellent opportunities to purchase, sell, exchange and transmit Northwest energy - even if below normal streamflow conditions prevail. The Company's generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum load-carrying capability and reliability. The transmission system of the Company is directly interconnected with the transmission systems of the Bonneville Power Administration, The Washington Water Power Company, the Pacific Power & Light and Utah Power & Light Divisions of PacifiCorp, The Montana Power Company and Sierra Pacific Power Company. Such interconnections, coupled with transmission line capacity made available under agreements with certain of the above utilities, permit the advantageous interchange, purchase and sale of power among the various systems and other electric systems in the West. The Company is a member of the Intercompany Pool, the Western Systems Coordinating Council and the Western Systems Power Pool. Increasing competitiveness in the electric power marketplace, the growing mobility of retail customers and the potential for deregulation of the electric power industry, all indicate a need for the Company to adjust its resource acquisition policy toward a greater emphasis on resource marketability. In order to avoid burdening the Company and its customers with unnecessary future power supply costs and higher rates, the Company has adopted a policy of acquiring all new resources as close as possible to the actual time of need for them, and selecting the lowest cost resources meeting all of the Company's requirements. In practice, this policy will result in the purchase of power from others through the marketplace whenever purchases are the lowest cost resources, and new investment in resource ownership by the Company only when a Company-owned resource would be cost effective on the market. In September, 1993, the Company submitted to its state regulators a position paper entitled "Acquisition of Supply-side Resources" describing its new resource acquisition policy, and is currently taking several steps toward implementing the policy. First, the Company filed an application with the IPUC in December, 1993 for permission to lower the price it must pay for new purchases from independent qualifying facilities (QFs) under the Public Utilities Regulatory Policies Act of 1978. The Company believes that the existing "avoided cost" rates are no longer appropriate, and that the timing of purchases, and the prices paid to QFs, should be based more closely on the Company's need for power and the current market prices of alternative resources. The IPUC is expected to rule upon the Company's application in 1994. Secondly, the Company is taking action to avoid new investments in Company-owned resources unless such new resources are cost effective compared to alternative market resources, or unless they are upgrades to existing hydroelectric facilities required under federal relicensing regulations. The Company expects to forego upgrades to its Shoshone Falls and Upper Salmon hydroelectric plants unless they are required as a condition for relicensing, and anticipates requesting permission to abandon the proposed A. J. Wiley Project on the Snake River. Refer to the "Construction Program" for facilities under construction. New Projects - During 1991, 1992 and 1993, the Company's new retail customers increased by 6,008 (or 2.1 percent), 9,759 (or 3.3 percent) and 10,205 (or 3.3 percent) respectively. The Company periodically updates its load and resource projections and now expects system energy requirements over the next 20 years to grow at an annual rate of 1.4 percent. The Company's current projects are the following: Rebuilding and expansion of the Swan Falls hydro plant, adding 13 megawatts (1994); and expansion from 10 to 53 megawatts at the Twin Falls hydro plant (1995). Capitalizing on the Company's strategic location between the Intermountain West and the Pacific Northwest, the Company is considering the construction and operation of a new transmission line that could serve as a major artery for regional transfers of power between north and south. The Southwest Intertie Project (SWIP) is a proposed 520-mile, 500-Kv transmission line that would interconnect the Company's system with utilities in the Southwest. The Bureau of Land Management (BLM) has completed the Final Environmental Impact Statement/Proposed Plan Amendment (EIS) for the SWIP. Approval of the EIS from the BLM is expected during the second quarter of 1994. After approval of the EIS, the economic feasibility of the line will be validated before the Company proceeds with construction. The Company has received preliminary commitments from various utilities and electric providers for financial participation in the project. The Company intends to retain up to a 20 percent ownership in the line. The following tables show how the Company expects to meet its forecast energy and peak demand requirements through 1998 from system generation and contracted resources. Because of its reliance upon hydroelectric generation, which varies according to streamflows, the Company's generating system is more energy constrained than capacity limited. Seasonal exchanges of winter- for-summer power are included among the contracted resources to maximize the firm load carrying capability. Exchanges are currently made with The Montana Power Company under a 10-year contract signed in 1987 and with Seattle City Light under an extended contract that expires in 2003. Summer Peak Capability (MW) (a) 1994 1995 1996 1997 1998 Generating capability 2,635 2,635 2,640 2,640 2,640 Contracts: Exchange (b) 175 175 175 175 175 Cogeneration and small power production 113 156 207 211 215 Firm peak load less interruptible (2,388) (2,424) (2,393) (2,423) (2,455) Peak capability margin 535 542 629 603 575 Percent 22.4% 22.4% 26.3% 24.9% 23.4% [FN] (a) Based upon median hydro conditions. (b) Net summer-winter exchange. Annual Energy Capability (000's of MWH)(a) 1994 1995 1996 1997 1998 Generation capability 15,702 15,614 15,702 15,679 15,766 Contracts: Cogeneration and small power production 654 1,056 1,617 1,637 1,663 Annual firm load (b) (14,976) (15,225) (14,984) (14,747) (14,978) Energy capability margin 1,380 1,445 2,335 2,569 2,451 Percent 9.2% 9.5% 15.6% 17.4% 16.4% [FN] (a) Forecast based upon average of 65 historical water conditions. (b) The growth in retail load is being offset by termination of some large short-term firm contracts. During the 1994-1998 period, the Company plans to provide all the energy required to serve its firm load requirements during periods of heavy demand, reduced hydrogeneration caused by below normal streamflow conditions, or unscheduled outages of generating units by utilizing its hydroelectric and coal-fired generating units. The Company plans to meet any temporary resource deficiencies caused by these conditions through short- term purchases of power from neighboring utilities. For additional information concerning new resource additions see "Construction Program." CSPP Purchases - As a result of the enactment of the Public Utility Regulatory Policies Act of 1978 (PURPA) and the adoption of avoided cost standards by the IPUC, the Company has entered into contracts for the purchase of energy from private developers. Because the Company's service territory encompasses substantial irrigation canal development, forest products production facilities, mountain streams, and food processing facilities, considerable amounts of energy are available from these sources. Such energy comes from hydro power producers who own and operate small plants and from cogenerators converting waste heat or steam from industrial processes into electricity. The estimated annualized cost for the 61 CSPP projects on-line as of December 31, 1993, is currently $40.6 million. During 1993, the Company purchased 567.6 million kilowatt-hours of power from these private developers at a blended price of 5.9 cents per kilowatt-hour. Firm Wholesale Power Sales - The Company has firm wholesale power sales contracts with Sierra Pacific Power Company, Portland General Electric Company, The Montana Power Company, the City of Weiser, Idaho, two entities in the state of Utah, one in the state of California and one in the state of Oregon. These contracts are for various amounts of energy and range from 7 to 100 average megawatts and are of various lengths that will expire between 1996 and 2009. Transmission Service - The BPA sells electricity to certain irrigation districts in southern Idaho for irrigation pumping and provides wholesale electric service to certain communities and rural cooperatives in and adjacent to the Minidoka Irrigation Project in Minidoka and Cassia Counties, Idaho. In addition, the Company has reciprocal wheeling agreements with various surrounding utilities. The Company has an open access philosophy and is experienced in providing reliable, high quality, economical transmission service. The transmission system is well maintained and due to the Company's strategic geographic location is able to offer transmission service if capacity is available. FUEL The Company, through Idaho Energy Resources Co., owns a one-third interest in the Bridger Coal Company and the Jim Bridger coal mine that supplies coal to the Jim Bridger generating plant in Wyoming. The mine, located near the Jim Bridger plant, operates under a long-term sales agreement providing for delivery of coal over a 41-year period that began in 1974 (see Item 2 "Prop erties"). The Bridger Coal Company has sufficient reserves to provide coal deliveries pursuant to the sales agreement. The average cost to the Company per ton of coal burned at the Jim Bridger plant, the largest thermal station on the Company's system, for the last five years is as follows: 1989 - $20.48; 1990 - $20.68; 1991 - $20.78; 1992 - $20.13 and 1993 - $20.99. The Company also has a coal supply contract providing for annual deliveries of coal through 2005 from the Black Butte Coal Company's Leucite Hills mine adjacent to the Jim Bridger project. This contract supplements the Bridger Coal Company deliveries and provides another coal supply to operate the Jim Bridger plant. The Jim Bridger plant's rail load-in facility and unit coal train allows the plant to take advantage of potentially lower-cost coal from outside mines for tonnage requirements above established contract minimums. Portland General Electric Company (PGE), with whom the Company is a 10 percent participant in the ownership and operation of the Boardman plant, has a flexible contract with a division of AMAX Coal Company for delivery of low sulfur coal from its mine near Gillette, Wyoming, to Boardman Unit No. 1. Under this contract, PGE has the option to purchase 750,000 tons of coal annually through 1999. This agreement enables PGE and the Company to take advantage of lower cost spot market coal for some or all of the Boardman plant's requirements. Sierra Pacific Power Company (SPPCo), with whom the Company is a joint (50/50) participant in the ownership and operation of the North Valmy Steam Electric Generating plant (Valmy plant), entered into a 22-year coal contract that began in July of 1981 with Southern Utah Fuel Company, a subsidiary of Coastal States Energy Corporation, for the delivery of 17.5 million tons of low- sulfur coal from a mine near Salina, Utah, for Valmy Unit No. 1. With the commercial operation of Valmy Unit No. 2 in May 1985, an additional coal source was needed to assure an adequate supply for both units at the Valmy plant. Accordingly, in 1986 the Company and SPPCo signed a long-term coal supply agreement with the Black Butte Coal Company. This contract provides for Black Butte to supply coal to the Valmy project over the next two decades under a flexible delivery schedule that allows for variations in the number of tons to be delivered ranging from a minimum of 200,000 tons per year to a maximum of 1,150,000 tons per year. This flexibility will accommodate fluctuations in energy demands, hydroelectric generating conditions and purchases of energy from CSPP facilities. WATER RIGHTS The Company, except as otherwise stated herein, has valid water rights, unlimited as to time, to the waters used in its generating stations, which were obtained under applicable provisions of state law. Such rights, however, are subject to prior rights and, with respect to license provisions of certain hydroelectric facilities and water licenses, are subject to future upstream diversion of water for irrigation and other consumptive use. Over time, increased irrigation and other consumptive diversions on the Snake River have resulted in some reduction in the streamflows available for the Company's hydroelectric generating facilities. In this regard, the Company has pursued a course of action to determine and protect its water rights and their priority consistent with the settlement agreements negotiated with the state of Idaho signed on October 25, 1984. In 1987, Congress passed and the President signed into law House Bill 519 which permitted implementation of the agreements and provided that the Federal Energy Regulatory Commission would accept the settlement agreements and that the settlement was consistent with the terms of hydroelectric licenses and was prudent for the purpose of determining rates under Section 205 of the Federal Power Act during the remaining term of certain project licenses on the Snake River. The Idaho State Legislature has charged the Idaho Department of Water Resources with the responsibility of proceeding with the adjudication of water rights on the Snake River. The adjudication process commenced in 1987 and has yet to be completed. The Company does not anticipate any modification of its water rights in conjunction with the adjudication process. REGULATION The Company is not in direct competition with any electric public utility company or municipality within its service territory. The Company is under the regulatory jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities Commission, the Public Utility Commission of Oregon and the Public Service Commission of Nevada. The Company is also under the regulatory jurisdiction of the IPUC, OPUC and the Public Service Commission of Wyoming as to the issuance of securities. The Company is subject to the provisions of the Federal Power Act as a "licensee" and "public utility" as therein defined. The Company's retail rates are established under the jurisdiction of the state regulatory agencies and its wholesale and transmission rates are regulated by the FERC (see "Rates"). Pursuant to the requirements of Section 210 of the PURPA, the state regulatory agencies have each issued orders and rules regulating the Company's purchase of power from CSPP facilities. As a licensee under the Federal Power Act, the Company and its licensed hydroelectric projects are subject to the provisions of Part I of the Act. All licenses are subject to conditions set forth in the Act and regulations of the FERC thereunder, including, but not limited to, provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment, severance damages, and other matters. The state of Oregon has a Hydroelectric Act providing for licensing of hydroelectric projects in that state. The Company's Brownlee, Oxbow and Hells Canyon facilities are on the Snake River where it forms the boundary between Idaho and Oregon and occupy land located in both states. These facilities are subject, with respect to project property located in Oregon, to such provisions of the Oregon Hydroelectric Act. The Company has obtained Oregon licenses for these facilities and these licenses as are not in conflict with the Federal Power Act or the Company's FERC license. ENVIRONMENTAL REGULATION Environmental controls at the federal, state, regional and local levels are having a continuing impact on the Company's operations due to the cost of installation and operation of equipment required for compliance with such controls. Based upon the requirements of present environmental laws and regulations, the Company estimates its capital expenditures (excluding allowance for funds used during construction) for environmental matters for 1994 and during the period 1995-1998 will total approximately $1.7 million and $7.4 million, respectively. However, to the extent regulations under federal and state environmental protection laws, as well as the laws themselves, are changed, costs for compliance with such laws and regulations in connection with the Company's existing facilities and facilities under construction are subject to change in an amount not determinable. Air - The Company has analyzed the Clean Air Act legislation and its effects upon the Company and its ratepayers. The Company's coal- fired plants in Nevada and Oregon already meet the federal emission rate standards and the Company's coal-fired plant in Wyoming meets that state's even more stringent regulations. The Company anticipates no material adverse effect upon its operations. Water - The Company has received National Pollutant Discharge Elimination System Permits, as required under the Federal Water Pollution Control Act Amendments of 1972, for the discharge of effluents from its hydroelectric generating plants. The state of Oregon Department of Environmental Quality determined that the flow of water over large dams on the Columbia and Snake Rivers could result in the supersaturation of the water with dissolved nitrogen possibly resulting in damage to the fish population. The Company has obtained a permit from the Oregon Department of Environmental Quality to operate the Brownlee, Oxbow and Hells Canyon Dams in accordance with the water quality program of the state of Oregon. At the Company's American Falls hydroelectric generating plant, the Company has agreed to meet certain dissolved oxygen standards. The Company signed amendments to the agreements relating to the operation of the American Falls Dam and the location of water quality monitoring facilities to provide more accurate and reliable water quality measurements necessary to maintain water quality standards during the May 15 to October 15 period each year downstream from the Company's plant. The Company has also installed aeration equipment, water quality monitors and data processing equipment as part of the Cascade hydroelectric project to provide accurate water quality data and increase dissolved oxygen levels as necessary to maintain water quality standards on the Payette River. The Company owns and finances the operation of anadromous fish hatcheries and related facilities to mitigate the effects of its hydroelectric dams on fish populations. In connection with its fish facilities, the Company sponsors ongoing programs for the control of fish disease and improvement of fish production. The Company's anadromous fish facilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs continue to be operated under agreements with the Idaho Department of Fish and Game. In 1993, the operation of these facilities pursuant to the FERC License 1971 cost approximately $2.1 million. Endangered Species - The Northwest as a region continues to grapple with the problem of the long-term survival of anadromous fish runs - particularly salmon - on the Columbia and Lower Snake Rivers. The number of fish from several species of salmon has been declining over the last several years, the exact cause or causes of such decline is not fully known, but over-harvest, federal government dams, habitat losses and other man-caused impediments appear to be contributing factors. In addition to the Snake River sockeye which the federal government has declared endangered, two other ocean-going salmon stocks on the Columbia and Lower Snake Rivers have been granted threatened species listing. The Company is cooperating with all regional interests in an effort to resolve these issues and again in 1993 assisted the federal government by operating the Company's hydroelectric facilities to enhance downstream fish passage through federal dams. The Company, which over the years has invested millions of dollars in fish protection, mitigation and enhancement, undertook this assistance voluntarily. The Company fully supports and actively participates in the regional effort to develop a comprehensive and scientifically credible recovery program for the salmon. The Snake River Salmon Recovery Team submitted its Draft Recovery Plan to the National Marine Fisheries Service (NMFS) detailing its draft recommendations for restoring the listed Snake River salmon runs. The Company has concluded a review of the 500-page report and believes it sets forth a course of action that, if fully implemented, could lead to a successful recovery. The Draft Plan details comments regarding some institutional changes and responsibility for management of the recovery efforts. It suggests reductions in the ocean and in-river harvest rates, calls for significant improvements in transportation and collection systems, supports flow augmentation and habitat improvements, calls for a test drawdown of the federal Lower Granite Reservoir on the Snake River and suggests habitat, hatchery and predation improvements. The Company will continue to closely monitor the finalization of the Recovery Plan which is expected to be released in 1994. It is possible the final recovery plan could have a material impact on the Company, as well as every other person, community and industry in the Northwest that depends on the Snake and Columbia Rivers. The Company is hopeful that the anadromous fish runs can be restored to the level that society demands without undue hardship on the Company and those who benefit from its service. In mid-December 1992, five Snake River mollusks were listed as endangered and threatened species. This has been a part of all the Company's discussions regarding relicensing and new hydro development since that time. The listing specifically mentions the impact fluctuating water levels related to hydro operations may have on the snails' habitat. While most of the facilities on that stretch of the river are run of the river (baseload) facilities, some do provide peaking capability. There is uncertainty on exactly what impact, if any, water fluctuations caused by the facilities have on the snails. The Company intends to testify to the U. S. Fish and Wildlife Service, the listing agency, that there is little data in this area and that it proposes to study these operations. While there is potential the listing could impact the way the Company operates these facilities, at this time it is difficult to estimate what impact, if any, the issue could have on the Company and its operations. Hazardous/Toxic Wastes and Substances - Under the Toxic Substances Control Act (TSCA), the Environmental Protection Agency (EPA) has adopted regulations governing the use, storage, testing, inspection and disposal of electrical equipment that contain polychlorinated biphenyls (PCBs). The regulations permit the continued use and servicing of certain electrical equipment (including transformers and capacitors) that contain PCBs. The Company continues to meet all federal requirements of the TSCA for the continued use of equipment containing PCBs. The Company has a program to make the 200-plus substations on its system PCB free. The costs for this disposal program were $0.9 million, $0.3 million and $0.1 million for 1991, 1992, and 1993 respectively. While the Company's use of equipment containing PCBs falls well within the federal safety standards, the Company has voluntarily decided to virtually eliminate these compounds from the substation sites. This program will save costs associated with the long-term monitoring and testing of substation equipment and grounds for PCB contamination as well as being good for the environment today. The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and the Resource Conservation and Recovery Act of 1976 authorize the EPA to seek a court order compelling responsible parties to undertake cleanup action at any location determined to present an imminent and substantial danger to the public or to the environment because of an actual or threatened release of one or more hazardous substances. Because of the nature of the Company's business, various by-products and substances are produced and/or handled which are classified as hazardous under one or more of these statutes. The Company provides for the disposal or recycling of such substances through licensed independent contractors, but these statutory provisions also impose potential responsibility for certain clean up costs on the generators of the wastes. As discussed in Item 3- "Legal Proceedings," the Company accepted the responsibility to clean up certain portions of a designated Superfund site. Electric and Magnetic Fields - While scientific research has yet to establish any conclusive link between electric and magnetic fields and human disease, the possibility of a connection has caused public concern nationally and internationally. Electric and magnetic fields are found wherever there is electric current, whether it be in a high- voltage transmission line or the simplest of household electrical appliances. Concern over possible health effects already has prompted regulatory efforts to limit human exposure to electric and magnetic fields in several areas of the nation. Depending on what researchers ultimately discover and what regulations may be deemed necessary, it is an issue that could impact a number of industries, including electric utilities. At this time, it is difficult to estimate what impact, if any, the issue could have on the Company and its operations. RATES Idaho Jurisdiction - In May 1992, the IPUC issued an order which authorized the Company to put in place for a twelve-month period a drought- related temporary rate increase of 3.9 percent or $15.0 million in additional revenues. On March 29, 1993, the IPUC approved a Power Cost Adjustment (PCA) mechanism that would enable the Company to collect, or require it to refund, all or a portion of the difference between net power supply costs actually incurred and those allowed in the base rates of the Company. The PCA is intended to avoid the need for temporary rate increases during low water years and will return benefits to customers in high water years. Under the approved PCA, customers' power rates will be adjusted annually to reflect forecasted changes in the Company's net power supply costs in the current year and to true-up any deviation between forecasted and actual costs for the previous year. At the same time the temporary rate increase initiated in May 1992 ceased in May 1993, the Company implemented its first PCA rate increase of $5.0 million, combining for a net decrease of $10.0 million in rates. For the current year (May 1993 through April 1994) the PCA will be applied to 60 percent of the deviations from normalized power costs. Following the IPUC's next formal review of the Company's general revenue requirements, the PCA will be raised to recover 90 percent of the variation in power supply costs. The current balance is adjusted monthly as actual conditions are compared to the forecasted net power supply costs. The final cumulative PCA amount as of May 15, 1994 will be included in the true-up portion of the 1994 PCA. On January 8, 1993, the IPUC authorized the Company to suspend five and one-half months (January 1, 1993, through June 15, 1993) of the revenue deferral associated with the Afton generation facility for a total of $1,225,707. This allowed the Company to defer additional 1992 reserve capacity (purchased generation available to meet load if needed) costs of $1,225,707 against the suspension of revenue deferral in 1993. The Company intends to file a general revenue requirements case in its Idaho retail jurisdiction during 1994. One purpose of the filing is to bring all of the Company's cost components to a current level in response to concerns expressed by the IPUC and various customer groups in recent regulatory proceedings regarding the length of time since the Company's costs were reviewed on a comprehensive basis. In these proceedings the Company indicated that an opportunity for such a review would occur in the 1993/1994 time frame and full implementation of the PCA will not occur until such a proceeding is completed. The amount of any additional revenue requirement to be requested, if any, has not yet been determined. Oregon Jurisdiction - In 1992 the Company received OPUC authority to defer, with interest, 33.5 percent of Oregon's share of increased power production costs starting on March 23, 1992, and continuing through December 31, 1992. The Company subsequently filed a request and received approval from the OPUC for a 24-month amortization period of an annual rate increase of $526,360 or 2.57 percent effective July 1, 1993. In 1993, the Company did not file any applications for general rate relief in the Oregon retail jurisdiction. Other Jurisdictions - The Company also submitted a rate increase request to the FERC to increase rates to certain wholesale customers to recover additional 1992 power supply costs incurred due to the drought. The FERC granted a $547,900 rate increase for a twelve-month period effective November 10, 1992. In 1993 the Company did not file any applications for rate relief in its Nevada retail jurisdiction. CONSTRUCTION PROGRAM The Company's construction program for the 1994-1998 period includes completion of the rebuild of the Swan Falls hydro facility and expansion of the Twin Falls hydro facility. The total cash construction program (excluding allowance for funds used during construction) for the five-year period 1994-1998 is presently estimated to require cash funds of approximately $580.9 million as follows: 1994 1995-1998(a) (Millions of Dollars) Generating Facilities: Hydro $ 34.7 $ 56.1 Thermal 12.2 59.8 Total generating facilities 46.9 115.9 Transmission lines and substations 13.5 103.1 Distribution lines and substations 37.0 171.8 General 22.1 70.6 Total cash construction 119.5 461.4 AFUDC 3.2 4.4 Total construction including AFUDC (b) $122.7 $465.8 [FN] (a) Includes construction costs escalated at 3.86%, 3.14%, 2.66% and 2.90% annually for the years 1995-1998, respectively. (b) Does not include Ida-West equity investment in construction which is $0.2 million in 1994 and $0.5 million for the 1995- 1998 period. Ida-West intends to develop a major portion of its construction as a participant in joint ventures which are not a part of the consolidated entity. These estimates are subject to constant revision in light of changing economic, regulatory and environmental factors and patterns of conservation. Construction started in 1991 to rebuild the Swan Falls powerhouse and increase its generating capacity from 12 megawatts to 25 megawatts. The amended FERC license provides for the retirement of the present powerhouse and construction of a new powerhouse containing two generating units of 12.5 megawatts each with completion scheduled in 1994. In January 1991, the Company received authority from the IPUC to include the costs of the rebuild of the Swan Falls hydroelectric facility in the Company's rate base. The total cash expenditures of the rebuild are presently estimated at $53.6 million with total construction costs at $60.0 million including an allowance for funds used during construction. In January 1991, the Company received a 50-year license from the FERC for the Twin Falls Project that approves increasing the generating capacity from 10 megawatts to 53 megawatts. Construction started in July 1993 with completion scheduled for mid-1995. In July 1993, the Company received approval from the IPUC to rebuild the Twin Falls hydroelectric facility as proposed in its application. The commitment estimate, including allowance for funds used during construction, is $50.8 million which represents the maximum amount the Company recommends be included in Idaho ratebase. The total cash expenditures of the expansion are presently estimated at $32.3 million with total construction costs at $34.2 million including allowance for funds used during construction. Remodeling the old general office building began in 1993. The total cash expenditures for the remodel are presently estimated at $6.0 million. As these and other potential projects become more definitive as to amount, timing and regulation, future construction forecasts will change accordingly. The Company has no nuclear involvement and its future construction plans do not include development of any nuclear generation. The Company is looking at various options that may be available to meet the future energy requirements of its customers which include: (1) customer conservation resulting from incentive programs, (2) efficiency improvements on the Company's generation, transmission and distribution systems, (3) additional power purchases from CSPP facilities, (4) purchased power and exchange agreements with other utilities and (5) participation in a solar demonstration project. As additional energy demands are placed upon the system, the project or projects best meeting the changed requirements will be pursued. FINANCING PROGRAM The Company's five-year financing program primarily is designed to finance its construction program and to repay maturing long- term debt. The most recent estimate of capital requirements and sources of capital for the period is $598.7 million outlined as follows: 1994 1995-1998 (Millions of Dollars) Capital Requirements: Net cash construction expenditures $119.5 $461.4 Conservation expenditures 11.7 28.5 Other cash expenditures (7.2) (15.2) Total $124.0 $474.7 Sources of Capital: Internal generation $ 69.6 $384.3 Short-term bank loans - Net 17.9 26.1 First mortgage bonds 25.0 108.0 Common stock 13.0 13.0 Cash investments (increase) (1.5) (56.7) Total (a) $124.0 $474.7 [FN] (a) Does not include Ida-West financing. These estimates are subject to constant review in light of changing economic, regulatory and environmental factors and patterns of energy conservation. Any additional securities to be sold will depend upon market conditions and other factors, but it is the Company's objective to maintain capitalization ratios of approximately 45 percent common equity, 8 to 10 percent preferred stock and the balance long-term debt. The Company will continue to take advantage of any refinancing opportunities as they become available. The Company, in its five-year financial forecast, plans to sell additional debt securities and to issue common stock. It further expects that over one-half of its capital requirements will be met through internal cash generation. Under the terms of the Indenture relating to the Company's First Mortgage Bonds, net earnings must be at least two times the annual interest on all bonds and other equal or senior debt. For the twelve months ended December 31, 1993, net earnings were 6.27 times. Additional preferred stock may be issued when earnings for twelve consecutive months within the preceding fifteen months are at least equal to 1.5 times (until December 31, 2000, at which time the issuance ratio will increase to 1.75 times) the aggregate annual interest requirements on all debt securities and dividend requirements on preferred stock. At December 31, 1993, the actual preferred dividend earnings coverage was 2.90 times. If the dividends on the shares of Auction Preferred Stock were to reach the maximum allowed, the preferred dividend earnings coverage would be 2.62 times. The Indenture and the Company's Restated Articles of Incorporation are exhibits to the Form 10-K and reference is made to them for a full and complete statement of their provisions. ITEM 2. PROPERTIES The Company's system includes 17 hydroelectric generating plants located in southern Idaho and eastern Oregon (detailed below) and an interest in three coal-fired steam electric generating plants. The system also includes approximately 4,654 miles of high voltage transmission lines; 21 step-up transmission substations located at power plants; 17 transmission transformer substations; 7 transmission switching stations; and 196 energized distribution substations (excludes mobile substations and dispatch centers). Refer to Item 1 - "Construction Program" for facilities under construction. The Company holds licenses under the Federal Power Act for 13 hydroelectric projects from the FERC. These and the other generating stations and their capacities are listed below: Maximum Non-Coincident Operating Nameplate License Project Capacity KW Capacity KW Expiration Properties Subject to Federal Licenses: Lower Salmon 70,000 60,000 1997 Bliss 80,000 75,000 1998 Upper Salmon 39,000 34,500 1998 Shoshone Falls 12,500 12,500 1999 C J Strike 89,000 82,800 2000 Upper Malad 9,000 8,270 2004 Lower Malad 15,000 13,500 2004 Brownlee-Oxbow-Hells Canyon 1,398,000 1,166,500 2005 Swan Falls 11,100 9,465 2010 American Falls 112,420 92,340 2025 Cascade 14,000 12,420 2031 Twin Falls 10,000 8,437 2041 Milner 59,448 59,448 2038 Other Generating Plants: Other Hydroelectric 10,400 11,300 Jim Bridger (Coal-Fired 693,333 678,077 Station) Valmy (Coal-Fired Station) 260,650 260,650 Boardman (Coal-Fired Station) 53,000 53,000 On December 31, 1993, the composite average ages of the principal parts of the Company's system, based on dollar investment, were: production plant, 15.9 years; transmission system and substations, 17.7 years; and distribution lines and substations, 13.9 years. The Company considers its properties to be well maintained and in good operating condition. The Company owns in fee all of its principal plants and other important units of real property, except for portions of certain projects licensed under the Federal Power Act and reservoirs and other easements, subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses, and to minor defects common to properties of such size and character that do not materially impair the value to, or the use by, the Company of such properties. As a result of various federal legislative actions and proposals (such as the Electric Consumers Protection Act of 1986, Energy Policy Act of 1992, Clean Water Act Reauthorization and Endangered Species Act Reauthorization), a major issue facing the Company is the relicensing of its hydro facilities. Because the federal licenses for the majority of the Company's hydroelectric projects expire during the next 10 to 15 years, the Company has established an internal task force to vigorously pursue the relicensing process. The relicensing of these projects is not automatic under federal law. The Company must demonstrate comprehensive usage of the facilities, that it has been a conscientious steward of the natural resource entrusted to it and that there is a strong public interest in the Company continuing to hold the federal licenses. The Company cannot anticipate what type of environmental or operational requirements may be placed on the projects in the relicensing process, nor can it estimate what the eventual cost will be for relicensing. However, the Company anticipates that its efforts in this matter for all of the hydro facilities will be successful. Idaho Energy Resources Co. owns a one-third interest in certain coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant. Ida-West owns a 50 percent interest in five PURPA-qualified facilities that have a total generating capacity of approximately 34 MW. The energy from these facilities is sold to the Company. ITEM 3. LEGAL PROCEEDINGS The Company is a defendant in a Superfund case entitled United States of America vs. Pacific Hide & Fur Depot, et al., Civil No. 83-4062, pending in the United States District Court for the District of Idaho. The suit involves PCB contamination at a scrap metal/recycling facility near Pocatello, Idaho. The Company entered into a Partial Consent Decree which was signed by the District Judge on September 26, 1989, wherein the Company agreed to remediate PCBs at the site. After completion of certain Initial Tasks and the Final Remedial Design, by letter dated October 4, 1990, EPA notified the Company of the discovery of lead and other metals contamination at levels of concern at the site, and instructed the Company to suspend further remedial action at the site until further notice. On April 24, 1991, the Company initiated discussions with EPA in an effort to facilitate the commencement and completion of PCB remediation. On July 16, 1991, the Company submitted a proposal whereby the PCB and lead/other metal contaminants would be divided into at least two operable units for purposes of site remediation. On January 20, 1992, a Final Operable Unit Focused Feasibility Study was submitted by the Company to EPA. On January 4, 1992, EPA issued a Proposal to Amend Record of Decision which proposed to divide the site into "operable units" to allow for immediate cleanup of PCB contamination at the site through the removal of the PCB and PCB mixed with lead contaminated soils from the site and disposal of the soils at an EPA approved waste facility. An Amended Record of Decision authorizing the foregoing was issued on April 29, 1992. Remedial Design Documents were approved by EPA on July 8, 1992. In order to facilitate the commencement/completion of remedial activities during 1992, an "interim" Administrative Order directing the Company to undertake remedial activities was issued on July 13, 1992. Remediation activities commenced on July 27, 1992, and were completed on October 21, 1992. A Certification of Completion for the Operable Unit Remedial Action dated March 31, 1993, was issued by EPA to the Company. The Amended Partial Consent Decree which will supersede EPA's "Interim" Administrative Order has not yet been completed. On August 30, 1993, Notice of the Lodging of the Amended consent Decree was published in the Federal Register, creating a 30-day period for public comment. On September 30, 1993, the Company was advised that the public comment period would be extended until October 21, 1993, at which time, barring any disclosure of facts or considerations which indicate that the proposed settlement is inappropriate, improper or inadequate, the District Court for the District of Idaho should enter a final judgment in the matter resolving the government's claims against the Company. Pursuant to the Request for Public Comment, a number of Potentially Responsible Parties involved with the lead contamination at the site filed objections to the proposed Amended Consent Decree. The objections generally contend that the government's information relating to the Company's contribution to the lead contaminations at the site is erroneous, and that the Company's proposed settlement is disproportionately low in relation to its liability. On November 19, 1993, the Company provided the Department of Justice with its responses to the objections. The government is continuing to prepare its responsive comments to the objections. The Company was advised on February 8, 1994, that the government anticipated the filing of its responsive summary with the court by the end of February 1994. This matter has been previously reported in Form 10-K dated March 9, 1989, March 8, 1990, March 14, 1991, March 16, 1992, March 12, 1993, and other reports filed with the Commission. On February 16, 1994, an action for declaratory relief and breach of contract entitled Idaho Power Company vs. Underwriters at Lloyds London, et al., was filed by the Company in Federal District Court in Pocatello, Idaho, against its solvent liability insurers in the period of 1969 to 1974, arising out of the insurer's denial of coverage for the Company's environmental remediation of a hazardous waste site in Pocatello. The action seeks a declaratory judgment that the policies cover the Company's costs of defending claims related to the site and of site remediation, and damages for the insurers' breach of the insurance contracts based on their failure to pay such costs, which at the present time are approximating $6.9 million. On December 6, 1991, a complaint entitled Nez Perce Tribe, Plaintiff, v. Idaho Power Company, Defendant, Civil No. CIV 91- 0517-S-EJL, was filed against the Company in the United States District Court for the District of Idaho. The Company was served with the Complaint on March 26, 1992. In the Complaint, the Tribe contends that pursuant to treaties with the United States Government including the Treaty of June 11, 1855, 12 Stat. 957, and the Treaty of June 9, 1863, 14 Stat. 647, the right to take fish at all usual and accustomed fishing places outside the Nez Perce Reservation and the exclusive right to take fish in all streams running through or bordering the reservation were reserved for the Tribe in said treaties. The Complaint further states that the Snake River supported substantial runs of anadromous fish and that the construction of Brownlee, Oxbow and Hells Canyon Dams in 1958, 1961 and 1967, respectively, created total barriers to the migration of the anadromous fish, thereby destroying the fish runs and violating the reserved fishing rights stated in the above-described treaties. In the Complaint, the Tribe seeks actual, incidental and consequential damages in amounts to be proven at trial together with $150,000,000 in punitive damages as well as pre- and post-judgment interest and costs and attorney fees. On September 11, 1992, the Tribe filed an Amended Complaint in which it amplified its original Complaint by asserting that Brownlee, Oxbow and Hells Canyon Dams were "constructed, operated and maintained in such a manner as to damage plaintiff's rights" to harvest fish, which rights the Tribe asserts to be "present, possessory property right(s)". As the basis for its alleged right to recover damages from the Company, the Tribe asserts that the Company negligently constructed, operated and maintained Brownlee, Oxbow and Hells Canyon Dams, that the Company negligently failed to prevent or mitigate harm to the Tribe, that the Company intentionally and willfully destroyed, interfered with, and dispossessed the Tribe of its property rights, and that the Company improperly exercised dominion over the Tribe's property, thus depriving the Tribe of its possession. The Tribe has requested to try its case to a jury. As was true for the Tribe's original Complaint, the Tribe seeks through its Amended Complaint to secure actual, incidental, and consequential damages in amounts to be proven at trial, together with pre and post- judgment interest, costs and disbursements of the action, attorney fees and witness fees. The Amended Complaint restates the Tribe's claim for punitive damages, but omits the prior reference to a sum certain in favor of requesting punitive damages in an "amount sufficient to punish the defendant and deter others". On September 18, 1992, the Company filed a motion for summary judgment in the hope of securing dismissal of the Tribe's action. On January 19, 1993, a federal court hearing was held before a federal magistrate on the Company's motion for summary judgment. On July 30, 1993, the magistrate issued a Report and Recommendation to the District Judge wherein it was recommended that the Company's motion for summary judgment be granted. The Tribe filed briefing in which it urged the District Court to reject the Magistrate's Report and Recommendation, and the Company responded with a request that the District Court enter summary judgment in accordance with the Magistrate's opinion. On November 30, 1993, the District Court entered a second order of reference, in which the court sent the case back to the Magistrate for the Magistrate to make additional findings with respect to the Tribe's contention that it is entitled to compensation based on physical exclusion from its usual and accustomed fishing places. The Magistrate ordered the parties to brief this issue. That briefing was concluded, and oral argument was held before the Magistrate on February 11, 1994. On February 28, 1994, the Magistrate issued a Second Report and Recommendation wherein it was recommended that the District Court deny the Company's motion for summary judgment as to the tribes claim for damages arising from precluding the tribe access to its usual and accustomed fishing places and reaffirmed its recommendation in the original Report and Recommendation to grant the Company's motion for summary judgment as to all other claims. The lawsuit is still in the early stages, and the Company is unable to predict the outcome of this case. However, the Company believes its actions were lawful and intends to vigorously defend this suit. This matter has been previously reported in Form 10-K dated March 16, 1992, March 12, 1993, and other reports filed with the Commission. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None EXECUTIVE OFFICERS OF THE REGISTRANT The names, ages and positions of all of the executive officers of the Company are listed below along with their business experience during the past five years. Officers are elected annually by the Board of Directors. There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was elected. Business Experience During Past Five Name, Age and Position (5) Years J. W. Marshall, 55 Appointed August 18, 1989. Chairman of the Board Mr. Marshall was Executive Vice and Chief Executive President prior to August 18, 1989. Officer L. R. Gunnoe, 58 Appointed July 12, 1990. President and Chief Mr. Gunnoe was Vice President - Operating Officer Distribution prior to July 12, 1990. Daniel K. Bowers, 46 Appointed July 10, 1986. Vice President and Treasurer J. LaMont Keen, 41 Appointed November 14, 1991. Vice President and Mr. Keen was Controller prior to Chief Financial Officer November 14, 1991. Douglas H. Jackson, 57 Appointed July 12, 1990. Vice President - Mr. Jackson was Senior Manager of Distribution Corporate Services prior to July 12, 1990, and Assistant to the Chairman and Chief Executive Officer prior to August 21, 1989. Paul L. Jauregui, 52 Appointed June 4, 1988. Vice President - Human Resources C. N. Olson, 44 Appointed July 11, 1991. Mr. Olson Vice President - was Senior Manager - Corporate Corporate Services Services prior to July 11, 1991, Senior Manager - Administrative Services prior to September 1, 1990, Distribution Engineering and Construction Manager prior to February 1, 1990, and Division Electrical Superintendent prior to May 29, 1989. J. B. Packwood, 50 Appointed July 13, 1989. Vice President - Mr. Packwood was Senior Manager - Power Supply Power Supply, prior to July 13, 1989. Robert W. Stahman, 49 Appointed July 13, 1989. Vice President, General Mr. Stahman was General Counsel and Counsel and Secretary Secretary prior to July 13, 1989. Harold J. Hochhalter, 58 Appointed January 9, 1992. Controller and Chief Mr. Hochhalter was Manager of Accounting Officer Corporate Accounting and Reporting prior to January 9, 1992. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Company has paid cash dividends on its common stock in each year since 1918. For the years of 1991, 1992 and 1993, cash dividends per share of common stock were $1.86. At the July 1993 meeting, the Board of Directors voted to maintain the annual common dividend at $1.86 per share. It is the intention of the Board of Directors to continue to pay dividends quarterly on the common stock, but such dividends in the future will depend on earnings, cash requirements of the Company and other factors. The common stock is listed on the New York and Pacific stock exchange. For the years of 1992 and 1993, the following table indicates the reported high and low sale price of the Company's common stock as reported by the Wall Street Journal as composite tape transactions. The holders of record of the Company's common stock as of December 31, 1993 was 26,870. 1992 (Quarters) Common Stock, $2.50 par value: 1st 2nd 3rd 4th High $28 3/4 $26 3/8 $27 1/4 $28 1/8 Low 24 3/8 24 3/4 25 1/4 25 1/2 Dividends paid per share (cents) 46.5 46.5 46.5 46.5 1993 (Quarters) Common Stock, $2.50 par value: 1st 2nd 3rd 4th High $30 3/8 $31 1/2 $33 $32 7/8 Low 27 1/4 27 7/8 31 29 1/8 Dividends paid per share (cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA SUMMARY OF OPERATIONS (000 1993 1992 1991 1990 omitted) Revenues: General business $428,658 $431,818 $409,454 $401,350 Sales to other utilities 86,525 42,000 52,563 44,368 Other revenues 25,219 24,274 21,176 19,217 Total revenues 540,402 498,092 483,193 464,935 Expenses: Purchased power 45,361 58,496 51,210 43,923 Fuel expense 87,855 96,710 75,161 77,606 Other operation and 164,388 137,547 151,593 134,126 maintenance Depreciation 58,724 59,823 57,597 55,114 Taxes other than income taxes 22,129 20,562 21,168 20,752 Total expenses 378,457 373,138 356,729 331,521 Income from operations 161,945 124,954 126,464 133,414 Other income and deductions - (12,984) (11,133) (9,453) (11,666) Net Interest charges - Net 53,991 52,935 56,901 52,605 Income taxes 36,474 23,162 21,144 23,234 Cumulative effect of accruing unbilled revenues - - - - Net income 84,464 59,990 57,872 69,241 Dividends on preferred stocks 6,009 5,516 4,904 4,279 Earnings on common stock 78,455 54,474 52,968 64,962 Dividends on common stock 67,959 65,043 63,197 63,197 Net change to retained earnings $ 10,496 $(10,569) $(10,229) $ 1,765 CAPITALIZATION (000 omitted) % % % % First mortgage bonds $490,000} 47 $485,000} 49 $435,000} 48 $367,500} 46 Other long-term debt 203,780 216,948 194,981 194,159 Mandatory redeemable preferred stock -} 9 -} 7 -} 8 -} 5 Preferred stock 132,751 107,874 108,191 58,761 Common stock (incl. prem. & exp.) 439,467} 44 412,998} 44 356,824} 44 358,078} 49 Retained earnings 222,900 212,404 222,973 233,241 Total capitalization $1,488,898 100 $1,435,224 100 $1,317,969 100 $1,211,739 100 Short-term borrowings outstanding $4,000 $6,000 $48,500 $48,280
SUMMARY OF OPERATIONS (000 1989 1988 1987 1986 omitted) (Cont'd) Revenues: General business $397,974 $362,050 $343,899 $336,480 Sales to other utilities 70,749 32,175 35,447 54,987 Other revenues 27,438 18,096 15,251 17,394 Total revenues 496,161 412,321 394,597 408,861 Expenses: Purchased power 43,845 43,723 30,234 31,849 Fuel expense 77,127 74,528 65,934 31,260 Other operation and maintenance 132,114 116,230 114,235 114,407 Depreciation 53,092 51,691 50,929 49,308 Taxes other than income taxes 20,213 19,301 19,072 18,539 Total expenses 326,391 305,473 280,404 245,363 Income from operations 169,770 106,848 114,193 163,498 Other income and deductions - Net (10,005) (6,552) (13,115) (17,064) Interest charges - Net 52,997 50,762 51,843 51,206 Income taxes 42,041 13,558 27,246 50,923 Cumulative effect of accruing unbilled revenues - - (11,302) - Net income 84,737 49,080 59,521 78,433 Dividends on preferred stocks 4,285 4,293 4,298 10,553 Earnings on common stock 80,452 44,787 55,223 67,880 Dividends on common stock 62,177 61,159 61,159 59,755 Net change to retained earnings $ 18,275 $(16,372) $ (5,936) $ 8,125 CAPITALIZATION (000 omitted) % % % % First mortgage bonds $377,000} 47 $392,000} 47 $407,000} 47 $432,000} 47 Other long-term debt 165,551 164,426 160,003 153,887 Mandatory redeemable preferred stock -} 5 -} 5 -} 5 -} 5 Preferred stock 58,923 59,126 59,238 59,403 Common stock (incl. prem. & exp.) 357,986} 48 357,866} 48 357,797} 48 357,708} 48 Retained earnings 231,476 213,201 229,573 235,509 Total capitalization $1,190,936 100 $1,186,619 100 $1,213,611 100 $1,238,507 100 Short-term borrowings outstanding $31,000 $37,000 $4,000 $5,000
SUMMARY OF OPERATIONS (000 1985 1984 1983 omitted) (Cont'd) Revenues: General business $336,705 $324,701 $289,905 Sales to other utilities 98,980 86,724 67,358 Other revenues 15,495 16,422 18,881 Total revenues 451,180 427,847 376,144 Expenses: Purchased power 16,188 1,215 (6,788) Fuel expense 81,961 50,850 44,283 Other operation and 125,728 119,604 109,392 maintenance Depreciation 45,595 40,974 39,038 Taxes other than income taxes 16,790 16,363 15,119 Total expenses 286,262 229,006 201,044 Income from operations 164,918 198,841 175,100 Other income and deductions - Net (20,352) (11,191) (20,174) Interest charges - Net 47,891 45,579 45,591 Income taxes 52,556 64,418 61,602 Cumulative effect of accruing unbilled revenues - - - Net income 84,823 100,035 88,081 Dividends on preferred stocks 12,447 13,617 15,917 Earnings on common stock 72,376 86,418 72,164 Dividends on common stock 56,277 52,221 47,691 Net change to retained earnings $ 16,099 $ 34,197 $ 24,473 CAPITALIZATION (000 omitted) % % % First mortgage bonds $467,000} 47 $467,000} 47 $467,000} 47 Other long-term debt 149,074 138,452 112,046 Mandatory redeemable preferred stock 63,000} 9 63,000} 10 88,000} 12 Preferred stock 60,585 61,079 61,500 Common stock (incl. prem. & exp.) 355,007} 44 342,038} 43 329,776} 41 Retained earnings 230,558 214,459 183,562 Total capitalization $1,325,224 100 $1,286,028 100 $1,241,884 100 Short-term borrowings outstanding $ - $ - $ -
FINANCIAL STATISTICS 1993 1992 1991 1990 Income from operations as a percent of total revenues 30.0% 25.1% 26.2% 28.7% Times interest charges earned: Before tax 3.14 2.50 2.34 2.72 After tax 2.50 2.08 1.98 2.29 Market-to-book ratio 170% 159% 168% 148% Payout ratio 87% 120% 119% 97% Return on year-end common equity 11.84% 8.71% 9.14% 10.99% Common stock data: Earnings per average share outstanding $2.14 $1.55 $1.56 $1.91 Dividends declared per share $1.86 $1.86 $1.86 $1.86 Book value per share $17.86 $17.28 $17.07 $17.40 Average shares outstanding (000 omitted) 36,675 35,116 33,977 33,977 Common shareowners 26,870 27,834 28,069 29,080 CUSTOMER DATA General business data: Energy sales - kwh (000,000 omitted) 11,406 11,606 11,266 11,086 Number of customers 317,772 307,567 297,808 291,800 Residential customer data: Number of customers 263,682 255,022 246,689 241,790 Average kwh use per customer 14,587 13,856 14,845 14,281 Average rate per kwh (cents) 4.82 4.80 4.72 4.73 OTHER STATISTICS Total assets (000 omitted) $2,097,417 $1,862,307 $1,773,674 $1,680,110 Gross plant additions (000 omitted) $116,972 $118,920 $135,904 $80,117 Number of employees (full-time) 1,654 1,638 1,626 1,574
FINANCIAL STATISTICS (Cont'd) 1989 1988 1987 1986 Income from operations as a percent of total revenues 34.2% 25.9% 28.9% 40.0% Times interest charges earned: Before tax 3.30 2.18 2.76* 3.40 After tax 2.53 1.93 2.10* 2.46 Market-to-book ratio 169% 138% 127% 150% Payout ratio 77% 137% 111% 88% Return on year-end common equity 13.65% 7.84% 9.40% 11.44% Common stock data: Earnings per average share outstanding $2.37 $1.32 $1.63* $2.00 Dividends declared per share $1.83 $1.80 $1.80 $1.76 Book value per share $17.35 $16.81 $17.29 $17.46 Average shares outstanding 000 omitted) 33,977 33,977 33,977 33,961 Common shareowners 30,291 32,225 33,733 34,456 * Includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kwh (000,000 omitted) 11,069 10,563 10,175 9,938 Number of customers 284,363 279,529 276,249 274,129 Residential customer data: Number of customers 236,008 232,650 230,486 228,921 Average kwh use per customer 14,923 14,364 13,785 14,541 Average rate per kwh (cents) 4.69 4.47 4.34 4.21 OTHER STATISTICS Total assets (000 omitted) $1,625,120 $1,608,935 $1,602,311 $1,621,887 Gross plant additions (000 omitted) $62,094 $64,358 $38,929 $50,257 Number of employees (full-time) 1,528 1,500 1,521 1,524
FINANCIAL STATISTICS (Cont'd) 1985 1984 1983 Income from operations as a percent of total revenues 36.6% 46.5% 46.6% Times interest charges earned: Before tax 3.61 4.12 4.00 After tax 2.61 2.90 2.77 Market-to-book ratio 133% 114% 106% Payout ratio 78% 60% 66% Return on year-end common equity 12.36% 15.53% 14.06% Common stock data: Earnings per average share outstanding $2.16 $2.63 $2.25 Dividends declared per share $1.68 $1.59 $1.49 Book value per share $17.29 $16.74 $15.77 Average shares outstanding (000 omitted) 33,544 32,893 32,070 Common shareowners 35,959 35,216 35,967 CUSTOMER DATA General business data: Energy sales - kwh (000,000 omitted) 10,366 10,191 9,599 Number of customers 272,155 268,974 265,197 Residential customer data: Number of customers 227,562 225,319 222,625 Average kwh use per customer 15,432 15,342 14,066 Average rate per kwh (cents) 3.98 4.01 3.69 OTHER STATISTICS Total assets (000 omitted) $1,646,847 $1,584,874 $1,518,011 Gross plant additions (000 omitted) $74,064 $99,028 $102,970 Number of employees (full-time) 1,568 1,725 1,705
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Idaho Power Company's consolidated, wholly-owned subsidiaries consist of Idaho Energy Resources Co. (IERCO), Ida-West Energy Company (Ida-West), IDACORP, INC, and Idaho Utility Products Company (IUPCO). Together, Idaho Power and these subsidiaries are referred to herein as the Company. EARNINGS PER SHARE Earnings per share of common stock increased to $2.14 in 1993 as compared to $1.55 in 1992 and $1.56 in 1991. The lower earnings per share in 1991 and 1992 resulted from drought conditions and accompanying low streamflows. The improved 1993 earnings reflect more favorable hydroelectric conditions and a gain on the sale of the Wood River turbine to offset the impact of the 1993 federal income tax increase. The Company also recorded income tax reserve adjustments relating to the settlement of prior years' returns (1983-1990) during the fourth quarter. The two actions combined to increase the year's earnings approximately $6.0 million over 1992. The 1993 earnings equate to an 11.8 percent earned return on year-end common equity compared to the 8.7 percent earned in 1992 and 9.1 percent earned in 1991. Book value per share of common stock was $17.86 at December 31, 1993. RESULTS OF OPERATIONS Precipitation and Streamflows Heavy spring precipitation and cool summer temperatures in the Company's service territory coupled with near normal accumulations of snow last winter propelled the 1993 water year to more than three times that of 1992. Streamflows into Brownlee Reservoir (which provides water to the three dam Hells Canyon complex which generates about half of the electricity produced by the Company in a normal water year) were 5.97 million acre-feet (MAF) compared to only 1.8 MAF during 1992. Inflows into Brownlee during 1993 were nearly 25 percent above the 63-year median of 4.81 MAF. Energy Requirements Even though streamflows were much improved, hydro generation did not fully return to normal levels during 1993. The major adverse factors were the carryover effects of six years of drought conditions on reservoirs and the aquifer and the inability to fully utilize hydro generation capability during the first few months of 1993, as the Company was restoring and then maintaining Brownlee reservoir levels for later use. The Company's hydroelectric output accounted for 52 percent of its total energy requirements in 1993, a substantial increase from 35 percent in 1992 and 41 percent in 1991. Thermal generation accounted for 40 percent of total energy requirements with purchased power and other exchanges accounting for 8 percent during 1993. Under normal conditions the Company's hydro system would contribute approximately 58 percent with thermal generation providing approximately 36 percent and the remaining 6 percent from purchased power and other interchanges. Although it is too early to predict with certainty what hydroelectric conditions will be during 1994, preliminary reports indicate the mountain snowpack is again below normal. However, carryover reservoir storage is above average throughout the Snake River Basin. The Company expects to meet projected energy loads during the coming year by utilizing its hydro and coal-fired facilities and strategic geographic location - which provides excellent opportunities to purchase, sell, exchange and transmit Northwest energy - even if below normal streamflow conditions prevail. Economy For the fifth year the state of Idaho and the Company's service territory continued to experience extraordinary economic growth. For the state, nonagricultural employment gains of an expected 3.0 percent in 1993 were preceded by 4.6 percent in 1992 and 3.3 percent in 1991. The Company's service area exceeded state-wide results with expected gains in non-agricultural employment of nearly 4.0 percent in 1993 with 5.3 percent and 5.4 percent in 1992 and 1991. Population growth in the Company's service area remains strong. Residential customer growth increased by 2.0 percent in 1991, 3.4 percent in 1992 and 3.4 percent in 1993. New households in the service area are forecasted to grow at a 3 percent annual average rate during the next five years with population growth estimated to exceed 2.2 percent per year over the same period. Power Cost Adjustment In 1992, the Company asked the Idaho Public Utilities Commission (IPUC) to adopt a Power Cost Adjustment (PCA) mechanism that would enable the Company to collect, or require it to refund, all or a portion of the difference between net power supply costs actually incurred and those allowed in the base rates of the Company. The PCA is intended to avoid the need for temporary rate increases during low water years and will return benefits to customers in high water years. For the current year (May 1993 through April 1994) the PCA will be applied to 60 percent of the power cost deviations from normalized rates. After the Company's next general revenue requirement case is completed, the PCA will be raised to 90 percent of power supply costs. On March 29, 1993, the IPUC approved a PCA mechanism in substantially the form proposed by the Company. Under the approved PCA, customers' power rates will be adjusted annually to reflect forecasted changes in the Company's net power supply costs in the current year and to true-up any deviation between forecasted and actual costs for the previous year. In May 1993, the Company implemented its first PCA rate increase of $5.0 million. The current balance is adjusted monthly as actual conditions are compared to the forecasted net power supply costs. The final cumulative PCA amount as of May 15, 1994 will be included in the true-up portion of the 1994 PCA. Revenue For the three-year period 1991, 1992, and 1993, an average of 87 percent of the Company's operating revenues were derived from electric sales in Idaho, 5 percent in Oregon, less than 1 percent in Nevada and 8 percent from the wholesale market. For the same three year period, residential customers averaged 34 percent of the Company's total operating revenues. Commercial and industrial customers with less than 750 Kw demand combined with irrigation and street lighting customers averaged 30 percent and commercial and industrial customers with 750 Kw demand and over averaged 19 percent. Sales to other utilities and interchange arrangements averaged 12 percent, and miscellaneous revenues averaged 5 percent. Energy sales to the Company's general business customers increased 1.6 percent in 1991, 3.0 percent in 1992 but decreased 1.7 percent in 1993. These increases reflect the strong economic growth in the Company's service territory and varied temperature, precipitation and energy usage patterns. The decrease for 1993 resulted from a wet spring which reduced irrigation sales by 28.8 percent and temporary changes in operations at two of the Company's large industrial customers which lowered consumption during 1993. FMC Corporation's (FMC) elemental phosphorus production plant reduced operations at times during 1993 due to market conditions for the sale of its manufactured product. FMC also intends to maintain this reduced production level for a portion of 1994. The Idaho National Engineering Laboratory's (INEL) 1993 electrical use was down and can be volatile due to federal regulatory mandates and maintenance schedules. The INEL estimates a steady growth in the amount of consumption during 1994 and beyond. General business revenues constitute approximately 84 percent of total operating revenues and were $409.5 million in 1991, $431.8 million in 1992 and $428.7 million in 1993. The increase in 1992 reflects an increase in irrigation revenues due to the drought and an increase in the number of customers served along with the temporary rate relief granted by the IPUC in May 1992. The decrease in 1993 results from the 27.9 percent decrease in irrigation revenue due to the wet spring which was partially offset by increases in residential revenues (9.3 percent) and small commercial revenues (4.0 percent). The number of general business customers served increased by 8.9 percent (or 25,972 customers) during the three year period. Energy usage per residential customer was 14,845 Kwh in 1991 versus 13,856 Kwh in 1992 and 14,587 Kwh in 1993. Total operating revenues increased $18.3 million or 3.9 percent in 1991, $14.9 million or 3.1 percent in 1992, and $42.3 million or 8.5 percent in 1993. The increase for 1992 was due in part to the temporary rate relief granted by the IPUC in May 1992, along with an increase in customers served, while the increase for 1993 was due to increased opportunity sales to other utilities resulting from improved hydroelectric conditions and an increase in the number of general business customers. Regulatory Action Drought-Related Temporary Rate Increases In response to drought conditions which reduced streamflows and increased power supply costs, the Company requested temporary rate relief several times during the three year period. In May 1992, the IPUC issued an order which authorized the Company to put in place for a twelve-month period a temporary rate increase of 3.9 percent or $15.0 million in additional revenues. At the same time the temporary rate increase ceased in May 1993, the Company implemented its first PCA rate increase of $5.0 million, combining for a net decrease of $10.0 million in rates. In 1992 the Company received Oregon Public Utility Commission (OPUC) authority to defer with interest 33.5 percent of Oregon's share of increased power production costs starting on March 23, 1992 and continuing through December 31, 1992. The Company subsequently filed a request and received approval from the OPUC for a 24 month amortization period of an annual rate increase of $526,360 or 2.57 percent effective July 1, 1993. The Company also submitted a rate increase request to the Federal Energy Regulatory Commission (FERC) to increase rates to certain wholesale customers. The FERC granted a $547,900 rate increase for a twelve-month period effective November 10, 1992. On January 8, 1993, the IPUC authorized the Company to suspend five and one-half months (January 1, 1993, through June 15, 1993) of the revenue deferral associated with the Afton generation facility for a total of $1,225,707. This allowed the Company to defer additional 1992 reserve capacity (purchased generation available to meet load if needed) costs of $1,225,707 against the suspension of revenue deferral in 1993. General Revenue Requirement Case The Company intends to file a general revenue requirements case in its Idaho retail jurisdiction during 1994 and may also file in its Oregon retail jurisdiction. The purpose of the filing is to bring all of the Company's cost components to a current level in response to concerns expressed by the IPUC and various customer groups in recent regulatory proceedings regarding the length of time since the Company's costs were reviewed on a composite basis. In these proceedings the Company indicated that an opportunity for such a review would occur in the 1993/1994 time frame and full implementation of the PCA will not occur until such a proceeding is completed. The amount of any additional revenue requirement to be requested has not yet been determined. When a case is filed the Company's allowed return on common equity will, among other things, be subject to review. Recent allowed returns on equity granted nationally have declined as a result of the current low interest rate environment. Low allowed returns on equity are a concern because they have created a contrast with dividend payout levels set during periods of higher interest rates for some utilities. The Company will seek an allowed return on equity above its present dividend yield on year- end book value sufficient to provide current earnings to cover dividend payments, but cannot predict the final outcome of such rate proceedings in the current low interest rate environment. Off-System Sales Revenues from sales to other utilities increased $8.2 million in 1991, decreased $10.6 million in 1992 but increased $44.5 million in 1993. These deliveries are comprised of firm sales, which are long-term contractual arrangements, and opportunity sales which are made on a when available basis. The volume and price of these sales depend on the Company's firm energy demand, hydrogeneration conditions in the Company's service area, and market conditions throughout the West. Revenues from firm sales to other utilities amounted to $41.5 million in 1991, $37.5 million in 1992 and $45.4 million in 1993. The decrease for 1992 was due to the termination at the end of 1991 of a short-term firm sales agreement and a reduction in the amount of energy taken by another customer pursuant to contract agreements. Revenues from opportunity sales to other utilities amounted to $11.0 million for 1991, decreased to $4.5 million in 1992 but increased to $41.1 million in 1993. For the years 1991 and 1992, the drought's adverse effect on the Company's hydrogeneration resulted in reduced sales, while in 1993 the return to more normal hydro conditions increased dramatically the volume of sales and revenue. Expenses Total operating expenses increased $25.2 million in 1991, $16.4 million in 1992 and $5.3 million in 1993. The increases for 1991 and 1992 reflect the drought conditions which increased reliance on thermal generation and purchased power. The increase in operating expenses for 1993 reflects the deferral of certain net power supply costs to 1993 from 1992 to better match drought related expenses with surcharge revenues. Maintenance expense for 1993 increased reflecting more normal operating conditions. Purchased power expenses were high and fluctuated during the last three years reflecting necessity purchases from neighboring utilities during the drought periods and increased purchases from cogeneration and small power production (CSPP) projects during 1993 as a result of the improved hydro conditions. The estimated annualized cost for the 61 CSPP projects on-line as of December 31, 1993, is currently $40.6 million. The Company increased utilization of its thermal facilities by operating at high capacity factors during the drought which increased fuel expense for 1992 by $21.5 million. In 1993 fuel expense decreased $8.9 million as a direct result of increased availability of hydro facilities to meet customer demand. All other operation and maintenance expenses increased $30.3 million over the same three year period. These increases were due, in part, to an increase in payroll and benefits ($10.1 million and 80 new employees), an increase in maintenance expense ($7.2 million) due to a return to more normal operating conditions and an increase in thermal operations ($6.0 million). Depreciation expense increased for the three year period by $3.6 million or 6.6 percent due to a greater plant investment base. Taxes other than income taxes increased $1.4 million or 6.6 percent due to increased property taxes and taxes on increased generation and sale of hydro power. Interest Charges Interest charges on long-term debt fluctuated during the three- year period, ultimately increasing by $2.7 million reflecting the maturity, early redemption, and issuance of several series of first mortgage bonds. The Company took advantage of the declining interest rate environment and refinanced several higher cost bond issues. These refinancings reduced the overall cost of debt and annual interest expense which largely offset the cost of additional financing (see Note 6 of Notes to Consolidated Financial Statement). Interest on short-term debt fluctuated due to varying interest rates on short-term debt during the period and changes in the level of short-term debt borrowings (see Notes 7 of Notes to Consolidated Financial Statement). The Company purchased Prairie Power Cooperative's (PPC) assets on July 24, 1992 and under the terms of the acquisition agreement with PPC, assumed the Cooperative's long-term debt (REA notes) of approximately $1,914,000. Income Taxes In August 1993, Congress enacted the "Omnibus Budget Reconciliation Act of 1993" which, among other things, changed the statutory corporate federal income tax rate from 34 percent to 35 percent retroactive to January 1, 1993. Accordingly, taxes on current income were computed at the new higher rate. The Company requested and received from the IPUC permission to offset these higher taxes against a portion of the gain from the disposition of the Wood River Turbine recorded in 1993. The actual rates charged for electric service will not change due to the tax increase until the next general revenue requirement case is finalized. Also during 1993, the Company settled federal tax liabilities on the 1987 through 1990 tax years except for immaterial amounts that relate to a partnership. Ida-West Ida-West Energy Company (Ida-West), a wholly owned subsidiary of the Company, through various partnerships, has completed construction of the Hazelton B Project, the Wilson Lake Project and the Falls River Project. Third parties unaffiliated with Ida- West own 50 percent of each of these projects and the South Forks Project (which an Ida-West subsidiary and its partner acquired as an operating project in March 1992), thus satisfying "qualifying facility" status under PURPA guidelines. These partnerships have obtained project financing (non-recourse to the Company) having recently procured the initial permanent financing for the Hazelton B and Wilson Lake Projects from a single institutional investor and for the Falls River Project from a commercial lending institution. Construction of both the Hazelton B and Wilson Lake Projects started in July 1991, and commenced commercial operation in May 1993. Construction of the Falls River Project began in August 1991, and started commercial operation in August 1993. As a result of a construction-related incident involving the Falls River Project in 1992, the cost to complete the project increased from $15 million to $28.1 million, net after recovery of $2.56 million from insurance carriers. To help defray a portion of these additional costs, the project entity obtained an increase in project financing from $11.5 million to $18 million. On June 16, 1993, the FERC issued a notice proposing civil penalties of no more than $500,000 for alleged license and FERC regulation violations in connection with the construction of the Falls River Project. The project entity is currently negotiating with the FERC for a reduction of these penalties and has recorded a portion of them as a liability. On August 13, 1993, the state of Idaho appealed to the Ninth Circuit the FERC's June 16 denial of the state's request for rehearing of the FERC's January 13 order allowing resumption of construction. On November 24, 1993, the project entity reached a settlement with the state. Under the settlement, the project entity paid the state $150,000 for deposit into a fund to be used for studies and mitigation activities in the project vicinity, and the state dropped the appeal and released the project entity from any further liability arising out of past construction incidents. As part of its Resource Contingency Program, the Bonneville Power Administration (BPA) requested proposals to provide up to 800 average megawatts of energy options. Ida-West along with two partners submitted a proposal for a 227 megawatt gas-fired cogeneration project to be located near Hermiston, Oregon, which was one of ten projects being given final consideration by BPA. On June 4, 1993, BPA selected the partnership's project, together with two other projects, to participate in the program. The partnership and BPA have signed an option development agreement which grants BPA an option to acquire energy from the project at any time during a five year option hold period after all option development period tasks, including permitting, have been completed. The partnership expects these development period tasks to be completed by year-end 1995. The Company made an additional investment of $8.0 million in Ida- West during 1993 bringing its total equity investment to $20 million. Ida-West continues to actively seek or develop new projects. LIQUIDITY AND CAPITAL RESOURCES Cash Flow Net cash generation from operations for the three-year period amounted to $365.4 million. After deductions for both common and preferred dividends ($212.3 million), net cash generation from operating activities provided approximately $153.1 million for the Company's construction program and other capital requirements. Internal cash generation after dividends provided 33 percent of the total capital requirements in 1991, 30 percent in 1992, 54 percent in 1993, and is projected to provide approximately 53 percent in 1994 and 73 percent during the five-year period 1994- 1998. The Company expects to continue financing its construction program using both internally generated funds, and to the extent required, externally financed capital. Drought conditions have negatively impacted the Company's internal cash generation in two of the last three years. In its 1994-1998 five-year forecast the Company anticipates issuing additional common stock and first mortgage bonds. During the forecast period, the Company also has first mortgage bond refundings of $20 million in 1996 and $30.0 million in 1998. At January 1, 1994 the total lines of credit maintained by the Company with various banks amounted to $70 million. (See Note 7 of Notes to Consolidated Financial Statements.) Cash Construction Expenditures The Company's consolidated cash construction expenditures were $133.7 million in 1991, $118.0 million in 1992, and $122.9 million in 1993. During 1992, in response to the ongoing drought conditions, the Company's cash construction budget was reduced. Approximately 44 percent of these expenditures were spent on generation facilities, 9 percent for transmission facilities, 32 percent for distribution facilities and 15 percent on general plant and equipment. Principal additions during the period to the Company's plant investment base include the completion of the Milner Powerhouse in October 1992. Testing at the Milner project was completed and the units were declared available for commercial operation during the fall of 1992. The total cost of construction at December 31, 1993 is $56.3 million including allowance for funds used during construction. Prairie Power On June 30, 1992, the Company received approval from the IPUC to acquire the Prairie Power Cooperative (PPC) and provide service to its customers. Under the terms of the acquisition agreement, which was consummated on July 24, 1992, the Company acquired PPC's assets by assuming the cooperative's long-term debt of approximately $1.9 million. The Company agreed also to implement over the next ten years a $2.0 million rehabilitation of the distribution system and reduced those PPC customers' rates by 15 percent from PPC rates effective at the time of the acquisition. The new reduced rates will remain frozen at that level for 10 years and are higher than the Company's present rates for other Idaho retail customers. Wood River Turbine Sale In 1993 the Company sold a 50-megawatt gas fired turbine generator for $8.0 million. The Company's after-tax gain was $4.2 million ($3.6 applicable to the Idaho jurisdiction). The Company requested and received from the IPUC permission to use a portion of the gain from the turbine sale as an offset to the increased revenue requirement resulting from the additional income taxes for 1993. Construction Program The Company's construction program (as detailed below) for the 1994-1998 period includes the rebuild of the Swan Falls hydro facility and expansion of the Twin Falls hydro facility. The Company's 1994 cash construction expenditures are expected to be approximately $119.5 million with the 1994-1998 total presently estimated at $580.9 million. Swan Falls Construction started in 1991 to rebuild the Swan Falls powerhouse and increase its generating capacity from 12 megawatts to 25 megawatts. The amended FERC license provides for the retirement of the present powerhouse and construction of a new powerhouse containing two generating units of 12.5 megawatts each with completion scheduled in 1994. The total cash expenditures of the rebuild are presently estimated at $53.6 million with total construction costs at $60.0 million including an allowance for funds used during construction. Twin Falls In January 1991, the Company received a 50-year license from the FERC for the Twin Falls Project that approves increasing the generating capacity from 10 megawatts to 53 megawatts. The Company received approval from the IPUC to rebuild the Twin Falls hydroelectric facility as proposed in its application. Construction started in July 1993 with completion scheduled in mid 1995. The total cash expenditures of the expansion are presently estimated at $32.3 million with total construction costs at $34.2 million including allowance for funds used during construction. Southwest Intertie Project Capitalizing on the Company's strategic location between the Intermountain West and the Pacific Northwest, the Company is considering the construction and operation of a new transmission line which could serve as a major artery for regional transfers of power between north and south. The Southwest Intertie Project (SWIP) is a proposed 520-mile, 500 Kv transmission line which would interconnect the Company's system with utilities in the Southwest. The Bureau of Land Management (BLM) has completed the Final Environmental Impact Statement/Proposed Plan Amendment (EIS) for the SWIP. Approval of the EIS from the BLM is expected during the second quarter of 1994. After approval of the EIS, the economic feasibility of the line will be validated prior to the time the Company proceeds with construction. The Company has received preliminary commitments from various utilities and electric providers for financial participation in the project. It is the Company's intention to retain up to a 20 percent ownership in the line. Solar The Company has joined Southern California Edison, the U. S. Department of Energy and others in retrofitting an existing 10- megawatt solar thermal experimental power plant called Solar 2. The Company will contribute $630,500 over the next three years and the Electric Power Research Institute, of which the Company is a member, will contribute an additional $630,500 of matching funds, bringing the Company's credited contribution to approximately $1.3 million. The project is located near Barstow, California, and should begin generating electricity in 1995. Photovoltaic Systems In August 1992, the Company proposed a $5 million three-year pilot program to design, install, and maintain solar-powered photovoltaic systems for remote locations that would otherwise require costly line extensions. It is the Company's intent to service only those inquiries located in its service territory. The IPUC approved the proposal during September 1993 with the OPUC giving its approval in October 1993 and the Nevada Public Service Commission in June 1993. Financing Program Capital Structure The Company's capital structure (as illustrated in Selected Financial Data) has fluctuated during the three year period with common equity remaining stable at 44 percent, preferred increasing to 9 percent and debt decreasing to 47 percent. It is the Company's objective to maintain capitalization ratios of approximately 45 percent common equity, 8 to 10 percent preferred stock and the balance long-term debt. The Company's strategy is to achieve this target structure through accumulated earnings and issuance of new equity. The Company's pre-tax interest coverage ratios were 2.34 times in 1991, 2.50 times in 1992, and 3.14 times in 1993. The Company has on file a shelf registration statement for the issuance of first mortgage bonds and/or preferred stock with the total aggregate principal not to exceed $200.0 million. The primary financial commitments at year-end 1993 are related to contracts and purchase orders for the Company's program for construction and operation of facilities. Common Stock On July 8, 1992, the Company sold 1,250,000 shares of Common Stock. The net proceeds of $30,706,250 were used for payment of $4.0 million of short-term debt and the Company's ongoing construction program. In 1992, the Company also resumed issuing original issue shares to its Employee Savings Plan, the Dividend Reinvestment and Stock Purchase Plan and the Employee Stock Ownership Plan. During the twelve months ended December 31, 1993 and 1992, common shares totaling 898,528 and 959,527 were issued producing $26.7 million and $25.5 million in proceeds to the Company, which were used for its on-going construction program. Preferred Stock During 1991, the Company issued $25.0 million of serial preferred stock which was used to retire an existing $25.0 million of serial preferred stock. Also, in November 1991, the Company issued $50.0 million of Auction Preferred Stock which proceeds were used to retire early $32.5 million of first mortgage bonds, to retire at maturity $10.0 million of first mortgage bonds and other corporate purposes. On July 1, 1993 the Company utilized its remaining preferred stock shelf registration and issued $25 million of serial preferred stock. The net proceeds of the issuance were used for the Company's ongoing construction program. Long-Term Debt On January 14, 1991, the Company issued $75,000,000 principal amount of first mortgage bonds due January 1, 2021. The net proceeds were used for payment of $48,280,000 of short-term borrowings. The remainder of the funds were invested in temporary cash investments until needed for general corporate purposes. On August 19, 1991, the Company issued $25,000,000 principal amount of first mortgage bonds due August 2031. This series of bonds was issued on a private placement basis and the net proceeds were used for payment of $21,950,000 of short-term borrowings with the remainder used for construction and general corporate purposes. On March 25, 1992, the Company issued $100,000,000 principal amount of first mortgage bonds, $50,000,000 due in 2004, and $50,000,000 due in 2027. The net proceeds were used to pay down $36,000,000 of outstanding commercial paper notes, the early redemption of $50,000,000 of existing first mortgage bonds due 2004, and for the Company's ongoing construction program. On April 28, 1993 the Company issued $160,000,000 principal amount of secured medium term notes, $80,000,000 due in 2003 and $80,000,000 due in 2023. In May, the net proceeds were used to retire early four series of first mortgage bonds totaling $155,000,000 plus premiums and accrued interest. On September 1, 1993 the Company issued $30,000,000 principal amount of secured medium term notes due in 1998. In October 1993, the net proceeds were used to retire early, first mortgage bonds of $30,000,000 plus premiums and accrued interest. Environmental Issues Pacific Hide & Fur During 1989, a Partial Consent Decree was filed with the United States District Court for the District of Idaho wherein the Company agreed to clean up the PCBs at a superfund site (Pacific Hide & Fur Depot) and further agreed to pay for three years of operation and maintenance of the site after the Certification of Completion is issued by the Environmental Protection Agency (EPA). Remediation activities were completed in 1992 by moving the PCB contaminated soil to an EPA approved off-site disposal facility. The EPA is conducting an investigation regarding parties responsible for lead contamination at the site. Information indicates that the Company may have contributed a very small amount of lead to the site. However, the EPA has presently indicated the Company's involvement in the lead contamination at the site is insignificant and that the Company may not be required to participate in the lead clean-up. At present, the Company has expensed approximately $6.9 million to cover the estimated total cost of implementing remediation of the PCBs and lead contaminated soil and scrap at the site. Mountaineer In May 1993, the Company was notified that Bridger Coal Company (BCC), a joint venture, which is one-third owned by Idaho Energy Resources Co (IERCO), a wholly-owned subsidiary of the Company, was a potential contributor to a superfund site involving waste motor oil delivered to a refinery (Mountaineer Refinery) in Wyoming. In November 1993, BCC agreed to be included on the potentially responsible party list for this site. The current estimated cost for clean up is from $2.6 million to $5.0 million. BCC's portion of the clean up, based on the amount of oil delivered to the site, is estimated to be approximately 9 percent, or $234,000 to $450,000. IERCO would be liable for one- third of the BCC portion, or approximately $78,000 to $150,000. This liability has not been recorded in the Company's consolidated financials because it does not have a material effect on the results of operations. PCB Program The Company has a program to make the 200-plus substations on its system non-PCB. The costs for this disposal program were $0.9 million, $0.3 million and $0.1 million for 1991, 1992, and 1993 respectively. While the Company's use of equipment containing PCBs falls well within the federal safety standards, the Company has voluntarily decided to virtually eliminate these compounds from the substation sites. This program will save costs associated with the long-term monitoring and testing of substation equipment and grounds for PCB contamination as well as being good for the environment today. Salmon Recovery Plans The Company continues to be actively involved with the long-term survival of anadromous fish runs on the Columbia and Lower Snake Rivers. The Company fully supports and actively participates in the regional effort to develop a comprehensive and scientifically credible recovery program for the salmon. The Snake River Salmon Recovery Team submitted its Draft Recovery Plan to the National Marine Fisheries Service (NMFS) detailing its draft recommendations for restoring the listed Snake River salmon runs. The Company has concluded a review of the 500-page report and believes it sets forth a course of action that, if fully implemented, could lead to a successful recovery. The Draft Plan details comments regarding some institutional changes and responsibility for management of the recovery efforts. It suggests reductions in the ocean and in-river harvest rates, calls for significant improvements in transportation and collection systems, supports flow augmentation and habitat improvements, calls for a test drawdown of the Lower Granite Reservoir on the Snake River and suggests habitat, hatchery and predation improvements. The Company will continue to closely monitor the finalization of the Recovery Plan which is expected to be released in 1994. It is possible the final recovery plan could have a material impact on the Company, as well as every other person, community and industry in the Northwest that depend on the Snake and Columbia Rivers. The Company is hopeful that the anadromous fish runs can be restored to the level that society demands without undue hardship placed upon the Company and those who benefit from its service. Nez Perce Tribe On December 6, 1991, the Nez Perce Tribe filed a civil action against the Company in the United States District Court for the District of Idaho. The Tribe alleges that the Company's construction, operation and maintenance of the Hells Canyon Project, consisting of the Brownlee, Oxbow and Hells Canyon Dams, prevented anadromous fish from reaching their traditional spawning areas, and destroyed certain runs of those fish. This allegedly deprived the Nez Perce Tribe of its treaty right to take fish from the Snake and Columbia Rivers. The Nez Perce Tribe is seeking compensatory and punitive damages, each in an amount to be proven at trial. The Company maintains the suit is without merit and has asked the federal court to enter a summary judgment dismissing the action. The Company believes responsibility for the concerns the Nez Perce Tribe has identified lies with the United States. The Company's Hells Canyon Project was licensed by the federal government and built in accordance with federally approved plans. Since its inception, the Project has been operated subject to federal regulation. The Company has complied with all governmental requirements for mitigation of any impacts the Project may have had on the fisheries. On January 19, 1993, a hearing was held in Federal Court on the Company's motion for summary judgment and the Court took the matter under advisement. On July 30, 1993, the magistrate issued a Report and Recommendation to the District Judge wherein it is recommended that the Company's motion for summary judgment be granted. Following briefing by the parties the District Judge by order dated November 30, 1993, referred to the magistrate for additional findings the tribes claim for compensation based on exclusion from its usual and accustomed fishing places resulting from the construction of the Hells Canyon Project. This issue has been fully briefed by the parties and oral argument was held on February 11, 1994. Snake River Mollusk In mid-December 1992, five Snake River mollusks were listed as endangered and threatened species. This possibility has been a part of all the Company's discussions regarding relicensing and new hydro development since that time. The listing could influence the way the Company operates its existing mid-Snake River hydro facilities. The listing specifically mentions the impact fluctuating water levels related to hydro operations may have on the snails' habitat. While most of the facilities on that stretch of the river are baseload facilities, some do provide load-following capability. There is uncertainty on exactly what impact, if any, water fluctuations caused by the facilities have on the snails. The Company intends to testify to the U. S. Fish and Wildlife Service, the listing agency, that there is little data in this area and that it proposes to study these operations. While there is potential the listing could impact the way the Company operates these facilities, the Company believes such changes will be minor and not present any undue hardship. Clean Air The Company has analyzed the Clean Air Act legislation and its effects upon the Company and its ratepayers. The Company's coal- fired plants in Nevada and Oregon already meet the federal emission rate standards and the Company's coal-fired plant in Wyoming meets that state's even more stringent regulations. The Company anticipates no material adverse effect upon its operations. Electric and Magnetic Fields While scientific research has yet to establish any conclusive link between electric and magnetic fields and human disease, the possibility of a connection has caused public concern both nationally and internationally. Electric and magnetic fields are found wherever there is electric current, whether it be in a high- voltage transmission line or the simplest of household electrical appliances. Concern over possible health effects already has prompted regulatory efforts to limit human exposure to electric and magnetic fields in several areas of the nation. Depending on what researchers ultimately discover and what regulations may be deemed necessary, it is an issue that could impact a number of industries, including electric utilities. At this time it is difficult to estimate what impact, if any, the issue could have on the Company and its operations. Competition The electric utility industry in general has become, and is expected to be, increasingly competitive due to a variety of regulatory, economic and technological developments. The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market (a) through amendments to the Holding Company Act, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Power Act, authorizing the FERC under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services to or for other utilities and other entities generating electric energy for sale or resale. With the passage of the Energy Policy Act and the advent of a more competitive electric utility environment, the Company has intensified its ongoing strategic planning process. The Company's goal is to anticipate and fully integrate into its operations any legislative, regulatory, environmental, competitive and technological changes. The Company is well positioned to succeed in a more competitive environment with its low cost of energy production and is taking action to preserve its competitive advantage. A major action area identified is the Company's resource acquisition policies. In September the Company submitted a detailed position paper to its state regulators and other interested parties outlining proposed resource acquisition policy changes. With the potential deregulation of the electric utility industry and a more competitive power supply market place, the Company believes that current resource acquisition policies must be changed to avoid burdening the Company and customers with unnecessary future power supply costs. The Company wants to establish that future supply additions are both needed at the time of development and are the least-cost market alternative. Accordingly, in December 1993, the Company filed with the IPUC for permission to approve new lower prices for CSPP purchases. The Company believes existing rates are no longer appropriate and that prices paid to CSPP developers should be based upon need for the power and current market conditions. At the same time, in its position paper the Company proposes to abandon planned development or expansion of several of its own hydroelectric projects ahead of need. Expansion of existing projects will only proceed if the price of the incremental capacity is competitive within the regional marketplace or unless required to do so under federal licensing rules. Accordingly, the Company will forego relicense upgrades to its Shoshone Falls and Upper Salmon hydro plants (unless necessitated by relicensing requirements) and anticipates requesting permission from regulators to abandon the proposed A. J. Wiley Project on the Snake River. The remaining costs associated with the A.J. Wiley Project to be written off will be immaterial. Relicensing As a result of various federal legislative actions and proposals (such as the Electric Consumers Protection Act of 1986, Energy Policy Act of 1992, Clean Water Act Reauthorization and Endangered Species Act Reauthorization) a major issue facing the Company is the relicensing of its hydro facilities. Because the federal licenses for the majority of the Company's hydroelectric projects expire during the next 10 to 15 years, the Company has established an internal task force to vigorously pursue the relicensing process. The relicensing of these projects is not automatic under federal law. The Company must demonstrate comprehensive usage of the facilities, that it has been a conscientious steward of the natural resource entrusted to it and that there is a strong public interest in the Company continuing to hold the federal licenses. The Company can not anticipate what type of environmental or operational requirements may be placed on the projects in the relicensing process, nor can it estimate what the eventual cost will be for relicensing. However, the Company anticipates that its efforts in this matter for all of the hydro facilities will prove to be successful. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES PAGE Management's Responsibility for Financial Statements 57 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 1993, 1992 and 1991 58-59 Consolidated Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 60 Consolidated Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 61 Consolidated Statements of Capitalization as of December 31, 1993, 1992 and 1991 62 Consolidated Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 63 Notes to Consolidated Financial Statements 64-79 Independent Auditors' Report 80 Supplemental Financial Information (Unaudited) 81 Supplemental Schedules for the Years Ended December 31, 1993, 1992 and 1991: Schedule V- Property, Plant and Equipment 89-91 Schedule VI- Accumulated Depreciation and Amortization of Property, Plant and Equipment 92-94 Schedule VIII- Valuation and Qualifying Accounts 95 Schedule X- Supplementary Income Statement Information 96 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Idaho Power Company is responsible for the preparation and presentation of the information and representations contained in the accompanying financial statements. The financial statements have been prepared in conformance with generally accepted accounting principles for a rate regulated enterprise. Where estimates are required to be made in preparing the financial statements, management has applied its best judgment as to the adequacy of the estimates based upon all available information. The Company maintains a system of internal accounting controls and related policies and procedures designed to provide reasonable assurance that all assets are protected against loss or unauthorized use and that transactions are executed in accordance with management's authorization and properly recorded to permit preparation of reliable financial statements. The systems are supported by a staff of corporate accountants and internal auditors who, among other duties, evaluate and monitor the systems of internal accounting control in coordination with the independent auditors. The staff of internal auditors conduct special and operational audits in support of these accounting controls throughout the year. The Board of Directors, through its Audit Committee comprised entirely of outside directors, meets periodically with management, internal auditors and the Company's independent auditors to discuss auditing, internal control and financial reporting matters. To ensure their independence, both the internal auditors and independent auditors have full and free access to the Audit Committee. The financial statements have been audited by Deloitte & Touche, the Company's independent auditors, who were responsible for conducting their audit in accordance with generally accepted auditing standards. By:__/s/__Joseph W. Marshall__ By:__/s/__J. LaMont Keen__ Joseph W. Marshall J. LaMont Keen Chairman and Vice President and Chief Chief Executive Officer Financial Officer By:__/s/__Harold J. Hochhalter__ Harold J. Hochhalter Controller and Chief Accounting Officer IDAHO POWER COMPANY CONSOLIDATED BALANCE SHEETS ASSETS
December 31, 1993 1992 1991 (Thousands of Dollars) ELECTRIC PLANT (Notes 1 and 6): In service (at original cost) $2,249,723 $2,198,747 $2,094,611 Less accumulated provision for depreciation 728,979 683,332 639,238 In service - Net 1,520,744 1,515,415 1,455,373 Construction work in progress 92,682 66,997 70,841 Held for future use 2,958 3,083 3,060 Electric plant - Net 1,616,384 1,585,495 1,529,274 INVESTMENTS AND OTHER PROPERTY 20,772 11,411 9,801 CURRENT ASSETS: Cash and cash equivalents 8,228 4,966 7,229 Receivables: Customer 29,741 28,687 27,280 Allowance for uncollectible accounts (1,377) (1,421) (1,300) Notes 5,616 1,669 744 Employee notes receivable 5,909 5,970 4,283 Other 1,858 1,695 2,114 Accrued unbilled revenues (Note 1) 25,583 27,210 23,737 Materials and supplies (at average cost) 23,372 25,762 26,423 Fuel stock (at average cost) 11,553 14,282 15,708 Prepayments (Note 9) 20,975 22,171 15,678 Regulatory assets associated with income taxes 4,914 - - Total current assets 136,372 130,991 121,896 DEFERRED DEBITS: American Falls and Milner water rights 32,755 32,890 21,315 Company-owned life insurance (Note 9) 45,294 40,228 32,892 Regulatory assets associated with income taxes 171,569 - - Regulatory assets - other 35,036 - - Other 39,235 61,292 58,496 Total deferred debits 323,889 134,410 112,703 TOTAL $2,097,417 $1,862,307 $1,773,674 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1993 1992 1991 (Thousands of Dollars) CAPITALIZATION (See Page 62): Common stock equity (Note 3): Common stock - $2.50 par value (shares authorized 50,000,000; shares outstanding 1993 - 37,085,055; 1992 - 36,186,527; 1991 - 33,977,000) $92,713 $90,466 $84,942 Premium on capital stock 350,882 326,338 275,505 Capital stock expense (4,128) (3,806) (3,623) Retained earnings 222,900 212,404 222,973 Total common stock equity 662,367 625,402 579,797 Preferred stock (Note 4) 132,751 107,874 108,191 Long-term debt (Note 6) 693,780 701,948 629,981 Total capitalization 1,488,898 1,435,224 1,317,969 CURRENT LIABILITIES: Long-term debt due within one year 466 464 350 Notes payable (Note 7) 4,000 6,000 48,500 Accounts payable 31,912 34,821 33,874 Taxes accrued 15,452 16,182 14,600 Interest accrued 14,920 18,287 17,285 Other 13,731 12,125 14,459 Total current liabilities 80,481 87,879 129,068 DEFERRED CREDITS: Accumulated deferred investment tax credits (Notes 1 and 2) 72,013 73,651 75,300 Accumulated deferred income taxes (Notes 1 and 2) 358,280 210,435 202,340 Regulatory liabilities associated with income taxes 34,968 - - Regulatory liabilities - other 4,235 - - Other (Note 9) 58,542 55,118 48,997 Total deferred credits 528,038 339,204 326,637 COMMITMENTS AND CONTINGENT LIABILITIES (Note 8) TOTAL $2,097,417 $1,862,307 $1,773,674 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME Year Ended December 31, 1993 1992 1991 (Thousands of Dollars) REVENUES (Note 1) $540,402 $498,092 $483,193 EXPENSES: Operation: Purchased power (Note 1) 45,361 58,496 51,210 Fuel expense (Note 10) 87,855 96,710 75,161 Other 121,252 101,659 107,223 Maintenance 43,136 35,888 44,370 Depreciation (Note 1) 58,724 59,823 57,597 Taxes other than income taxes 22,129 20,562 21,168 Total expenses 378,457 373,138 356,729 INCOME FROM OPERATIONS 161,945 124,954 126,464 OTHER INCOME: Allowance for equity funds used during construction (Note 1) 3,060 2,400 1,945 Other - Net (Note 9) 9,924 8,733 7,508 Total other income 12,984 11,133 9,453 INTEREST CHARGES: Interest on long-term debt 53,706 53,408 54,370 Other interest (Notes 1 and 7) 2,750 2,050 4,606 Total interest charges 56,456 55,458 58,976 Allowance for borrowed funds used during construction (Note 1) (2,465) (2,523) (2,075) Net interest charges 53,991 52,935 56,901 INCOME BEFORE INCOME TAXES 120,938 83,152 79,016 INCOME TAXES (Notes 1 and 2) 36,474 23,162 21,144 NET INCOME 84,464 59,990 57,872 Dividends on preferred stock (Note 4) 6,009 5,516 4,904 EARNINGS ON COMMON STOCK $ 78,455 $ 54,474 $ 52,968 AVERAGE COMMON SHARES OUTSTANDING (000) 36,675 35,116 33,977 EARNINGS PER SHARE OF COMMON STOCK (Note 3) $2.14 $1.55 $1.56 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Year Ended December 31, 1993 1992 1991 (Thousands of Dollars) RETAINED EARNINGS Beginning of year $212,404 $222,973 $233,241 NET INCOME 84,464 59,990 57,872 Total 296,868 282,963 291,113 DIVIDENDS: Preferred stock (Note 4) 6,009 5,516 4,904 Common stock (per share: 1993 - 1991 - $1.86) (Note 3) 67,959 65,043 63,197 Total dividends 73,968 70,559 68,101 PREFERRED STOCK REDEMPTION - - 39 RETAINED EARNINGS End of year $222,900 $212,404 $222,973 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1993 % 1992 % 1991 % (Thousands of Dollars) COMMON STOCK EQUITY (Note 3): Common stock $92,713 $90,466 $84,942 Premium on capital stock 350,882 326,338 275,505 Capital stock expense (4,128) (3,806) (3,623) Retained earnings 222,900 212,404 222,973 Total common stock equity 662,367 44 625,402 44 579,797 44 PREFERRED STOCK (Note 4): 4% preferred stock 17,751 17,874 18,191 7.68% Series, serial preferred stock 15,000 15,000 15,000 8.375% Series, serial preferred stock 25,000 25,000 25,000 Auction rate preferred stock 50,000 50,000 50,000 7.07% Series, serial preferred stock 25,000 - - Total preferred stock 132,751 9 107,874 7 108,191 8 LONG-TERM DEBT (Note 6): First mortgage bonds: 5 1/4% Series due 1996 20,000 20,000 20,000 6 1/8% Series due 1996 - 30,000 30,000 5.33 % Series due 1998 30,000 - - 8.65 % Series due 2000 80,000 80,000 80,000 7 3/4% Series due 2002 - 30,000 30,000 6.40 % Series due 2003 80,000 - - 8 3/8% Series due 2004 - 35,000 35,000 8 % Series due 2004 50,000 50,000 - 10 % Series due 2004 - - 50,000 8 1/2% Series due 2006 - 30,000 30,000 9 % Series due 2008 - 60,000 60,000 9.50 % Series due 2021 75,000 75,000 75,000 7.50 % Series due 2023 80,000 - - 8 3/4% Series due 2027 50,000 50,000 - 9.52 % Series due 2031 25,000 25,000 25,000 Total first mortgage bonds 490,000 485,000 435,000 *Less amount due within one year - - - Net first mortgage bonds 490,000 485,000 435,000 Pollution control revenue bonds: 5.90 % Series due 2003 25,050* 25,450* 25,800* 6.0 % Series due 2007 24,000 24,000 24,000 7 1/4% Series due 2008 4,360 4,360 4,360 7 5/8% Series 1983-1984 due 2013-2014 68,100 68,100 68,100 8.30 % Series 1984 due 2014 49,800 49,800 49,800 Total pollution control revenue bonds 171,310 171,710 172,060 *Less amount due within one year (400) (400) (350) Net pollution control Revenue bonds 170,910 171,310 171,710 Project financing - Ida-West - 11,243 1,694 REA notes 1,834 1,899 - Less amount due within one year (66) (64) - Net REA notes 1,768 1,835 - American Falls bond guarantee 21,055 21,190 21,315 Milner Dam note guarantee 11,700 11,700 - Unamortized premium/ discount-Net (Note 1) (1,653) (330) 262 Total long-term debt 693,780 47 701,948 49 629,981 48 TOTAL CAPITALIZATION $1,488,898 100 $1,435,224 100 $1,317,969 100 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 1993 1992 1991 (Thousands of Dollars) OPERATING ACTIVITIES: Cash received from operations: Retail revenues $ 434,625 $ 432,594 $ 414,811 Wholesale revenues 84,726 42,541 52,521 Other revenues 23,411 25,531 21,652 Fuel paid (83,885) (96,839) (71,706) Purchased power paid (50,246) (55,976) (57,930) Other operation & maintenance paid (162,014) (145,518) (148,443) Interest paid (include long and short-term debt only) (56,348) (52,310) (51,901) Income taxes paid (32,512) (14,859) (22,802) Taxes other than income taxes paid (22,165) (21,399) (21,883) Other operating cash receipts and payments - Net 8,213 (5,917) (603) Net cash provided by operating activities 143,805 107,848 113,716 FINANCING ACTIVITIES: First mortgage bonds issued 188,136 98,870 98,969 PC bond fund requisitions/other long- 5,594 9,583 1,694 term debt Common stock issued 26,781 56,223 - Preferred stock issued 24,781 - 74,031 Short-term borrowings (2,140) (42,500) 220 Long-term debt retirement (191,878) (52,346) (60,049) Preferred stock retirement (65) (270) (25,351) Dividends on preferred stock (5,914) (5,620) (4,599) Dividends on common stock (67,959) (65,043) (63,197) Net cash - financing activities (22,664) (1,103) 21,718 INVESTING ACTIVITIES: Additions to utility plant (122,949) (118,048) (133,735) Conservation (6,687) (5,287) (3,852) Other 11,757 14,327 (663) Net cash - investing activities (117,879) (109,008) (138,250) Change in cash and cash equivalents 3,262 (2,263) (2,816) Cash and cash equivalents beginning of period 4,966 7,229 10,045 Cash and cash equivalents end of period $ 8,228 $ 4,966 $ 7,229 RECONCILIATION OF NET INCOME TO NET CASH PROVIDED BY OPERATING ACTIVITIES: Net income $ 84,464 $ 59,990 $ 57,872 Adjustments to reconcile net income to net cash: CSPP-Net amortization/(deferral) (518) (3,587) (4,225) Depreciation 58,724 59,823 57,597 Deferred income taxes 6,690 8,179 5,762 Investment tax credit - Net (1,583) (1,439) (3,177) Allowance for funds used during construction (5,525) (4,923) (4,020) Postretirement benefits funding (excl pensions) (7,481) (11,369) (8,574) Changes in operating assets and liabilities: Accounts receivable 2,360 2,574 5,791 Fuel inventory 3,970 (129) 3,455 Accounts payable (4,367) 6,107 (2,494) Taxes payable (1,141) 779 (4,927) Interest payable (1,010) 2,841 4,227 Other - Net 9,222 (10,998) 6,429 Net cash provided by operating activities $ 143,805 $ 107,848 $ 113,716 The accompanying notes are an integral part of these statements.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: PRINCIPLES OF CONSOLIDATION _ The consolidated financial statements include the accounts of the Company and its wholly- owned subsidiaries, Idaho Energy Resources Co (IERCO), Idaho Utility Products Company (IUPCO), IDACORP, INC. and Ida-West Energy Company (Ida-West). All significant intercompany transactions and balances have been eliminated in consolidation. SYSTEM OF ACCOUNTS _ The Company is an electric utility and its accounting records conform to the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission and adopted by the public utility commissions of Idaho, Oregon, Nevada and Wyoming. ELECTRIC PLANT _ The cost of additions to electric plant in service represents the original cost of contracted services, direct labor and material, allowance for funds used during construction and indirect charges for engineering, supervision and similar overhead items. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to operations. For property replaced or renewed the original cost plus removal cost less salvage is charged to accumulated provision for depreciation while the cost of related replacements and renewals is added to electric plant. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) _ The allowance, a non-cash item, represents the composite interest costs of debt, shown as a reduction to interest charges, and a return on equity funds, shown as an addition to other income, used to finance construction. While cash is not realized currently from such allowance, it is realized under the ratemaking process over the service life of the related property through increased revenues resulting from higher rate base and higher depreciation expense. Based on the uniform formula adopted by the Federal Energy Regulatory Commission (FERC), the Company's weighted average monthly AFDC rates for 1993, 1992 and 1991 were 9.6%, 8.7% and 9.4%, respectively. REVENUES _ In order to match revenues with associated expenses, the Company accrues unbilled revenues for electric services delivered to customers but not yet billed at month- end. RATE RELIEF _ On May 4, 1992, the Idaho Public Utilities Commission (IPUC) issued an order which authorized the Company to put in place for a twelve-month period temporary rate relief of 3.9 percent or $15.0 million effective May 6, 1992. The Company also filed and received an accounting order from the Oregon Public Utility Commission (OPUC) for permission to begin deferring with interest 33.5 percent of Oregon's share of increased power production costs starting on March 23, 1992 and continuing through December 31, 1992. The Company filed a request and received approval from the OPUC for a 24 month amortization period of an annual rate increase of $526,360 or 2.57 percent effective July 1, 1993. The Company also submitted a rate increase request to the FERC for approval to increase rates to its wholesale customers. The FERC granted a $547,900 rate increase for a twelve-month period effective November 10, 1992. All of these rate actions were requested due to drought related effects during 1991 and 1992, which reduced water flows and increased net power supply costs. On October 9, 1992, the Company filed an application with the IPUC which would allow the Company to suspend the deferral of certain revenue items to partially offset the increase in 1992 power supply costs. On January 8, 1993, the IPUC authorized the Company to suspend five and one-half months (January 1, 1993 through June 15, 1993) of the revenue deferral associated with the Afton cogeneration facility for a total of $1,225,707. This allowed the Company to defer additional 1992 reserve capacity costs of $1,225,707 against this suspension of revenue deferrals in 1993. On March 29, 1993, the IPUC approved a power cost adjustment (PCA) mechanism for the Company, pursuant to the Company's application requesting authority to implement a PCA. Under the PCA, customer's rates will be adjusted annually to reflect the Company's forecasted net power supply costs. Deviations from predicted costs are deferred with interest and then adjusted (trued-up) in the subsequent year. A transition period was established providing for inclusion of 60% of power cost deviations from normalized rates in the PCA until conclusion of the Company's next general rate case when the allowed percentage will increase to 90%. On May 16, 1993, the Company implemented its first PCA after the IPUC approved a $5.0 million revenue increase to base rates for the period May 16, 1993 through May 15, 1994. At the same time the one-year temporary rate relief granted in May 1992 ceased and the combined effect was a decrease of $10.0 million in rates. DEPRECIATION _ Effective April 1, 1993, the Company revised its depreciation methodology on certain generation plants from the five percent present worth method to the straight- line method. This change and the extention of the service lives of certain plants resulted in a minimal change in depreciation expense. All electric plant is now depreciated using the straight-line method. Annual depreciation provisions as a percent of average depreciable electric plant in service approximated 2.92% in 1993, 2.91% in 1992 and 2.93% in 1991 and are considered adequate to amortize the original cost over the estimated service lives of the properties. INCOME TAXES _ Consistent with orders and directives of the IPUC, the regulatory authority having principal jurisdiction, deferred income taxes (commonly referred to as normalized accounting) are provided for the difference between income tax depreciation and straight-line depreciation on coal-fired generation facilities and properties acquired after 1980. On other facilities, deferred income taxes are provided for the difference between accelerated income tax depreciation and straight-line depreciation using tax guideline lives on assets acquired prior to 1981. Deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods do not provide for current recovery in rates. The Company adopted SFAS No. 109 "Accounting for Income Taxes" on January 1, 1993 which had no material effect on the earnings of the Company (see Note 2). The state of Idaho allows a three percent investment tax credit upon certain plant additions. Investment tax credits are deferred and amortized to income over the estimated service lives of the related properties. PURCHASED POWER _ The Company has contracts to purchase the energy from five PURPA Qualified Facilities which are 50 percent owned by Ida-West (a wholly-owned subsidiary of the Company). Power purchased from these facilities amounted to $5,975,093 in 1993. CASH AND CASH EQUIVALENTS _ For purposes of reporting cash flows, cash and cash equivalents include cash on hand and highly liquid temporary investments with original maturity dates of three months or less. The Company has changed the Statements of Cash Flows from the indirect method to the direct method. Previous year's presentations have been restated to conform with the new method. OTHER ACCOUNTING POLICIES _ Debt discount, expense and premium are being amortized over the terms of the respective debt issues. RECLASSIFICATIONS _ Certain items previously reported for years prior to 1993 have been reclassified to conform with the current year's presentation. Net income was not affected by these reclassifications. 2. INCOME TAXES: A reconciliation between the statutory federal income tax rate and the effective rate for the years 1993, 1992 and 1991 is as follows:
1993 1992 1991 Amount Rates Amount Rates Amount Rates (Thousands of Dollars) Computed income taxes based on statutory federal income tax rate $42,328 35.0% $28,272 34.0% $26,898 34.0% Change in taxes resulting from: AFUDC (1,798) (1.5) (1,508) (1.8) (1,349) (1.7) Investment tax credit restored (2,898) (2.4) (3,446) (4.1) (3,936) (5.0) Repair allowance (2,975) (2.5) (2,278) (2.7) (2,278) (2.9) Elimination of amounts provided in prior years (4,686) (3.9) (1,601) (1.9) - - Current state income taxes 2,693 2.2 973 1.2 1,507 1.9 Depreciation 4,116 3.4 1,738 2.1 658 0.8 Other (306) (0.1) 1,012 1.1 (356) (0.3) Total provision for federal and state income taxes $36,474 30.2% $23,162 27.9% $21,144 26.8% The provision for income taxes consists of the following: Income taxes currently payable: Federal $27,199 $16,366 $16,394 State 4,168 56 2,165 Total 31,367 16,422 18,559 Income taxes deferred - Net of Amortization: Federal 6,621 7,688 6,302 State 69 491 (540) Total 6,690 8,179 5,762 Investment and other tax credits: Deferred 1,315 2,007 759 Restored (2,898) (3,446) (3,936) Total (1,583) (1,439) (3,177) Total provision for income taxes $36,474 $23,162 $21,144 The provision for deferred income taxes consists of the following: Deferred: Excess of tax over book depreciation normalized $14,044 $12,474 $10,582 Other 6,384 6,743 2,986 Total 20,428 19,217 13,568 Restored (13,738) (11,038) (7,806) Total $ 6,690 $ 8,179 $ 5,762
During 1993, the Company settled federal tax liabilities on the 1987 through 1990 tax years except for immaterial amounts that relate to a partnership. Federal income tax returns for years 1991 and 1992 are under examination by the Internal Revenue Service and the Company believes that a final settlement of its federal income tax liabilities for these years will not have a material effect on its results of operation or financial position. The Company adopted SFAS No. 109 "Accounting for Income Taxes" on January 1, 1993 which had no material effect on the earnings of the Company. SFAS 109, among other things, (i) requires the liability method be used in computing deferred taxes on all temporary differences between book and tax basis of assets and liabilities; (ii) requires that deferred tax liabilities and assets be adjusted for an enacted change in tax laws or rates; and (iii) prohibits net-of-tax accounting and reporting. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. As of December 31, 1993, the Company has recorded regulatory assets of $176.5 million and regulatory liabilities in the amount of $35.0 million which were offset by an equal amount of accumulated deferred income tax provision. The regulatory asset is primarily based upon differences between the book and tax basis of the electric plant in service and the accumulated reserve for depreciation. In August 1993, Congress passed the Revenue Reconciliation Act of 1993 which retroactively to January 1, 1993 increased the Federal tax rate from 34% to 35%. The Company requested and received from the IPUC permission to recover the higher taxes by realizing a portion of the gain on the sale of the Wood River Turbine as income in 1993. 3. COMMON STOCK: Changes in shares of the common stock of the Company for 1993, 1992 and 1991 were as follows: Common Stock Premium $2.50 on Shares Par Capital Value Stock (Thousands of Dollars) Balance at December 31, 1990 33,977,000 $84,942 $275,802 Gain on reacquired 4% preferred stock (Note 4) - - 283 Preferred stock redemption (Note 4) - - (580) Balance at December 31, 1991 33,977,000 84,942 275,505 Gain on reacquired 4% preferred stock (Note 4) - - 152 Stock purchase plans 959,527 2,399 23,101 Public offering (July 1992) 1,250,000 3,125 27,580 Balance at December 31, 1992 36,186,527 90,466 326,338 Gain on reacquired 4% preferred stock (Note 4) - - 50 Stock purchase plans 898,528 2,247 24,494 Balance at December 31, 1993 37,085,055 $92,713 $350,882 During the first quarter of 1992 the Company reinstated issuing original issue shares of common stock for its Dividend Reinvestment and Stock Purchase Plan, the Employee Savings Plan and the Employee Stock Ownership Plan. During 1993 and 1992, common shares totaling 898,528 and 959,527, respectively, have been issued to these plans. On July 8, 1992, the Company issued 1,250,000 shares of its common stock. The net proceeds of $30,706,250 were received and used for the payment of $4.0 million of short-term debt with the remainder used for the Company's ongoing construction program. As of December 31, 1993, the Company had 2,151,078 of its authorized but unissued shares of common stock reserved for future issuance under its Dividend Reinvestment and Stock Purchase Plan, Employee Savings Plan and Employee Stock Ownership Plan. On January 11, 1990, the Board of Directors adopted a Shareowner Rights Plan (Plan). Under the Plan, the Company declared a distribution of one Preferred Stock Right (Right) for each of the Company's outstanding Common shares held on January 29, 1990 or issued thereafter. The Rights are currently not exercisable and will be exercisable only if a person or group (Acquiring Person) either acquires ownership of 20 percent or more of the Company's Voting Stock or commences a tender offer that would result in ownership of 20 percent or more. The Company may redeem the Rights at a price of $0.01 per Right anytime prior to acquisition by an Acquiring Person of a 20 percent position. Following the acquisition of a 20 percent position, each Right will entitle its holder, subject to regulatory approval, to purchase for $85 that number of shares of Common Stock or Preferred Stock having a market value of $170. If after the Rights become exercisable, the Company is acquired in a merger or other business combination, 50 percent or more of its consolidated assets or earnings power are sold or the Acquiring Person engages in certain acts of self-dealing, each Right entitles the holder to purchase for $85, shares of the acquiring company's Common Stock having a market value of $170. Any Rights that are or were held by an Acquiring Person become void if either of these events occurs. The Rights expire on January 11, 2000. 4. PREFERRED STOCK: The number of shares of preferred stock outstanding at December 31, 1993, 1992 and 1991 was as follows: Shares Outstanding at December 31, Call Price 1993 1992 1991 Per Share Preferred stock: Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 177,506 178,735 181,913 $104.00 Serial preferred stock, 7.68% Series (authorized 150,000 shares) 150,000 150,000 150,000 $102.97 Serial preferred stock, cumulative, without par value; total of 3,000,000 shares authorized: 8.375% Series, $100 stated value, (authorized 250,000 shares)(a) 250,000 250,000 250,000 $105.58 to $100.37 7.07% Series, $100 stated value, (authorized 250,000 shares)(b) 250,000 - - $103.535 to $100.354 Auction rate preferred stock, $100,000 stated value, (authorized 500 shares)(c) 500 500 500 $100,000.00 Total 828,006 579,235 582,413 [FN] (a) The preferred stock is not redeemable prior to October 1, 1996. (b) The preferred stock is not redeemable prior to July 1, 2003. (c) Dividend rate at December 31, 1993 was 3.04% and ranged between 2.62% and 3.21% during the year. During 1993, 1992 and 1991 the Company reacquired and retired 1,229; 3,178 and 5,697 shares of 4% preferred stock resulting in a net addition to premium on capital stock of $50,151; $151,891 and $282,431, respectively. As of December 31, 1993 the overall effective cost of all outstanding preferred stock was 5.70 percent. On July 1, 1993 the Company utilized the remaining preferred stock shelf registration and issued $25,000,000 of 7.07% Series, Serial Preferred Stock ($100 stated value). The net proceeds of the issuance were used for the Company's ongoing construction program. 5. FAIR VALUE OF FINANCIAL INSTRUMENTS: The estimated fair value of the Company's financial instruments have been determined by the Company using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The total estimated fair value of long-term debt was approximately $733,251,000 for 1992 and $762,575,000 for 1993. The estimated fair values for long-term debt are based upon quoted market prices of the same or similar issues. 6. LONG-TERM DEBT: The amount of first mortgage bonds issuable by the Company is limited to a maximum of $900,000,000 and by property, earnings and other provisions of the mortgage and supplemental indentures thereto. Substantially all of the electric utility plant is subject to the lien of the indenture. Pollution Control Revenue Bonds, Series 1984, due December 1, 2014, are secured by First Mortgage Bonds, Pollution Control Series A, which were issued by the Company and are held by a Trustee for the benefit of the bondholders. On March 25, 1992, the Company issued $50,000,000 principal amount of First Mortgage Bonds, 8% Series, due 2004, and $50,000,000 principal amount of First Mortgage Bonds, 8 3/4% Series, due 2027. The net proceeds were used initially to pay down $36,000,000 of outstanding commercial paper notes and the remainder was used for the early redemption of $50,000,000 First Mortgage Bonds, 10% Series, due 2004, and for the Company's ongoing construction program. On April 28, 1993 the Company issued $80,000,000 principal amount of Secured Medium Term Notes, Series A, 6.40% Series due 2003 and $80,000,000 principal amount of Secured Medium Term Notes, Series A, 7.50% Series due 2023. In May, the net proceeds were used to retire early four series (7 3/4% Series due 2002, 8 3/8% Series due 2004, 8 1/2% Series due 2006 and 9% Series due 2008) of first mortgage bonds totaling $155,000,000 plus premiums and accrued interest. On September 1, 1993 the Company issued $30,000,000 principal amount of Secured Medium Term Notes, Series A, 5.33% Series due 1998. On October 1, 1993, the net proceeds were used to retire early the 6 1/8% Series, First Mortgage Bonds of $30,000,000 plus premiums and accrued interest. The early redemption of these first mortgage bonds reduced the Company's overall cost of long-term debt and reduced the Company's annual interest expense by approximately $2.3 million. The only first mortgage bonds maturing during the five-year period ending 1998 are $20,000,000 in 1996 and $30,000,000 in 1998. Sinking fund requirements for the first mortgage bonds outstanding at December 31, 1993 are $5,398,000 per year. These requirements may be met by the deposit of cash, deposit of bonds, or by certification of property additions at the rate of 167% of requirements. The Company's practice is to certify additional property to meet the sinking fund requirements. In September 1991, 1992 and 1993, $350,000, $350,000, and $400,000 respectively, of the 5.90% Series, Pollution Control Revenue Bonds, were retired pursuant to sinking fund requirements for those years. Sinking fund requirements during the five-year period ending 1998 for pollution control bonds outstanding at December 31, 1993 are $400,000 in 1994, $450,000 in 1995 and 1996, and $500,000 in 1997 and 1998. As of December 31, 1993, the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 8.02 percent in comparison to 8.33 percent in 1992 and 8.43 percent in 1991. On February 10, 1992, $11,700,000 principal amount of 8.95% Guaranteed Notes due 2017 were issued by Milner Dam, Inc., an Idaho Corporation, in which the Twin Falls Canal Company and the North Side Canal Company have assigned their interest in the Milner Dam Rehabilitation Project. The Company, pursuant to an agreement signed with Milner Dam. Inc., executed a guarantee of these notes and agreed to make royalty (falling water) payments to Milner Dam, Inc. for use of water released from the Milner Dam Rehabilitation Project beginning in 1993. 7. NOTES PAYABLE: At January 1, 1994, the Company had regulatory authority to incur up to $150,000,000 of short-term indebtedness. Under this authority, total lines of credit maintained with various banks amounted to $70,000,000. Under annual borrowing arrangements with these banks, the Company is required to pay a fee of 3/16 of 1% on the available and committed lines of credit. Commercial paper may be issued in an amount not to exceed 25% of revenues for the latest twelve-month period and are supported by bank lines of credit of an equal amount. Balances and interest rates of short-term borrowings were as follows: Year Ended December 31, 1993 1992 1991 (Thousands of Dollars) Balance at end of period: Banks $4,000 $2,000 $10,500 Commercial paper - 4,000 38,000 Effective annual interest rate at end of period: Banks 6.9% (a) 5.9% 5.3% Commercial paper - 5.9 5.3 Maximum balance during period: Banks $10,500 $37,500 $25,000 Commercial paper 14,000 47,400 48,280 Average daily balance during period: Banks $1,800 $3,600 $6,700 Commercial paper 900 8,300 7,200 Effective annual interest rate during period: Banks 7.6% (a) 5.5% 6.5% Commercial paper 9.1 (a) 5.4 6.9 [FN] (a) Effective rates have been inflated by the commitment fees being larger than the interest paid for the year. If the commitment fees were excluded the effective annual interest rate at end of period would have been 3.6%. The effective annual interest rate during period for banks and commercial paper would have been 3.1% and 3.5%, respectively. 8. COMMITMENTS AND CONTINGENT LIABILITIES: Commitments under contracts and purchase orders relating to the Company's program for construction and operation of facilities amounted to approximately $25,300,000 at December 31, 1993. The commitments are generally revocable by the Company subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges. The Company is party to various legal claims, actions, and complaints, certain of which involve material amounts. Although the Company is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings or, if not, what the impact might be, based upon the advice of legal counsel, management presently believes that disposition of these matters will not have a material adverse effect on the Company's results of operations. 9. BENEFIT PLANS: Pension Plan - The Company maintains a trusteed noncontributory defined benefit pension plan for all employees who work 1,000 hours or more during a calendar year. The benefits under the plan are based on years of service and the employee's final average earnings. The Company's policy is to fund with an independent corporate trustee at least the minimum required under the Employee Retirement Income Security Act of 1974 but not more than the maximum amount deductible for income tax purposes. The Company funded $5.0 million in 1993, and $5.1 million in 1992. The plan's assets held by the trustee consist primarily of listed stocks (both U.S. and foreign), fixed income securities and investment grade real estate. Deferred Compensation Plan - The Company has a nonqualified, deferred compensation plan for certain senior management employees and directors that provides for benefit payments over a fifteen-year period to the participant and his or her family upon retirement or death. The plan is being funded by life insurance policies, of which the Company is the beneficiary, with premiums being paid by the Company and each participant. These policies have accumulated cash values of $42.4 million and $36.4 million at December 31, 1993 and 1992, respectively, which do not qualify as plan assets in the actuarial computation of the funded status. Based upon SFAS No. 87, Paragraphs 36-38, the Company has recorded an additional liability of $10.8 million. The following tables set forth the amounts recognized in the Company's financial statements and the funded status of both plans in accordance with accounting standard SFAS No. 87, "Employers' Accounting for Pensions." Plan Costs for the Year 1993 1992 1991 (Thousands of Dollars) Pension plan: Service cost $ 4,496 $ 3,762 $ 3,440 Interest cost 11,688 10,926 9,848 Actual return on plan assets (23,322) (10,877) (31,871) Deferred gain (loss) on plan assets 9,848 (1,861) 21,715 Net cost $ 2,710 $ 1,950 $ 3,132 Approximate percentage included in operating expenses 66% 64% 64% Net deferred compensation plan costs charged to other income (including life insurance and SFAS No. 87 liability accrual)(a) $ 1,372 $ 1,276 $ 959 [FN] (a) These charges to the Income Statement have been reduced by gains from the Company-Owned Life Insurance (COLI) of $1,638,000; $1,607,000; and $1,663,000 for 1993, 1992 and 1991, respectively.
Funded status and significant assumptions as of December 31: Deferred Pension Plan Compensation Plan 1993 1992 1993 1992 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $134,292 $113,255 $ 24,024 $ 20,992 Accumulated benefit obligation 139,270 113,601 24,027 20,993 Projected benefit obligation 179,895 145,844 30,114 26,240 Plan assets at fair value 169,920 150,006 - - Plan assets in excess of (or less than) projected benefit obligation (9,975) 4,162 (30,114) (26,240) Unrecognized net (gain) loss from past experience different from that assumed 17,295 803 7,295 3,872 Unrecognized prior service cost 1,460 1,788 2,546 2,689 Unrecognized net (asset) obligation existing at date of initial adoption (19.5 year straight-line amortization) (3,019) (3,282) 7,053 7,666 Minimum liability adjustment - - (10,807) (8,980) Net asset (liability) included in the balance sheet $ 5,761 $ 3,471 $(24,027) $(20,993) Discount rate to compute projected benefit obligation 7.0% 8.25% 7.0% 8.25% Rate for future compensation increases 4.5 5.0 4.5 5.0 Expected long-term rate of return on plan assets 9.0 9.0 - -
Savings Plan _ The Company has an Employee Savings Plan whereby, for each $1 of employee contribution up to 6% of their salary the Company will match 100% of the first 2% employee contribution and 50% of the next 4% employee contribution, all such amounts to be invested by a trustee to any or all of seven investment options. The Company's contribution amounted to $2,283,200 in 1993, $2,046,100 in 1992 and $1,733,300 in 1991. As of December 31, 1993, a total of 3,078,663 common shares were held in this plan. An additional 955,969 common shares were held by an Employee Stock Ownership Plan as of December 31, 1993. Postretirement Benefits _ The Company maintains a defined benefit postretirement plan (consisting of health care and life insurance) that covers all employees who were enrolled in the active group plan at the time of retirement, their spouses and qualifying dependents. The plan provides for payment of hospital services, physician services, prescription drugs, dental services and various other health services, some of which have annual or lifetime limits, after subtracting payments by Medicare or other providers and after a stated deductible and co-payments have been met. Participants become eligible for the benefits if they retire from the Company after reaching age 55 with 15 years of service or after 30 years of service. The plan is contributory with retiree contributions adjusted annually. For those retirees that were age 65 or older at December 31, 1992 the plan is noncontributory. The Company also provides life insurance of one times salary for pre-65 retirees and $20,000 for post-65 retirees with the retirees paying a portion of the cost. The Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" as of January 1, 1993. This new standard requires that the expected costs of postretirement benefits be charged to expense during the years that the employees render service. The Company has elected to amortize the transition obligation of $41.4 million that was measured as of January 1, 1993 over a period of 20 years. The following tables set forth the amounts to be recognized in the Company's financial statements for year-end 1993 and the funded status of the plan in accordance with accounting standard SFAS No. 106 as of January 1, 1993 and December 31, 1993 (thousands of dollars). Postretirement Benefit Cost for 1993: Service cost $ 750 Interest cost 3,610 Actual return on plan assets (860) Amortization of transition obligation 2,040 Net amortization and deferral - Regulatory asset (3,548) Net cost $ 1,992 (a) [FN] (a) Postretirement benefit costs charged to expense in 1992 and 1991 were $2,622,300 and $2,449,800 December 31, 1993 January 1, 1993 Funded Status: Accumulated postretirement benefit obligation (APBO) $(48,290) $(41,400) Plan assets at fair value 11,840 8,200 APBO in excess of plan assets (36,450) (33,200) Unrecognized gain/losses 4,670 - Unrecognized transition obligaton 38,760 40,800 Prepaid postretirement benefit cost $ 6,980 $ 7,600 Discount rate 7.25% 8.5% Medical and dental inflation rate 6.75 8.0 Long-term plan assets expected 9.0 9.0 return A one percent change in the medical inflation rate would change the APBO by five percent and the postretirement expense for 1993 by seven percent. The Company established a retiree medical benefits funding program in 1990. This program consists of life insurance policies on active employees of which the Company is the beneficiary, and a qualified Voluntary Employees Beneficiary Association (VEBA) Trust. The net charge to other income for the life insurance policies was $632,500 in 1993, $1,733,000 in 1992, and $768,000 in 1991. The funding to the VEBA was $2,692,000 in 1993, $2,977,400 in 1992, and $3,295,400 in 1991 and recorded as a prepayment. The VEBA trust represents plan assets which are invested in variable life insurance policies, Trust Owned Life Insurance (TOLI), on active employees. Inside buildup in the TOLI policies is tax deferred and tax free if the policy proceeds are paid to the Trust as death benefits. The investment return assumption reflects an expectation that investment income in the VEBA will be substantially tax free. The IPUC issued an order approving the appropriateness of applying accrual accounting to postretirement benefit expense for ratemaking and revenue requirement purposes. The IPUC also approved the deferral of the difference between the accrual amount and the pay-as-you-go amount until the Company's next general rate case subject to an earnings test, but not to exceed two years or $6,000,000. The Public Utility Commission of Oregon and the FERC have also approved accrual accounting to postretirement benefit expense for ratemaking, and FERC has approved the deferral of the difference between accrual and pay- as-you-go not to exceed three years. The amount deferred, as a regulatory asset, at December 31, 1993 is $3.5 million. Preliminary indications are that the Company will meet the earnings test prescribed by the IPUC and will be allowed the full deferral for 1993. Postemployment Benefits _ The Company provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. The Company has recognized its portion of the cost of providing these benefits as an expense during the period in which the costs were incurred. The Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits" as of January 1, 1993. The statement requires accrual of postemployment benefits. These benefits include salary continuation and related heath care and life insurance for both long and short-term disability plans, workmen's compensation and healthcare for surviving spouse and dependent plan. The adoption of SFAS 112 is a change of accounting principal; but since the Company is a regulated utility, a deferred asset was established which represents future revenue expected to be realized at the time the postemployment benefits are included in the Company's rates. The Company recorded a liability and a regulatory asset of $3.9 million which represents the costs associated with postemployment benefits at December 31, 1993. 10. JOINTLY-OWNED PROJECTS: The Company is involved in the ownership and operation of three jointly-owned generating facilities. The Consolidated Statements of Income include the Company's proportionate share of direct operations and maintenance expenses applicable to the projects. Each facility and extent of Company participation as of December 31, 1993 are as follows: Company Ownership Electric Accumulated Plant In Provision For Name of Plant Location Service Depreciation % MW (Thousands of Dollars) Jim Bridger Rock Springs, Units 1-4 WY $370,653 $141,515 33 693 Boardman Boardman, OR 58,690 22,233 10 53 Valmy Units 1 & 2 Winnemucca, NV 298,265 90,224 50 261 The Company's wholly-owned subsidiary, IERCO, is a joint venturer in Bridger Coal Company, which operates the mine supplying coal for the Jim Bridger steam generation plant. Coal purchased by the Company from the joint venture amounted to $45,424,000 in 1993, $42,291,000 in 1992 and $40,988,500 in 1991. INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareowners Idaho Power Company Boise, Idaho We have audited the accompanying consolidated financial statements of Idaho Power Company and its subsidiaries listed in the accompanying index to financial statements and financial statement schedules 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 the 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 consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and subsidiaries at December 31, 1993, 1992 and 1991, and the results of their operations and their cash flows for each of the years then ended, in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. As discussed in Notes 2 and 9 to the consolidated financial statements, the Company changed its method of accounting for income taxes and postretirement benefits in the year ended December 31, 1993. DELOITTE & TOUCHE Portland, Oregon January 31, 1994 IDAHO POWER COMPANY SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA: The following unaudited information is presented for each quarter of 1993, 1992 and 1991 (in thousands of dollars, except for per share amounts). In the opinion of the Company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operation for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported.
Quarter Ended March 31 June 30 September 30 December 31 1993 Revenues $140,809 $129,471 $134,577 $135,545 Income from operations 41,479 38,980 34,286 47,201 Income taxes 10,610 9,270 9,108 7,486 Net income 21,347 18,524 16,427 28,166 Dividends on preferred stock 1,345 1,318 1,565 1,781 Earnings on common stock 20,002 17,206 14,862 26,385 Earnings per share of common stock 0.55 0.47 0.40 0.71 1992 Revenues 114,453 124,656 129,050 129,934 Income from operations 31,024 30,376 29,593 33,962 Income taxes 7,396 6,670 4,353 4,743 Net income 13,378 12,394 15,067 19,152 Dividends on preferred stock 1,424 1,400 1,346 1,347 Earnings on common stock 11,954 10,994 13,721 17,805 Earnings per share of common stock 0.35 0.32 0.38 0.49 1991 Revenues 120,589 110,877 129,584 122,142 Income from operations 34,855 25,526 35,234 30,849 Income taxes 7,935 4,002 8,231 977 Net income 15,781 9,980 16,729 15,381 Dividends on preferred stock 1,069 1,067 1,067 1,700 Earnings on common stock 14,712 8,913 15,662 13,681 Earnings per share of common stock 0.43 0.26 0.46 0.40
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III Part III has been omitted because the registrant will file a definitive proxy statement pursuant to Regulation 14A, which involves the election of Directors, with the Commission within 120 days after the close of the fiscal year portions of which are hereby incorporated by reference (except for information with respect to executive officers which is set forth in Part I hereof). PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Please refer to Item 8, "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules. (b) Reports on SEC Form 8-K. The following report on Form 8-K was filed during the three months ended December 31, 1993. Items Reported Date of Report 1. Item 7, Financial Statements and Exhibits December 17, 1993 (Exhibits) (c) Exhibits. * Previously Filed and Incorporated Herein by Reference File As Exhibit Number Exhibit *3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation of the Company as filed with the Secretary of State of Idaho on June 30, 1989. *3(a)(i) 33-65720 4(a)(i) Statement of Resolution Establishing Terms of 8.375% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share), as filed with the Secretary of State of Idaho on September 23, 1991. *3(a)(ii) 33-65720 4(a)(ii) Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share), as filed with the Secretary of State of Idaho on November 5, 1991. *3(a)(iii) 33-65720 4(a)(iii) Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share), as filed with the Secretary of State of Idaho on June 30, 1993. *3(b) 33-41166 4(b) Waiver resolution to Restated Articles of Incorporation adopted by Shareholders on May 1, 1991. *3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on June 30, 1989, and presently in effect. *4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as of October 1, 1937, between the Company and Bankers Trust Company and R. G. Page, as Trustees. *4(a)(ii) Supplemental Indentures to Mortgage and Deed of Trust: Number Dated 1-MD B-2-a First July 1, 1939 2-5395 7-a-3 Second November 15, 1943 2-7237 7-a-4 Third February 1, 1947 2-7502 7-a-5 Fourth May 1, 1948 2-8398 7-a-6 Fifth November 1, 1949 2-8973 7-a-7 Sixth October 1, 1951 2-12941 2-C-8 Seventh January 1, 1957 2-13688 4-J Eighth July 15, 1957 2-13689 4-K Ninth November 15, 1957 2-14245 4-L Tenth April 1, 1958 2-14366 2-L Eleventh October 15, 1958 2-14935 4-N Twelfth May 15, 1959 2-18976 4-O Thirteenth November 15, 1960 2-18977 4-Q Fourteenth November 1, 1961 2-22988 4-B-16 Fifteenth September 15, 1964 2-24578 4-B-17 Sixteenth April 1, 1966 2-25479 4-B-18 Seventeenth October 1, 1966 2-45260 2(c) Eighteenth September 1, 1972 2-49854 2(c) Nineteenth January 15, 1974 2-51722 2(c)(i) Twentieth August 1, 1974 2-51722 2(c)(ii) Twenty-first October 15, 1974 2-57374 2(c) Twenty-second November 15, 1976 2-62035 2(c) Twenty-third August 15, 1978 33-34222 4(d)(iii) Twenty-fourth September 1, 1979 33-34222 4(d)(iv) Twenty-fifth November 1, 1981 33-34222 4(d)(v) Twenty-sixth May 1, 1982 33-34222 4(d)(vi) Twenty-seventh May 1, 1986 33-00440 4(c)(iv) Twenty-eighth June 30, 1989 33-34222 4(d)(vii) Twenty-ninth January 1, 1990 33-65720 4(d)(iii) Thirtieth January 1, 1991 33-65720 4(d)(iv) Thirty-first August 15, 1991 33-65720 4(d)(v) Thirty-second March 15, 1992 33-65720 4(d)(vi) Thirty-third April 16, 1993 1-3198 4 Thirty-fourth December 1, 1993 Form 8-K Dated 12/17/93 *4(b) Instruments relating to American Falls bond guarantee. (See Exhibits 10(f) and 10(f)(i)). *4(c) 33-65720 4(f) Agreement to furnish certain debt instruments. *4(d) 33-00440 2(a)(iii) Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation. *4(e) 33-65720 4(e) Rights Agreement dated January 11, 1990, between the Company and First Chicago Trust Company of New York, as Rights Agent (The Bank of New York, successor Rights Agent). *10(a) 2-51762 5(a) Agreement, dated April 20, 1973, between the Company and FMC Corporation. *10(a)(i) 2-57374 5(b) Letter Agreement, dated October 22, 1975, relating to agreement filed as Exhibit 10(a). *10(a)(ii) 2-62034 5(b)(i) Letter Agreement, dated December 22, 1976, relating to agreement filed as Exhibit 10(a). *10(a)(iii) 33-65720 10(a) Letter Agreement, dated December 11, 1981, relating to agreement filed as Exhibit 10(a). *10(b) 2-49584 5(b) Agreements, dated September 22, 1969, between the Company and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project. *10(b)(i) 2-51762 5(c) Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10(b). *10(c) 2-49584 5(c) Agreement, dated as of October 11, 1973, between the Company and Pacific Power & Light Company. *10(d) 2-49584 5(d) Agreement, dated as of October 24, 1973, between the Company and Utah Power & Light Company. *10(d)(i) 2-62034 5(f)(i) Amendment, dated January 25, 1978, relating to agreement filed as Exhibit 10(d). *10(e) 33-65720 10(b) Coal Purchase Contract, dated as of June 19, 1986, among the Company, Sierra Pacific Power Company and Black Butte Coal Company. *10(f) 2-57374 5(k) Contract, dated March 31, 1976, between the United States of America and American Falls Reservoir District, and related Exhibits. *10(f)(i) 33-65720 10(c) Guaranty Agreement, dated March 1, 1990, between the Company and West One Bank, as Trustee, relating to $21,425,000 American Falls Replacement Dam Bonds of the American Falls Reservoir District, Idaho. *10(g) 2-57374 5(m) Agreement, effective April 15, 1975, between the Company and The Washington Water Power Company. *10(h) 2-62034 5(p) Bridger Coal Company Agreement, dated February 1, 1974, between Pacific Minerals, Inc., and Idaho Energy Resources Co. *10(i) 2-62034 5(q) Coal Sales Agreement, dated February 1, 1974, between Bridger Coal Company and Pacific Power & Light Company and the Company. *10(i)(i) 33-65720 10(d) Second Restated and Amended Coal Sales Agreement, dated March 7, 1988, among Bridger Coal Company and PacifiCorp (dba Pacific Power & Light Company) and the Company. *10(j) 2-62034 5(r) Guaranty Agreement, dated as of August 30, 1974, with Pacific Power & Light Company. *10(k) 2-56513 5(i) Letter Agreement, dated January 23, 1976, between the Company and Portland General Electric Company. *10(k)(i) 2-62034 5(s) Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and the Company. *10(k)(ii) 2-62034 5(t) Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(k). *10(k)(iii) 2-62034 5(u) Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(k). *10(k)(iv) 2-62034 5(v) Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10(k). *10(k)(v) 2-62034 5(w) Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(k). *10(k)(vi) 2-68574 5(x) Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(k). *10(l) 2-68574 5(z) Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir. *10(m) 2-64910 5(y) Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and the Company. *10(n)1 33-65720 10(e) Nonqualified, deferred, compensation plan for certain senior management employees and directors of the Company. *10(o) 33-65720 10(f) Residential Purchase and Sale Agreement, dated August 22, 1981, among the United Stated of America Department of Energy acting by and through the Bonneville Power Administration, and the Company. *10(p) 33-65720 10(g) Power Sales Contact, dated August 25, 1981, including amendments, among the United States of America Department of Energy acting by and through the Bonneville Power Administration, and the Company. *10(q) 33-65720 10(h) Framework Agreement, dated October 1, 1984, between the State of Idaho and the Company relating to the Company's Swan Falls and Snake River water rights. *10(q)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984, between the State of Idaho and the Company relating to the agreement filed as Exhibit 10(q). *10(q)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October 25, 1984, between the State of Idaho and the Company relating to the agreement filed as Exhibit 10(q). *10(r) 33-65720 10(i) Agreement for Supply of Power and Energy, dated February 10, 1988, between the Utah Associated Municipal Power Systems and the Company. *10(s) 33-65720 10(j) Agreement Respecting Transmission Facilities and Services, dated March 21, 1988 among PC/UP&L Merging Corp. and the Company including a Settlement Agreement between PacifiCorp and the Company. *10(s)(i) 33-65720 10(j)(i) Restated Transmission Services Agreement, dated February 6, 1992, between Idaho Power Company and PacifiCorp. [FN] ___________________ 1 Compensatory Plan *10(t) 33-65720 10(k) Agreement for Supply of Power and Energy, dated February 23, 1989, between Sierra Pacific Power Company and the Company. *10(u) 33-65720 10(l) Transmission Services Agreement, dated May 18, 1989, between the Company and the Bonneville Power Administration. *10(v) 33-65720 10(m) Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between the Company and the Twin Falls Canal Company and the Northside Canal Company Limited. *10(v)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February 10, 1992, between the Company and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. *10(w) 33-65720 10(n) Agreement for the Purchase and Sale of Power and Energy, dated October 16, 1990, between the Company and The Montana Power Company. 12 Statement Re: Computation of Ratio of Earnings to Fixed Charges. 12(a) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. 12(b) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 12(c) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 21 Subsidiaries of Registrant. 23 Independent Auditors' Consent. IDAHO POWER COMPANY
SCHEDULE V - CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT Column A Column B Column C Column D Column E Column F Balance at Balance at Beginning Additions End of at Other Changes of Period Classification Period Cost (1) Retirements Transfers Other (2) Year Ended December 31, 1993 (Thousands of Dollars) Electric utility plant classified by prescribed accounts, at original cost: Intangible plant $ 4,930 $ 1,863 $ 234 $ (24) $ - $ 6,535 Production plant: Straight line 1,006,956 15,426 10,498 (17) - 1,011,867 5% present worth 187,192 129 - - - 187,321 Total 1,194,148 15,555 10,498 (17) - 1,199,188 Transmission plant: Straight line 315,972 4,269 1,287 1,017 - 319,971 5% present worth 8,250 28 - - - 8,278 Total 324,222 4,297 1,287 1,017 - 328,249 Distribution plant 545,490 43,294 5,137 (1,043) - 582,604 General plant: Straight line 130,154 6,626 3,519 67 - 133,328 5% present worth 257 16 - - - 273 Total 130,411 6,642 3,519 67 - 133,601 Plant held for future use 3,083 (125) - - - 2,958 Construction work in progress 66,997 25,685 - - - 92,682 Acquisition Adjustment (Prairie Power) (454) - - - - (454) Total electric utility plant $2,268,827 $97,211 $20,675 $ - $ - $2,345,363 Note (1): Additions at cost include completed projects transferred from construction work in progress and the amount of construction work in progress additions (deductions) represents the net changes for that account. (2): Five percent present worth balances are as of March 31, 1993. Effective April 1, 1993 all electric utility plant is classified as straight-line due to a change in depreciation methodology.
IDAHO POWER COMPANY
SCHEDULE V - CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT Column A Column B Column C Column D Column E Column F Balance at Beginning Additions Balance at of at Other Changes End Classification Period Cost (1) Retirements Transfers Other of Period Year Ended December 31, 1992 (Thousands of Dollars) Electric utility plant classified by prescribed accounts, at original cost: Intangible plant $ 3,695 $ 1,297 $ 62 $ - $ - $ 4,930 Production plant: Straight line 956,029 55,873 4,946 - - 1,006,956 5% present worth 184,041 3,236 71 (14) - 187,192 Total 1,140,070 59,109 5,017 (14) - 1,194,148 Transmission plant: Straight line 307,498 8,900 951 525 - 315,972 5% present worth 8,244 9 3 - - 8,250 Total 315,742 8,909 954 525 - 324,222 Distribution plant 513,467 38,401 5,829 (549) - 545,490 General plant: Straight line 121,382 15,479 6,743 36 - 130,154 5% present worth 255 - - 2 - 257 Total 121,637 15,479 6,743 38 - 130,411 Plant held for future use 3,060 23 - - - 3,083 Construction work in progress 70,841 (3,844) - - - 66,997 Acquisition adjustment (Prairie Power) - (454) - - - (454) Total electric utility plant $2,168,512 $118,920 $18,605 $ - $ - $2,268,827 Note (1): Additions at cost include completed projects transferred from construction work in progress and the amount of construction work in progress additions (deductions) represents the net changes for that account.
IDAHO POWER COMPANY
SCHEDULE V - CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT Column A Column B Column C Column D Column E Column F Balance at Beginning Additions Balance at of at Other Changes End Classification Period Cost (1) Retirements Transfers Other of Period Year Ended December 31, 1991 (Thousands of Dollars) Electric utility plant classified by prescribed a ccounts, at original cost: Intangible plant $ 3,430 $ 299 $ 34 $ - $ - $ 3,695 Production plant: Straight line 940,289 19,732 4,004 12 - 956,029 5% present worth 183,142 935 31 (5) - 184,041 Total 1,123,431 20,667 4,035 7 - 1,140,070 Transmission plant: Straight line 297,158 11,148 637 (171) - 307,498 5% present worth 8,025 278 43 (16) - 8,244 Total 305,183 11,426 680 (187) - 315,742 Distribution plant 483,050 34,784 4,559 192 - 513,467 General plant: Straight line 90,758 33,071 2,438 (9) - 121,382 5% present worth 259 (1) - (3) - 255 Total 91,017 33,070 2,438 (12) - 121,637 Plant held for future use 3,060 - - - - 3,060 Construction work in progress 35,192 35,658 - (9) - 70,841 Total electric utility plant $2,044,363 $135,904 $11,746 $ (9) $ - $2,168,512 Note (1): Additions at cost include completed projects transferred from construction work in progress and the amount of construction work in progress additions (deductions) represents the net changes for that account.
Idaho Power Company
Schedule VI - Consolidated Accumulated Depreciation and Amortization of Property, Plant and Equipment Column A Column B Column C Column D Column E Column F Additions Balance At Charged Charged To Deductions Other Balance At Beginning To Other Cost of Changes End Of Classification Of Period Income Accounts(1) Retirements Removal Salvage (2)(3) Period Year Ended December 31, 1993 (Thousands of Dollars) Accumulated provision for depreciation and amortization of electric utility plant shown in Schedule V: Intangible $ 2,325 $ 532 $ - $ 234 $ - $ - $ - $ 2,623 Production: Straight line 329,584 31,006 138 10,497 664 (8,258) (6,626) 351,199 5% present worth 39,088 601 - - 2 - - 39,687 Total 368,672 31,607 138 10,497 666 (8,258) (6,626) 390,886 Transmission: Straight line 105,983 7,196 - 1,276 480 (27) 1,767 113,217 5% present worth 4,311 77 - - - - - 4,388 Total 110,294 7,273 - 1,276 480 (27) 1,767 117,605 Distribution 169,077 18,225 - 5,136 1,320 (491) 6,747 188,084 General: Straight line 32,740 4,503 2,161 3,520 295 (527) (6,303) 29,813 5% present worth 233 2 - - - - (235) 0 Total 32,973 4,505 2,161 3,520 295 (527) (6,538) 29,813 Amortization of Acquistition Adj. (Prairie Power) (9) (23) - - - - - (32) Total $683,332 $62,119 $2,299 $20,663 $2,761 $(9,303) $(4,650) $728,979 Note (1): Represents amounts charged to transportation and communication clearing accounts which are distributed to other accounts on the basis of the use of the equipment and amounts charged to A/c 151 - Fuel Stock for Jim Bridger and Boardman coal railcars. (2): For 1993 includes damage claims, up and down costs, relocation costs, reserve transfers, Wood River Gas Turbine sale proceeds, Bald Mountain Distribution Facilities sale proceeds, customer off-street lighting conversion program undepreciated costs and reserve allocation adjustment between all transmission, distribution and general accounts. (3): Five percent present worth balances are as of March 31, 1993. Effective April 1, 1993 all accumulated depreciation and amortization is classified as straight-line due to a change in depreciation methodology.
Idaho Power Company
Schedule VI - Consolidated Accumulated Depreciation and Amortization of Property, Plant and Equipment Column A Column B Column C Column D Column E Column F Additions Balance At Charged Charged To Deductions Other Balance At Beginning To Other Cost of Changes End Of Classification Of Period Income Accounts(1) Retirements Removal Salvage (2) Period Year Ended December 31, 1992 (Thousands of Dollars) Accumulated provision for depreciation and amortization of electric utility plant shown in Schedule V: Intangible $ 2,071 $ 316 $ - $ 62 $ - $ - $ - $ 2,325 Production: Straight line 305,284 29,059 140 4,745 149 (5) (10) 329,584 5% present worth 36,712 2,459 - 71 12 - - 39,088 Total 341,996 31,518 140 4,816 161 (5) (10) 368,672 Transmission: Straight line 100,418 6,577 - 946 712 (31) 615 105,983 5% present worth 4,030 293 - 3 1 - (8) 4,311 Total 104,448 6,870 - 949 713 (31) 607 110,294 Distribution 158,420 16,596 - 5,786 1,350 (425) 772 169,077 General: Straight line 32,077 4,589 2,054 6,715 63 (647) 151 32,740 5% present worth 226 8 - - - - (1) 233 Total 32,303 4,597 2,054 6,715 63 (647) 150 32,973 Amortization of acquisition adjustment (Prairie Power) - (9) - - - - - (9) Total $639,238 $59,888 $2,194 $18,328 $2,287 $(1,108) $1,519 $683,332 Note (1): Represents amounts charged to transportation and communication clearing accounts which are distributed to other accounts on the basis of the use of the equipment and amounts charged to A/c 151 - Fuel Stock for Jim Bridger and Boardman coal railcars. (2): Includes damage claims, up & down costs, relocation reimbursements, accumulated reserve transfers, and Prairie Power Co-op, Inc. (purchased in 1992) accumulated depreciation.
Idaho Power Company
Schedule VI - Consolidated Accumulated Depreciation and Amortization of Property, Plant and Equipment Column A Column B Column C Column D Column E Column F Additions Balance At Charged Charged To Deductions Other Balance At Beginning To Other Cost of Changes End Of Classification Of Period Income Accounts (1) Retirements Removal Salvage (2) Period Year Ended December 31, 1991 (Thousands of Dollars) Accumulated provision for depreciation and amortization of electric utility plant shown in Schedule V: Intangible $ 1,838 $ 267 $ - $ 34 $ - $ - $ - $ 2,071 Production: Straight line 280,559 29,168 16 4,004 473 (20) (2) 305,284 5% present worth 34,665 2,077 - 31 2 (23) 2 36,712 Total 315,224 31,245 16 4,035 497 (43) - 341,996 Transmission: Straight line 95,322 6,332 - 637 579 (85) (105) 100,418 5% present worth 3,787 279 - 43 (7) - - 4,030 Total 99,109 6,611 - 680 572 (85) (105) 104,448 Distribution 147,610 15,695 - 4,559 1,320 (501) 493 158,420 General: Straight line 28,572 3,772 1,929 2,438 89 (331) - 32,077 5% present worth 219 7 - - - - - 226 Total 28,791 3,779 1,929 2,438 89 (331) - 32,303 Total $592,572 $57,597 $1,945 $11,746 $2,478 $(960) $388 $639,238 Note (1): Represents amounts charged to transportation and communication clearing accounts which are distributed to other accounts on the basis of the use of the equipment. (2): For 1991 includes damage claims, up and down costs, relocation reimbursements and accumulated reserve transfers.
IDAHO POWER COMPANY
SCHEDULE VIII - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1993, 1992 and 1991 Column C Column A Column B Additions Column D Column E Balance Balance Charged Charged At At to (Credited) Deductions End Of Classification Beginning Income to Other Period Of Period Accounts (1) (Thousands of Dollars) 1993: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,421 $1,174 $1,001(2) $2,219 $1,377 Other Reserves: Injuries and damages reserve $1,500 $2,820 $ - $2,820 $1,500 Miscellaneous operating reserves $ - $ 870 $ 332 $ 454 $ 748 1992: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,300 $1,224 $ 963(2) $2,066 $1,421 Other Reserves: Injuries and damages reserve $1,366 $2,468 $ - $2,334 $1,500 1991: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,290 $1,217 $1,224(2) $2,431 $1,300 Other Reserves: Injuries and damages reserve $3,086 $3,996 $ - $5,716 $1,366 Miscellaneous operating reserves $1,250 $ - $1,892 $3,142 $ - NOTES: (1) Represents deductions from the reserves for purposes for which the reserves were created. (2) Represents collections of accounts previously written off.
IDAHO POWER COMPANY SCHEDULE X - CONSOLIDATED SUPPLEMENTARY INCOME STATEMENT INFORMATION Column A Column B Charged to Costs and Expenses Year Ended December 31, Item 1993 1992 1991 (Thousands of Dollars) Taxes other than income taxes are as follows: Property $16,168 $15,467 $15,081 State kilowatt-hour 1,834 1,158 1,273 Social security and unemployment 5,814 5,564 5,197 Miscellaneous 1,129 1,793 1,807 Total $24,945 $23,982 $23,358 Charged to: Operating expenses - taxes $22,129 $20,562 $21,170 Other income 41 54 30 Construction, clearing and sundry 2,775 3,366 2,158 Total $24,945 $23,982 $23,358 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. IDAHO POWER COMPANY (Registrant) March 10, 1994 By:__/s/ __Joseph W.Marshall__ Joseph W. Marshall Chairman of the Board and Chief Executive Officer and Director Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. By:__/s/__Joseph W. Marshall__ Chairman of the Board and March 10, 1994 Joseph W. Marshall Chief Executive Officer and Director By:__/s/__Larry R. Gunnoe__ President and Chief Operating " Larry R. Gunnoe Officer and Director By:__/s/__J. LaMont Keen___ Vice President and Chief Financial " J. LaMont Keen Officer (Principal Financial Officer) By:__/s/__Harold J. Hochhalter_ Controller and Chief Accounting Officer " Harold J. Hochhalter (Principal Accounting Officer) By:__/s/__Robert D. Bolinder__ By:__/s/__Evelyn Loveless__ " Robert D. Bolinder Evelyn Loveless Director Director By:__/s/__Roger L. Breezley__ By:__/s/__James A. McClure__ " Roger L. Breezley James A. McClure Director Director By:__/s/__John B. Carley__ By:__/s/__ Jon H. Miller__ " John B. Carley Jon H. Miller Director Director By:__/s/__George L. Coiner__ By:__/s/__Richard T. Norman__ " George L. Coiner Richard T. Norman Director Director By:__/s/__Gene C. Rose__ By:__/s/__Phil Soulen__ " Gene C. Rose Phil Soulen Director Director By:__/s/__Peter T. Johnson__ " Peter T. Johnson Director EXHIBIT INDEX Exhibit Page Number Number 12 Statement Re: Computation of Ratio of 99 Earnings to Fixed Charges. 12(a) Statement Re: Computation of 100 Supplemental Ratio of Earnings to Fixed Charges. 12(b) Statement Re: Computation of Ratio of 101 Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 12(c) Statement Re: Computation of 102 Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 21 Subsidiaries of Registrant. 103 23 Independent Auditors' Consent. 104 EX-12 2 Idaho Power Company
Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1989 1990 1991 1992 1993 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464 Income taxes: Income taxes (includes amounts charged to other income and deductions) 45,336 26,418 24,321 24,601 38,057 Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583) Total income taxes 42,041 23,234 21,144 23,162 36,474 Income before income taxes 126,778 92,475 79,016 83,152 120,938 Fixed Charges: Interest on long-term debt 49,629 50,119 54,370 53,408 53,706 Amortization of debt discount, expense and premium - net 238 309 374 392 507 Interest on short-term bank loans 2,200 1,027 935 647 220 Other interest 3,164 2,259 3,297 1,011 2,023 Interest portion of rentals 757 902 884 683 1,077 Total fixed charges 55,988 54,616 59,860 56,141 57,533 Earnings - as defined $182,766 $147,091 $138,876 $139,293 $178,471 Ratio of earnings to fixed charges 3.26X 2.69X 2.32X 2.48X 3.10X
EX-12.(A) 3 Idaho Power Company
Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1989 1990 1991 1992 1993 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464 Income taxes: Income taxes (includes amounts charged to other income and deductions) 45,336 26,418 24,321 24,601 38,057 Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583) Total income taxes 42,041 23,234 21,144 23,162 36,474 Income before income taxes 126,778 92,475 79,016 83,152 120,938 Fixed Charges: Interest on long-term debt 49,629 50,119 54,370 53,408 53,706 Amortization of debt discount, expense and premium - net 238 309 374 392 507 Interest on short-term bank loans 2,200 1,027 935 647 220 Other interest 3,164 2,259 3,297 1,011 2,023 Interest portion of rentals 757 902 884 683 1,077 Total fixed charges 55,988 54,616 59,860 56,141 57,533 Suppl increment to fixed charges* 2,321 1,969 1,599 2,487 2,631 Total supplemental fixed charges 58,309 56,585 61,459 58,628 60,164 Supplemental earnings - as defined $185,087 $149,060 $140,475 $141,780 $181,102 Supplemental ratio of earnings to fixed charges 3.17X 2.63X 2.29X 2.42X 3.01X * Explanation of increment: Interest on the quaranty of American Falls Reservoir District Bonds and Milner Dam Inc Notes which are already included in operating expense.
EX-12.(B) 4 Idaho Power Company
Consolidated Financial Information Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements Twelve Months Ended December 31, (Thousands of Dollars) 1989 1990 1991 1992 1993 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464 Income taxes: Income taxes (includes amounts charged to other income and deductions) 45,336 26,418 24,321 24,601 38,057 Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583) Total income taxes 42,041 23,234 21,144 23,162 36,474 Income before income taxes 126,778 92,475 79,016 83,152 120,938 Fixed Charges: Interest on long-term debt 49,629 50,119 54,370 53,408 53,706 Amortization of debt discount, expense and premium - net 238 309 374 392 507 Interest on short-term bank loans 2,200 1,027 935 647 220 Other interest 3,164 2,259 3,297 1,011 2,023 Interest portion of rentals 757 902 884 683 1,077 Total fixed charges 55,988 54,616 59,860 56,141 57,533 Preferred dividend requirements 6,374 5,685 6,663 7,611 8,547 Total fixed charges and preferred dividends 62,362 60,301 66,523 63,752 66,080 Earnings - as defined $182,766 $147,091 $138,876 $139,293 $178,471 Ratio of earnings to fixed charges preferred dividends 2.93X 2.44X 2.09X 2.18X 2.70X
EX-12.(C) 5 Idaho Power Company
Consolidated Financial Information Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements Twelve Months Ended December 31, (Thousands of Dollars) 1989 1990 1991 1992 1993 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 84,737 $ 69,241 $ 57,872 $ 59,990 $ 84,464 Income taxes: Income taxes (includes amounts charged to other income and deductions) 45,336 26,418 24,321 24,601 38,057 Investment tax credit adjustment (3,295) (3,184) (3,177) (1,439) (1,583) Total income taxes 42,041 23,234 21,144 23,162 36,474 Income before income taxes 126,778 92,475 79,016 83,152 120,938 Fixed Charges: Interest on long-term debt 49,629 50,119 54,370 53,408 53,706 Amortization of debt discount, expense and premium - net 238 309 374 392 507 Interest on short-term bank loans 2,200 1,027 935 647 220 Other interest 3,164 2,259 3,297 1,011 2,023 Interest portion of rentals 757 902 884 683 1,077 Total fixed charges 55,988 54,616 59,860 56,141 57,533 Suppl increment to fixed charges* 2,321 1,969 1,599 2,487 2,631 Supplemental fixed charges 58,309 56,585 61,459 58,628 60,164 Preferred dividend requirements 6,374 5,685 6,663 7,611 8,547 Total supplemental fixed charges and preferred dividends 64,683 62,270 68,122 66,239 68,711 Supplemental earnings - as defined $185,087 $149,060 $140,475 $141,780 $181,102 Supplemental ratio of earnings to fixed charges and preferred dividends 2.86X 2.39X 2.06X 2.14X 2.64X * Explanation of increment: Interest on the quaranty of American Falls Reservoir District Bonds and Milner Dam Inc Notes which are already included in operating expense.
EX-21 6 SUBSIDIARIES OF REGISTRANT 1. Idaho Energy Resources Co., a Wyoming Corporation 2. Idaho Utility Products Company, an Idaho Corporation 3. IDACORP, INC., an Idaho Corporation 4. Ida-West Energy Company, an Idaho Corporation EX-23 7 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-65720 and 33-51215 of Idaho Power Company on Form S-3; and Post-Effective Amendment No. 1 to Registration Statement No. 2-99567 and Registration Statement No. 33-36947 of Idaho Power Company on Form S-8 of our report dated January 31, 1994 appearing in this Annual Report on Form 10-K of Idaho Power Company for the year ended December 31, 1993. DELOITTE & TOUCHE Portland, Oregon March 7, 1994 -----END PRIVACY-ENHANCED MESSAGE-----