-----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, A0FIL5q8K1OMlvvjxZ9DO9AT5Limi51juor1ZW63tHLL2eHpfoSuac8sAzf2Po5Z WYWWslzGEDP/ycKmDWHHUA== 0000049648-95-000011.txt : 19950615 0000049648-95-000011.hdr.sgml : 19950615 ACCESSION NUMBER: 0000049648-95-000011 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950310 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: IDAHO POWER CO CENTRAL INDEX KEY: 0000049648 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 820130980 STATE OF INCORPORATION: ID FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03198 FILM NUMBER: 95519719 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, 1994 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)-388-2200 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 whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Aggregate market value of voting stock held by nonaffiliates (January 31, 1995) $948,028,200 Number of shares of common stock outstanding at February 28, 1995 37,612,351 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 1995 Annual Meeting of Item 13 Shareowners to be held on May 3, 1995. The exhibit index is located on page 92. This document contains 140 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 695,000 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 implementation of a power cost adjustment mechanism (PCA) 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, temperature conditions, and management decisions and less on precipitation and streamflow conditions. As of December 31, 1994, the Company supplied electric energy to 330,308 general business customers and employed 1,703 people in its operations (1,609 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, 1994, 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 19 percent, commercial and industrial customers with 750 kW demand and over accounted for 19 percent and irrigation customers accounted for 12 percent. Public utilities and interchange arrangements accounted for 11 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 four large special contract customers in its Idaho retail jurisdiction - the Idaho National Engineering Laboratory (INEL), the J. R. Simplot Company, FMC Corporation (FMC) and Micron Technology, Inc. (Micron). 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, up to 38 megawatts of capacity and energy to the J. R. Simplot Company for its chemical fertilizer operations plant near Pocatello, Idaho and up to 37 megawatts of capacity and energy to Micron located in Boise. 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 by FMC 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 $30.5 million for 1.4 million megawatt- hours (MWH) of energy supplied during the twelve months ended December 31, 1994. Competition - Competition is increasing in the electric utility industry, due to a variety of developments (National Energy Policy Act of 1992, utility mergers surrounding our service territory, large cogeneration and small power projects, customer demands, etc.). In response to increasing competition, the Company continues to proceed with a strategic planning process. The goal of this process is to anticipate and fully integrate into Company operations any legislative, regulatory, environmental, competitive, or technological changes. With its low average energy production costs, the Company is ready to enter a more competitive environment and is taking action to preserve its low- cost competitive advantage. (see Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Competition and Strategic Planning.) With its predominantly hydro base and low-cost thermal plants, the Company is one of the lowest cost producers of electric energy among the nation's investor-owned utilities. Through its interconnections with BPA, PacifiCorp and other utilities, the Company has access to all the major electric systems in the West. 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 Rates). The Company's rates for its large (750 kW and over) industrial customers, excluding special contracts, averaged approximately 2.8 cents per kilowatt hour (see Power Supply). Some of these customers are converting waste heat to electricity for sale to the Company while purchasing their entire power needs at the Company's lower rates. The Company's rates for its small (under 750 kW) commercial and industrial customers average approximately 4.3 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 what was the utility's 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 the service area they are located or from any other electric utility or independent power supplier. The Idaho Legislature and the IPUC have not yet addressed retail wheeling. However, the Company believes with its low-cost energy production it is positioned 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 five wholly-owned subsidiary companies: Ida-West Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo), Idaho Utility Products Company (IUPCo), IDACORP, INC., and Stellar Dynamics. Ida-West was formed in 1989 to participate through partnership interests in cogeneration and small power production (CSPP) projects. Ida-West owns, through various partnerships, 50 percent of five Idaho hydroelectric projects with a total generating capacity of approximately 34 megawatts (MW). Third parties unaffiliated with Ida-West own the remaining 50 percent of these projects, thus satisfying the "qualifying facility" status under Public Utility Regulatory Policy Act (PURPA) guidelines. The partnerships have obtained project financing (non-recourse to the Company) for each of these facilities. Power purchased from these facilities amounted to approximately $7.1 million in 1994. To date, all power sales made by Ida-West have been to the Company. The Company has invested $20 million in Ida-West. Ida-West continues to actively seek to develop new projects. (see Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Subsidiaries.) 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, 1994, the Company's total investment in IERCo was $4.5 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 1994. As of December 31, 1994, the combined total investment in these subsidiaries was $3.3 million. In 1994, Idaho Power announced the formation of a fifth subsidiary company. Stellar Dynamics hopes to commercialize the Company's extensive expertise in control technology for electric substations and power plants. The Company approved the new venture after receiving a positive recommendation from a market survey by Newton-Evans Research Company. The recommendation was backed by strong interest from potential customers. One-third of the companies surveyed, including several large investor-owned utilities, requested product information. The primary opportunity for Stellar Dynamics' design, consulting, installation, and troubleshooting services lies in the U.S. substation controls market. The Company expects to capitalize Stellar Dynamics during the first half of 1995. Research and Development and Renewable Energy Sources - 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 now called Solar Two near Barstow, California. 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 have contributed $630,500 by the end of 1998 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 main benefit the Company will receive by participating in this project is valuable experience and knowledge in solar plant design, construction and operation. During 1994, the Company spent approximately $2.2 million on research and development of which $1.9 million was the Company's membership in EPRI. 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. As a member of EPRI, the Company participates in collaborative research projects with other EPRI-member utilities. This type of research project is known as Tailored Collaboration. It is tailored in that EPRI members invest additional funds to support research projects of specific value to their operations. In turn, EPRI provides matching funds from the Institute's base budget. Another aspect of the Company's research and development efforts is an internal program called the Emerging Technology (ET) Program. The ET program was established to maintain an active and coordinated response to new technology and the ongoing industry research program and initiatives that are of interest to the Company. Parts of the Company's service territory show a strong potential for solar power. The Company has just completed designing and constructing the nation's largest hybrid solar-powered photovoltaic (PV) system in the Mountain Home Air Force Base project. (see Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Solar and Solar Photovoltaic Projects.) 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 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 1994, the Company expended $7.0 million cash 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 in 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. In 1994, drought conditions again returned to the Company's service area. These conditions have hampered the Company's hydroelectric operations six of the last eight years. The system peak demand for 1994 was 2,392 megawatts set on June 23, 1994, which was 11.0 percent above the 1993 peak demand and 5.5 percent above the 1992 demand. The following table sets forth the total energy sources of the Company for the last five years: Total Energy Sources (000's of MWH) 1994 1993 1992 1991 1990 Generation - net station output - Hydro 6,213.2 8,361.7 4,990.3 5,819.2 6,108.8 Coal-fired 7,221.8 6,485.5 7,295.6 5,833.7 5,957.0 Purchased and interchange 2,287.0 1,273.8 2,102.8 2,583.1 1,936.7 Total 15,722.0 16,121.0 14,388.7 14,236.0 14,002.5 Purchased power expenses were high and fluctuated during the last three years reflecting necessity purchases from neighboring utilities during the drought years. The Company increases utilization of its thermal facilities by operating at high capacity factors during drought periods which increases fuel expense. Conversely, it relies more on hydro facilities to meet customer demand during good water years thereby reducing fuel expense. During 1994, approximately 40 percent of the Company's load requirements were met with the Company's hydroelectric generating plants, 46 percent from the thermal generating plants and the remaining 14 percent was purchased from or exchanged with neighboring utilities or from CSPP facilities. By comparison, hydroelectric generation met 52 percent of load requirements in 1993, 35 percent in 1992, 41 percent in 1991 and 44 percent in 1990. In a normal water year the hydro system contributes approximately 58 percent, thermal generation accounts for 33 percent and purchased power and other interchanges contributes the remaining 9 percent of total system requirements. Although it is too early to predict with certainty what hydroelectric conditions will be during 1995, preliminary reports indicate the mountain snowpack is approximately normal for this time of year. However, the carryover reservoir storage throughout the Snake River Basin is below average. 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 opportunities to purchase, sell, exchange and transmit energy. 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 (BPA), 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 most of the electric systems in the West. The Company is a member of the Intercompany Pool, the Western Systems Coordinating Council, the Western Systems Power Pool, and the Northwest 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 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 a detailed position paper to its state regulators and other interested parties. In December 1993 the Company filed with the IPUC for permission to approve lower published prices for new CSPP contracts. In response to the Company's filing, on January 31, 1995 the IPUC issued an order approving lower published CSPP rates. (see Rates and Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Issues.) New Projects - In response to increased customers and demand, the Company periodically updates its load and resource projections and now expects total Company energy requirements over the next 20 years to grow at an annual rate of 1.1 percent. The Company's current projects include the expansion from 10 to 53 megawatts of the Twin Falls hydro plant (1995) (see Construction Program). 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 path for regional transfers of power between the northwest and southwest. The Southwest Intertie Project (SWIP) is a proposed 500-mile, 500-Kv transmission line that would interconnect the Company's system with utilities in the Southwest. The Bureau of Land Management (BLM) completed the Final Environmental Impact Statement/Proposed Plan Amendment for the SWIP with a Record of Decision and Right of Way issued in December 1994. The utility and BLM will begin to prepare a detailed site-specific construction, operation and maintenance plan aimed at mitigating the environmental impact of the project. Detailed engineering work could begin in 1995. The Company has received preliminary commitments from various utility and non- utility entities 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 1999 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) 1995 1996 1997 1998 1999 Generation capability 2,686 2,691 2,691 2,691 2,691 Contracts: Exchange (b) 175 175 175 175 175 Cogeneration and small power production 134 158 158 158 158 Firm peak load less interruptible (2,276) (2,307) (2,392) (2,473) (2,510) Peak capability margin 719 717 632 551 514 Percent 31.6% 31.1% 26.4% 22.3% 20.5% (a) Based upon median hydro conditions. (b) Net summer-winter exchange. Annual Energy Capability (000's of MWH)(a) 1995 1996 1997 1998 1999 Generation capability 15,270 15,396 15,472 15,688 15,997 Contracts: Cogeneration and small power production 764 1,107 1,107 1,107 1,107 Annual firm load (b) (15,370) (15,446) (15,602) (16,179) (16,243) Energy capability margin 664 1,057 977 616 861 Percent 4.3% 6.8% 6.3% 3.8% 5.3% (a) Forecast based upon average of 66 historical water conditions. (b) The growth in retail load is being offset by termination of some large short-term firm contracts. During the 1995-1999 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 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 62 CSPP projects on-line as of December 31, 1994, is currently $40.7 million. During 1994, the Company purchased 543.3 million kilowatt-hours of power from these private developers at a blended price of 5.7 cents per kilowatt- hour (see Rates). 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 are presently scheduled to expire between 1996 and 2009. As these contracts expire the Company will use the energy to meet current retail load, re-negotiate a new contract with the existing customer or contract with new wholesale customers for the sale of energy. Transmission Service - The Company has long had an open access transmission policy and is experienced in providing reliable, high quality, economical transmission service. The Company presently provides transmission service to BPA for their sales of electricity to certain irrigation districts in southern Idaho for irrigation pumping and their 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 wheeling agreements with various surrounding utilities. Most recently, the Company has agreed to provide transmission service required by Sierra Pacific Power Company and the Washington Water Power Company to complete their proposed merger. The Company's system lies between and is interconnected to the winter peaking northern and summer peaking southern regions of the western interconnected power system. This position should be advantageous both in providing transmission service and reaching a broad power sales market. To help facilitate access throughout the power system, the Company has become a charter member of the Western Regional Transmission Association. This association is the first of the regional transmission groups seeking a FERC charter to facilitate transmission access under the National Energy Policy Act of 1992. 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 Jim Bridger Coal Mine 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: 1990 - $20.68; 1991 - $20.78; 1992 - $20.13; 1993 - $20.99 and 1994 - $19.52. 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 AMAX Coal Company for delivery of low sulfur coal from its mines 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 up to 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. In 1987, the Idaho Department of Water Resources filed a petition in state district court commencing the Snake River Basin Adjudication. This proceeding was initiated pursuant to state statute and a determination by the Idaho Legislature that the effective management of the Snake River basin required a comprehensive determination of the nature, extent and priority of all water users. The adjudication is still in its early stages, and the process will likely continue past the turn of the century. The Company has filed claims to its water rights within the basin and is participating in the adjudication to insure that its operations and water rights are not adversely impacted. The Company does not anticipate any modification of its water rights as a result of 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 IPUC, the OPUC 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 are not in conflict with the Federal Power Act or the Company's FERC license (see Item 2. Properties). 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 and the modification of system operations to accommodate such regulation. 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 1995 and during the period 1996-1999 will total approximately $1.5 million and $5.2 million, respectively. The Company also anticipates spending approximately $20 million a year in operating expenses for environmental facilities during the 1995-1999 period. 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. The Company has entered into a joint arrangement with PacifiCorp and Black Hills Power and Light under which certain of these companies generating units have been accepted by the Environmental Protection Agency as "Substitution" units for the Baldwin #2 unit owned by Illinois Power Company. In exchange for Illinois Power naming units at the Jim Bridger Station as "Substitution" units for Baldwin #2, the Company sold Illinois Power a portion of the Phase I SO2 Allowances it received by having its share of the Jim Bridger units accepted as Phase I "Substitution" units. 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 1994, the investment in these facilities was $11.7 million and the operation of these facilities pursuant to the FERC License 1971 cost approximately $2.5 million annually. The Niagara Springs project is currently going through an approximate $3.9 million expansion. Endangered Species - The Company continues to review and analyze the various effects upon its operations of the listing as threatened or endangered of several species of salmon and Snake River mollusks. The Company is cooperating with various governmental agencies to resolve these issues. (see Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation - Environmental Issues.) 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 $0.3 million, $0.1 million and $1.3 million for 1992, 1993, and 1994 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 (EMF) - While scientific research has yet to establish any conclusive link between EMF and human health, the possibility has caused public concern in the United States and abroad. Electric and magnetic fields are found wherever there is electric current, whether the source is a high-voltage transmission line or the simplest of electrical household appliances. Concerns over possible health effects have prompted regulatory efforts in several states to limit human exposure to EMF. Depending on what researchers ultimately discover and what regulations may be deemed necessary, it is possible that this issue could affect a number of industries, including electric utilities. However, at this time it is difficult to estimate what impacts, if any, the EMF issue could have on the Company and its operations. RATES Idaho Jurisdiction - Since May 1993, the Company's PCA mechanism has provided for it to collect, or to refund, a portion of the differences between actual net power supply costs and those allowed in the Company's Idaho base rates. Rates are adjusted each May based on forecasted costs for the upcoming period May-April. Deviations from forecasted costs are deferred with interest and trued up the following year. The Company filed its 1994 PCA application with the IPUC on April 15, 1994, requesting an increase in addition to base rates. The increase (in effect from May 16, 1994 through May 15, 1995) was approximately $9.8 million or 2.5 percent including last year's true-up. At December 31, 1994, the Company had recorded $8.6 million of power supply costs above those projected in the 1994 forecast. This cumulative amount adjusted for any deferrals through March 1995 will be requested to be included in the 1995 true-up adjustment. With the IPUC's recent revenue requirement order, beginning February 1, 1995, the PCA mechanism increased on a prospective basis to a 90 percent payout level from its original 60 percent. On June 30, 1994, the Company filed a general revenue requirement rate case with a calendar year 1993 test year, a thirteen month average rate base (annualized for its new Swan Falls production project) and a year end capitalization structure. The IPUC conducted hearings commencing on October 10 and December 12, 1994. On January 31, 1995, the Company received IPUC Order No. 25880 authorizing $17.2 million in general rate relief representing a 4.2 percent overall increase in Idaho retail rates. The relief is based on an 11.0 percent allowed return on equity with an overall rate of return of 9.199 percent. The Company had requested $37.1 million in general rate relief representing a 9.09 percent increase in rates, a 12.50 percent return on equity, and a 9.88 percent overall rate of return. These increased rates are effective February 1, 1995. On February 21, 1995 Idaho Power filed a Petition for Reconsideration with the IPUC in regard to Order No. 25880 issued January 31, 1995. In the petition, the Company requested an increase in the authorized rate of return on common equity to 11.75 percent. This would result in an additional increase in revenues of $6,840,143 or 1.6 percent. The petition is based on the Company's position that the rate of return determination was based upon an erroneous application of rate of return evidence, was unreasonable and contrary to the findings of the order, and failed to include any added increment for rewarding management's efforts. (see Part II - Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Regulatory Issues.) In September 1993, the Company submitted a detailed position paper to its state regulators and other interested parties. This report outlined proposed changes in the Company's resource acquisition policy. With the potential deregulation of the electric utility industry, and a more competitive power supply marketplace, the Company believes that current resource acquisition policies must be changed to avoid burdening it and its customers with unnecessary future power supply costs. The Company believes that the appropriate criteria for adding future supplies should be power needs at the time of development and that the addition be the least-cost market alternative. Therefore, in December 1993 the Company filed with the IPUC for permission to approve lower published prices for new CSPP contracts. In response to the Company's filing, on January 31, 1995 the IPUC issued an order approving lower published CSPP rates. In the order, the IPUC also determined that negotiated rates for future CSPP projects larger than one megawatt should be more closely tied to values determined in the Company's integrated resource planning process. In its order, the IPUC stated, "There is a widely held expectation that there will be increasing competition within the electric utility industry. In light of that, we believe it is especially important that the QF [Qualified Facilities] industry be able to demonstrate that the energy resources offers are as cost effective as those that a utility would construct." Oregon Jurisdiction - The Company presently contemplates filing a general revenue requirement case in Oregon in 1995 using the same information prepared for its 1994 general revenue requirement filing before the IPUC. The Company's PCA mechanism applies only to its Idaho jurisdiction. As a result of 1994's high power supply costs, the Company also filed for temporary drought rate relief with the OPUC. The OPUC issued an accounting order that granted the Company permission to defer with interest 60 percent of Oregon's share of the Company's increased power supply costs incurred between May 13, 1994 and December 31, 1994. The amount deferred at December 31, 1994 was $1.3 million. The Company is required and will file an application with the OPUC in early 1995 to recover these deferred costs. Other Jurisdictions - In 1994 the Company did not file any applications for rate relief before the FERC or in its Nevada retail jurisdiction. CONSTRUCTION PROGRAM The Company's construction program for the 1995-1999 period includes expansion of the Twin Falls hydro facility with the balance primarily in transmission and distribution facilities. The total cash construction program (excluding allowance for funds used during construction) for the five-year period 1995- 1999 is presently estimated to require cash funds of approximately $418.7 million as follows: 1995 1996-1999(a) (Millions of Dollars) Generating Facilities: Hydro $ 21.6 $ 35.4 Thermal 7.2 22.9 Total generating facilities 28.8 58.3 Transmission lines and substations 13.6 48.9 Distribution lines and substations 37.8 146.1 General 14.6 70.6 Total cash construction 94.8 323.9 AFUDC 1.7 4.5 Total construction including AFUDC (b) $ 96.5 $328.4 (a) Includes construction costs escalated at 3.25%, 2.49%, 2.61% and 2.84% annually for the years 1996-1999, respectively. (b) Does not include Ida-West equity investment in construction as Ida-West develops 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. In early spring of 1994, the Company completed testing of its new Swan Falls Project and both units were declared available for commercial operation. At December 31, 1994, the Company had spent approximately $55.0 million for construction of the Swan Falls Project, including allowance for funds used during construction. Additional work to preserve the old power plant as an historical site began during the year. Work to establish a museum on the site is scheduled for completion in 1995. In May, crews completed the federally-mandated stabilization of the dam and began the environmental reclamation of approximately 18 acres of land affected by construction activities. 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 $38.1 million with total construction costs at $41.9 million including allowance for funds used during construction. At December 31, 1994, the Company had expended approximately $29.4 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) efficiency improvements on the Company's generation, transmission and distribution systems, (2) additional power purchases from CSPP facilities, (3) purchased power and exchange agreements with other utilities or other power suppliers and (4) customer conservation. 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 refund maturing long- term debt. The most recent estimate of capital requirements and sources of capital for the period is $428.5 million outlined as follows: 1995 1996-1999 (Millions of Dollars) Capital Requirements: Net cash construction expenditures $ 94.8 $323.9 Conservation expenditures 7.8 16.3 Other cash expenditures (4.1) (10.2) Total $ 98.5 $330.0 Sources of Capital: Internal generation $ 60.3 $333.6 Short-term bank loans - Net (22.0) (31.0) First mortgage bonds/PC bond 50.0 138.1 Debt repayment (.6) (120.7) Common stock 12.0 14.0 Cash investments (increase) (1.2) (4.0) Total (a) $ 98.5 $330.0 (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, 1994, net earnings were 5.89 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, 1994, the actual preferred dividend earnings coverage was 2.61 times. If the dividends on the shares of Auction Preferred Stock were to reach the maximum allowed, the preferred dividend earnings coverage would be 2.40 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 4,648 miles of high voltage transmission lines; 21 step-up transmission substations located at power plants; 17 transmission substations; 7 transmission switching stations; and 195 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 1,166,900 2005 Swan Falls 27,170 27,170 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 Station) 693,333 678,077 Valmy (Coal-Fired Station) 260,650 260,650 Boardman (Coal-Fired Station) 53,000 53,000 On December 31, 1994, the composite average ages of the principal parts of the Company's system, based on dollar investment, were: production plant, 15.8 years; transmission system and substations, 18.0 years; and distribution lines and substations, 13.8 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 vigorously pursued 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 will submit its first applications for license renewal to the FERC in December 1995. These first applications will seek renewal of the Company's licenses for its Bliss, Upper Salmon and Lower Salmon Hydroelectric Projects. The Company cannot anticipate what type of environmental capital investment 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 and PCB/lead 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 will supersede EPA's "Interim" Administrative Order when it is entered by the court. On August 30, 1993, Notice of the Lodging of the Amended Partial 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 Partial 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. Following receipt of the Company's responses, EPA undertook further factual investigations relating to the extent of lead contamination at the site and the nature and extent of lead contributions to the site, including the Company's involvement. The Amended Partial Consent Decree was finally lodged together with EPA's Motion to Enter with the U.S. District Court for the District of Idaho on December 12, 1994. The Amended Partial Consent Decree provides that the Company is protected against any and all claims for contribution by other PRPs, both as to the PCB and lead contamination. On January 24, 1995, the Company was advised that the PRP group associated with lead contamination was objecting to the proposed entry of the Amended Partial Consent Decree on the basis that the Company has not paid its "fair share" of the remaining lead clean- up costs which EPA currently estimates at approximately $5 million. It is EPA's position that the Company, as an integral part of its clean-up of the PCB contamination and PCB/lead contamination, removed approximately 57 percent of the total lead contamination from the entire site, even though the Company contributed only 10.5 percent of the total lead contamination. The Company believes that the objections filed by the PRPs are completely without merit, and both the Company and the EPA are responding to the objections of the PRPs. 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, March 10, 1994, 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 and 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 costs of site remediation, and damages for the insurers' breach of the insurance contracts based on the insurers' failure to pay such costs. Due to a case backlog in the Idaho District, the case was assigned to a Federal Judge in the Eastern District of Washington. In the action, the Company seeks reimbursement for approximately $6,125,000 in indemnity and defense costs associated with the remediation, together with prejudgment interest and attorney fees and costs for the action. The Company successfully settled its claim for coverage with the Liquidation Trustee for the first layer insurer (which insurer is now in liquidation) on several of the policies at issue, resulting in a one-time payment of $827,500 to the Company last fall. This sum is not reflected in the damages which the Company seeks in this litigation. 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 Tribe's claim for damages arising from precluding the Tribe's 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. On March 21, 1994, the Federal District Judge issued an order granting the Company's motion for summary judgment on all claims except the Tribe's claim for compensation based on exclusion from its usual and accustomed fishing places, which part of the motion the District Judge denied without prejudice. On September 28, 1994, the Federal District Judge issued an Order rejecting the Second Report and Recommendation of the Magistrate and granting, in its entirety, the Company's motion for summary judgment. On November 8, 1994, the Tribe filed its Notice of Appeal with the Ninth Circuit Court of Appeals. No date for oral argument on the appeal has yet been set. 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, March 10, 1994, and other reports filed with the Commission. On October 6, 1994, the Company brought an action, Idaho Power Company, v. Monsanto Company, et al., in the district court of the fourth judicial district of the State of Idaho, against Monsanto Company, General Electric Company, Westinghouse Electric Corporation, Schlumberger Industries, Inc., McGraw-Edison Company, Asea Brown Boveri, Inc. and Cooper Industries, Inc. The Complaint alleges fraudulent misrepresentation or omission of material facts, and/or knowing failure to warn Idaho Power Company of the hazards of polychlorinated biphenyls (PCBs), in connection with the sale, service, replacement, maintenance, and/or removal of electrical equipment utilizing or contaminated with PCBs. The case has been removed to the United States District Court for the District of Idaho and is still in an early stage. Discovery has not yet commenced and no trial date has been set. 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 Name, Age and Position Five (5) Years J. W. Marshall, 56 Appointed August 18, 1989. Chairman of the Board and Chief Executive Officer L. R. Gunnoe, 59 Appointed July 12, 1990. Mr. Gunnoe President and Chief was Vice President - Distribution Operating Officer prior to July 12, 1990. Daniel K. Bowers, 47 Appointed July 10, 1986. Vice President and Treasurer J. LaMont Keen, 42 Appointed November 14, 1991. Vice President and Mr. Keen was Controller prior to Chief Financial Officer November 14, 1991. Douglas H. Jackson, 58 Appointed July 12, 1990. Vice President - Mr. Jackson was Senior Manager of Distribution Corporate Services prior to July 12, 1990. Paul L. Jauregui, 53 Appointed June 4, 1988. Vice President - Human Resources C. N. Olson, 45 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 and Distribution Engineering and Construction Manager prior to February 1, 1990. J. B. Packwood, 51 Appointed July 13, 1989. Vice President - Power Supply Robert W. Stahman, 50 Appointed July 13, 1989. Vice President, General Counsel and Secretary Harold J. Hochhalter, 59 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 1992, 1993 and 1994, cash dividends per share of common stock were $1.86. At the July 1994 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 exchanges. For years 1993 and 1994, the following table indicates the reported high and low sales price of the Company's common stock as reported by the Wall Street Journal as composite tape transactions. The Company's number of common stockholders of record at December 31, 1994 was 26,209. 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 1994 (Quarters) Common Stock, $2.50 par value: 1st 2nd 3rd 4th High $30 5/8 $27 5/8 $24 7/8 $24 1/8 Low 26 7/8 21 3/4 22 1/2 22 Dividends paid per share (cents) 46.5 46.5 46.5 46.5
ITEM 6. SELECTED FINANCIAL DATA SUMMARY OF OPERATIONS 1994 1993 1992 1991 (Thousands of Dollars) Revenues: General business $457,354 $428,658 $431,818 $409,454 Sales to other utilities 59,923 86,525 42,000 52,563 Other revenues 26,381 25,219 24,274 21,176 Total revenues 543,658 540,402 498,092 483,193 Expenses: Purchased power 60,216 45,361 58,496 51,210 Fuel expense 94,888 87,855 96,710 75,161 Other operation and 154,742 164,388 137,547 151,593 maintenance Depreciation 60,202 58,724 59,823 57,597 Taxes other than income taxes 23,945 22,129 20,562 21,168 Total expenses 393,993 378,457 373,138 356,729 Income from operations 149,665 161,945 124,954 126,464 Other income and deductions - (12,160) (12,984) (11,133) (9,453) Net Interest charges - Net 52,652 53,991 52,935 56,901 Income taxes 34,243 36,474 23,162 21,144 Cumulative effect of accruing unbilled revenues - - - - Net Income 74,930 84,464 59,990 57,872 Dividends on preferred stocks 7,398 6,009 5,516 4,904 Earnings on common stock 67,532 78,455 54,474 52,968 Dividends on common stock 69,594 67,959 65,043 63,197 Net change to retained earnings $ (2,062) $ 10,496 $(10,569) $(10,229) CAPITALIZATION (000 omitted) % % % % First mortgage bonds $490,000} 46 $490,000} 47 $485,000} 49 $435,000} 48 Other long-term debt 203,206 203,780 216,948 194,981 Mandatory redeemable preferred stock -} 9 -} 9 -} 7 -} 8 Preferred stock 132,456 132,751 107,874 108,191 Common stock (incl. prem. & 452,962} 45 439,467} 44 412,998} 44 356,824} 44 exp.) Retained earnings 220,838 222,900 212,404 222,973 Total capitalization $1,499,462 100 $1,488,898 100 $1,435,224 100 $1,317,969 100 Short-term borrowings $55,000 $4,000 $6,000 $48,500 outstanding
SUMMARY OF OPERATIONS 1990 1989 1988 1987 (Thousands of Dollars) (Cont'd) Revenues: General business $401,350 $397,974 $362,050 $343,899 Sales to other utilities 44,368 70,749 32,175 35,447 Other revenues 19,217 27,438 18,096 15,251 Total revenues 464,935 496,161 412,321 394,597 Expenses: Purchased power 43,923 43,845 43,723 30,234 Fuel expense 77,606 77,127 74,528 65,934 Other operation and 134,126 132,114 116,230 114,235 maintenance Depreciation 55,114 53,092 51,691 50,929 Taxes other than income taxes 20,752 20,213 19,301 19,072 Total expenses 331,521 326,391 305,473 280,404 Income from operations 133,414 169,770 106,848 114,193 Other income and deductions - (11,666) (10,005) (6,552) (13,115) Net Interest charges - Net 52,605 52,997 50,762 51,843 Income taxes 23,234 42,041 13,558 27,246 Cumulative effect of accruing unbilled revenues - - - (11,302) Net Income 69,241 84,737 49,080 59,521 Dividends on preferred stocks 4,279 4,285 4,293 4,298 Earnings on common stock 64,962 80,452 44,787 55,223 Dividends on common stock 63,197 62,177 61,159 61,159 Net change to retained earnings $ 1,765 $ 18,275 $(16,372) $ (5,936) CAPITALIZATION (000 omitted) % % % % First mortgage bonds $367,500} 46 $377,000} 47 $392,000} 47 $407,000} 47 Other long-term debt 194,159 165,551 164,426 160,003 Mandatory redeemable preferred stock -} 5 -} 5 -} 5 -} 5 Preferred stock 58,761 58,923 59,126 59,238 Common stock (incl. prem. & exp.) 358,078} 49 357,986} 48 357,866} 48 357,797} 48 Retained earnings 233,241 231,476 213,201 229,573 Total capitalization $1,211,739 100 $1,190,936 100 $1,186,619 100 $1,213,611 100 Short-term borrowings $48,280 $31,000 $37,000 $4,000 outstanding
SUMMARY OF OPERATIONS 1986 1985 1984 (Thousands of Dollars) (Cont'd) Revenues: General business $336,480 $336,705 $324,701 Sales to other utilities 54,987 98,980 86,724 Other revenues 17,394 15,495 16,422 Total revenues 408,861 451,180 427,847 Expenses: Purchased power 31,849 16,188 1,215 Fuel expense 31,260 81,961 50,850 Other operation and 114,407 125,728 119,604 maintenance Depreciation 49,308 45,595 40,974 Taxes other than income taxes 18,539 16,790 16,363 Total expenses 245,363 286,262 229,006 Income from operations 163,498 164,918 198,841 Other income and deductions - (17,064) (20,352) (11,191) Net Interest charges - Net 51,206 47,891 45,579 Income taxes 50,923 52,556 64,418 Cumulative effect of accruing unbilled revenues - - - Net Income 78,433 84,823 100,035 Dividends on preferred stocks 10,553 12,447 13,617 Earnings on common stock 67,880 72,376 86,418 Dividends on common stock 59,755 56,277 52,221 Net change to retained earnings $ 8,125 $ 16,099 $ 34,197 CAPITALIZATION (000 omitted) % % % First mortgage bonds $432,000} 47 $467,000} 47 $467,000} 47 Other long-term debt 153,887 149,074 138,452 Mandatory redeemable preferred stock -} 5 63,000} 9 63,000} 10 Preferred stock 59,403 60,585 61,079 Common stock (incl. prem. & exp.) 357,708} 48 355,007} 44 342,038} 43 Retained earnings 235,509 230,558 214,459 Total capitalization $1,238,507 100 $1,325,224 100 $1,286,028 100 Short-term borrowings outstanding $5,000 $ - $ -
FINANCIAL STATISTICS 1994 1993 1992 1991 Income from operations as a percent of total revenues 27.5% 30.0% 25.1% 26.2% Times interest charges earned: Before tax 3.01 3.14 2.50 2.34 After tax 2.38 2.50 2.08 1.98 Market-to-book ratio 131% 170% 159% 168% Payout ratio 103% 87% 120% 119% Return on year-end common equity 10.02% 11.84% 8.71% 9.14% Common stock data: Earnings per average share outstanding $1.80 $2.14 $1.55 $1.56 Dividends declared per share $1.86 $1.86 $1.86 $1.86 Book value per share $17.91 $17.86 $17.28 $17.07 Average shares outstanding (000 omitted) 37,499 36,675 35,116 33,977 Common shareowners 26,209 26,870 27,834 28,069 * Includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kWh (000,000 omitted) 12,194 11,406 11,606 11,266 Number of customers 330,308 317,772 307,567 297,808 Residential customer data: Number of customers 274,187 263,682 255,022 246,689 Average kWh use per customer 14,159 14,587 13,856 14,845 Average rate per kWh (cents) 4.83 4.82 4.80 4.72 OTHER STATISTICS Total assets (000 omitted) $2,191,816 $2,097,417 $1,862,307 $1,773,674 Gross plant additions (000 omitted) $107,667 $116,972 $118,920 $135,904 Number of employees (full-time) 1,609 1,654 1,638 1,626
FINANCIAL STATISTICS (Cont'd) 1990 1989 1988 1987 Income from operations as a percent of total revenues 28.7% 34.2% 25.9% 28.9% Times interest charges earned: Before tax 2.72 3.30 2.18 2.76* After tax 2.29 2.53 1.93 2.10* Market-to-book ratio 148% 169% 138% 127% Payout ratio 97% 77% 137% 111% Return on year-end common equity 10.99% 13.65% 7.84% 9.40% Common stock data: Earnings per average share outstanding $1.91 $2.37 $1.32 $1.63* Dividends declared per share $1.86 $1.83 $1.80 $1.80 Book value per share $17.40 $17.35 $16.81 $17.29 Average shares outstanding 000 omitted) 33,977 33,977 33,977 33,977 Common shareowners 29,080 30,291 32,225 33,733 * Includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kWh (000,000 omitted) 11,086 11,069 10,563 10,175 Number of customers 291,800 284,363 279,529 276,249 Residential customer data: Number of customers 241,790 236,008 232,650 230,486 Average kWh use per customer 14,281 14,923 14,364 13,785 Average rate per kWh (cents) 4.73 4.69 4.47 4.34 OTHER STATISTICS Total assets (000 omitted) $1,680,110 $1,625,120 $1,608,935 $1,602,311 Gross plant additions (000 omitted) $80,117 $62,094 $64,358 $38,929 Number of employees (full-time) 1,574 1,528 1,500 1,521
FINANCIAL STATISTICS (Cont'd) 1986 1985 1984 Income from operations as a percent of total revenues 40.0% 36.6% 46.5% Times interest charges earned: Before tax 3.40 3.61 4.12 After tax 2.46 2.61 2.90 Market-to-book ratio 150% 133% 114% Payout ratio 88% 78% 60% Return on year-end common equity 11.44% 12.36% 15.53% Common stock data: Earnings per average share outstanding $2.00 $2.16 $2.63 Dividends declared per share $1.76 $1.68 $1.59 Book value per share $17.46 $17.29 $16.74 Average shares outstanding (000 omitted) 33,961 33,544 32,893 Common shareowners 34,456 35,959 35,216 * Includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kWh (000,000 omitted) 9,938 10,366 10,191 Number of customers 274,129 272,155 268,974 Residential customer data: Number of customers 228,921 227,562 225,319 Average kWh use per customer 14,541 15,432 15,342 Average rate per kWh (cents) 4.21 3.98 4.01 OTHER STATISTICS Total assets (000 omitted) $1,621,887 $1,646,847 $1,584,874 Gross plant additions (000 omitted) $50,257 $74,064 $99,028 Number of employees (full-time) 1,524 1,568 1,725
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Idaho Power Company's consolidated financial statements represent the Company and its five wholly-owned subsidiaries: Idaho Energy Resources Company (IERCo); Ida-West Energy Company (Ida-West); IDACORP, Inc.; Idaho Utility Products Company (IUPCo); and Stellar Dynamics. This discussion uses the terms Idaho Power and the Company interchangeably to refer to Idaho Power Company and its subsidiaries. EARNINGS PER SHARE AND BOOK VALUE Two factors affected earnings per share in 1994. First, drought conditions returned to the Company's service area. These conditions have hampered the Company's hydroelectric operations six of the last eight years. Second, the Company entered into an agreement with a midwest utility regarding a substitution emission allowance exchange. This agreement resulted in a $2.5 million one-time addition to pretax income. Earnings per share of common stock were $1.80 in 1994, down from $2.14 in 1993, a year of improved precipitation and streamflows. However, the 1994 earnings per share are an increase over 1992's drought-affected $1.55. The 1994 earnings equate to a 10.0 percent earned return on year-end common equity, as compared to the 11.8 percent earned in 1993 and the 8.7 percent earned in 1992. At December 31, 1994, the book value per share of common stock was $17.91. RESULTS OF OPERATIONS Energy Demand and Customer Growth A prolonged period of high temperatures sparked sharp increases in energy demand during the summer of 1994. Southwestern Idaho and southeastern Oregon--the most densely populated area of the Company's service territory--experienced a record 44 consecutive days with temperatures of at least 90 degrees. On June 23, 1994, the Company set a new record for system peak load at 2,392 megawatts (MW). The Company's growth in new customers this year broke a record of its own. By December 31, 1994, Idaho Power had connected 12,536 new general business customers to its system, far outpacing the previous record of 11,563 set in 1978. By customer class, the Company added 10,505 residential customers, 1,548 commercial and industrial customers, and 483 irrigation customers. Economy The Company's service territory posted another outstanding year of economic growth in 1994. Idaho's nonagricultural employment grew by an estimated 4.6 percent, following gains of 5.0 percent in 1993 and 4.6 percent in 1992. Across the entire service territory, nonagricultural employment showed an estimated gain of nearly 4.6 percent for 1994, building on gains of 4.9 percent in 1993 and 3.5 percent in 1992. Population growth remains strong in the Company's service area. The number of residential customers grew by 3.4 percent in both 1992 and 1993, and by 4.0 percent in 1994. Over the next five years, the Company projects that the number of new households in its service area will grow by an average rate of 3.0 percent per year, while population growth over the same period will exceed 2.2 percent. Revenues For the three-year period 1992-1994, the Company received an average 86 percent of its operating revenues from electric sales in Idaho, 5 percent in Oregon, less than 1 percent in Nevada, and 9 percent from the wholesale market. For the same three-year period, the average percentages of total operating revenues by category were as follows: - - 34 percent from residential customers; - - 30 percent from a combination of irrigation customers, street lighting customers, and commercial and industrial customers with less than 750 kW demand; - - 19 percent from commercial and industrial customers with demand of 750 kW or greater; - - 12 percent from sales to other utilities and interchange arrangements; - - 5 percent miscellaneous revenue. The Company's energy sales to general business customers rose 3.0 percent in 1992, fell 1.7 percent in 1993, then increased 6.9 percent in 1994. The sales increases in 1992 and 1994 reflect the strong economic growth in Idaho Power's service territory, increases in new customers served, and varied temperature, streamflow, and energy usage patterns. The decline in 1993 can be traced to two factors: (1) wet spring weather that reduced irrigation kilowatt-hour sales by 28.8 percent; and (2) temporary operational changes made by two of the Company's large industrial customers that lowered energy consumption. FMC Corporation periodically curtailed 1993 operations at its elemental phosphorous production plant in response to market conditions for its product. Also, the Idaho National Engineering Laboratory (INEL) reduced its 1993 electrical usage. Both FMC and INEL returned to a higher level of operation during 1994. Record growth in new customers contributed to the 1994 increase in energy sales. In addition, a long, hot, dry summer boosted the Company's irrigation load by 34.5 percent. General business revenues constitute approximately 83 percent of the Company's total operating revenues. For 1992, general business revenues were $431.8 million, for 1993 $428.7 million, and for 1994 $457.4 million. The decrease in 1993 is a result of that year's wet spring, which reduced irrigation revenues by 27.9 percent. The decrease was partially offset by increases in residential revenues (9.3 percent) and small commercial revenues (4.0 percent). The 1994 increase reflects above-normal summer temperatures that increased irrigation revenues by 33.2 percent, or $16.2 million. The number of general business customers served increased by 32,500, or 10.9 percent during the three-year period. Energy usage per average residential customer was 13,856 kilowatt hours (kWh) in 1992, 14,587 kWh in 1993, and 14,159 kWh in 1994. Total operating revenues increased by $14.9 million (3.1 percent) in 1992, $42.3 million (8.5 percent) in 1993, and $3.3 million (0.6 percent) in 1994. Increased opportunity sales to other utilities created the 1993 increase in total operating revenue. Customer growth, coupled with above-normal summer temperatures, accounted for the 1994 increase. However, the increase was offset by a decline in opportunity sales caused by reduced streamflows. Off-System Sales Revenues from sales to other utilities fell $10.6 million in 1992, rose $44.5 million in 1993, and decreased by $26.6 million in 1994. These are composed of firm sales (long-term contractual agreements) and opportunity sales made on a when-available basis. The volume and price of these sales depend on the Company's firm energy demand, hydroelectric generation conditions in its service territory, and market conditions throughout the West. Revenues from firm sales to other utilities were $37.5 million in 1992, $45.4 million in 1993, and $53.6 million in 1994. Revenues from opportunity sales to other utilities were $4.5 million in 1992, $41.1 million in 1993, and $6.3 million in 1994. Drought conditions reduced opportunity sales in 1992 and 1994, while the return to more normal hydro conditions in 1993 increased the volume of sales and revenue dramatically. Expenses Total operating expenses grew $16.4 million in 1992, $5.3 million in 1993, and $15.5 million in 1994. The added expense for 1992 and 1994 are a result of drought conditions that elevated the Company's reliance on thermal generation and purchased power. The 1993 rise in operating expenses reflects the deferral of certain 1992 drought-related net power supply costs to 1993 authorized by the Idaho Public Utilities Commission (IPUC). Maintenance expense also increased in 1993 with that year's return to improved hydroelectric operating conditions. Purchased power expenses have been high and fluctuating during the last three years. This situation reflects both necessity purchases from neighboring utilities during drought periods and increased 1993 purchases from cogeneration and small power production (CSPP) projects as a result of improved hydro conditions. The current estimated annualized cost for the 62 CSPP projects on-line at December 31, 1994 is $40.7 million. The Company relies on its thermal generation facilities to operate at high-capacity factors during periods of drought. Increased thermal generation raised fuel expenses by $21.5 million in 1992 and $7.0 million in 1994. In 1993, fuel expenses declined by $8.9 million as a direct result of the increased availability of hydro generation to meet customer demand. All other operation and maintenance expenses fluctuated during the three-year period, with a cumulative increase of $3.1 million. These variations are due, in part, to increases in payroll and benefits, and changes in operation and maintenance due to drought conditions. Depreciation expense was up for the three-year period by $2.6 million, or 4.5 percent, due to a greater plant investment base. Taxes other than income taxes grew $2.8 million, or 13.1 percent, as a result of additional property taxes and taxes on the increased generation and sale of hydroelectric power. Interest Charges Interest charges on long-term debt fluctuated during the three- year period. Ultimately, they were down by $3.2 million, reflecting the maturity, early redemption, and issuance of several series of first mortgage bonds. The Company took advantage of declining interest rates to refinance several higher- cost bond issues. These refinancings reduced the overall cost of debt and annual interest expense by an amount that largely offset the cost of additional financing (see Note 5 of Notes to Consolidated Financial Statements). Interest on short-term debt rose due to varying interest rates during the period, as well as to a larger level of short-term borrowings. At December 31, 1994, the Company's short-term borrowings were $55.0 million (see Note 7 of Notes to Consolidated Financial Statements). Income Taxes In August 1993, Congress enacted the Omnibus Budget Reconciliation Act. Among other things, the Act raised 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 higher rate. Also in 1993, the Company settled with the Internal Revenue Service (IRS) federal income tax liabilities for the 1987-1990 tax years and in 1994 the Company settled federal income tax liabilities for the 1991-1992 tax years, except for immaterial amounts relating to a partnership. Precipitation and Streamflows After experiencing an above-average water year in 1993, Idaho Power's service territory experienced below-normal precipitation and above-normal temperatures throughout much of 1994. Between April and July, the Company recorded 2.75 million acre feet (MAF) of water flowing into Brownlee Reservoir (water source for the three-dam Hells Canyon hydroelectric complex). This figure is 46 percent of 1993's 6.0 MAF, 153 percent of 1992's 1.8 MAF, and 57 percent of the 66-year median of 4.8 MAF. The early indications for l995 are somewhat better. As of February 1, l995, reservoir storage above Brownlee Reservoir was at 37 percent of capacity. However, the average snow water equivalent for the Snake River above Brownlee Reservoir was at 114 percent of the 30-year average, compared to 56 percent of the average at this time last year. Based on current hydrologic conditions and projected meteorological conditions, the Company estimates that approximately 4.5 MAF of water will flow into Brownlee Reservoir between April and July 1995. If the estimate holds true, it would be a 64 percent increase over 1994's streamflow, but still 6 percent below the 66-year median inflow. Energy Requirements With drought conditions returning in 1994, hydroelectric generation accounted for only 40 percent of the Company's total energy requirements. This figure is a substantial decrease from 52 percent in 1993, but higher than 1992's 35 percent. Thermal generation accounted for 46 percent of total energy requirements in 1994, while purchased power and other exchanges supplied 14 percent. Under normal conditions, the Company's hydro system supplies approximately 58 percent of its total energy requirements, with thermal generation accounting for 33 percent and purchased power and other interchanges contributing the remaining 9 percent. The Company expects to meet l995's projected energy loads by using its hydro and coal-fired facilities and strategic geographic location-which presents excellent opportunities to purchase, sell, exchange, and transmit Northwest energy-even if stream flow conditions are below normal. Regulatory Issues Power Cost Adjustment (PCA) Since 1993, the Company's PCA mechanism has allowed it to collect, or to refund, the differences between actual net power supply costs and those allowed in the Company's Idaho base rates. Deviations from forecasted costs are deferred with interest and trued up the following year. The Company filed its 1994 PCA application with the IPUC on April 15, 1994, requesting an increase in base rates for the Idaho jurisdiction. The increase (in effect from May 16, 1994 through May 15, 1995) was approximately $9.8 million, or 2.5 percent including last year's true-up. At December 31, 1994, the Company had recorded $8.6 million of power supply costs above those projected in the 1994 forecast. This cumulative amount will be requested to be included in the 1995 true-up adjustment. With the IPUC's revenue requirement order on February 1, 1995, the PCA mechanism increased to a 90 percent recovery level from its original 60 percent. General Revenue Requirement Case On June 30, 1994, the Company filed its application based upon calendar year 1993, using a thirteen month average rate base (annualized for its new Swan Falls production project) and a year end capitalization structure. The IPUC conducted ten days of hearings commencing on October 10 and December 12, 1994. Public hearings were also held in Pocatello, Idaho on December 5 and in Caldwell, Idaho on December 7, 1994. Throughout the proceeding, including the interim rate hearing, documentary and oral evidence was presented by a number of parties. On January 31, 1995, the Company received IPUC Order No. 25880 authorizing $17.2 million in general rate relief from the IPUC representing a 4.2 percent overall increase in Idaho retail rates. The relief is based on an 11.0 percent allowed return on equity with an overall rate of return of 9.199 percent. The Company had requested $37.1 million in general rate relief representing a 9.09 percent increase in rates, a 12.50 percent return on equity, and a 9.88 percent overall rate of return. These increased rates are effective February 1, 1995. The Company is disappointed with the allowed return on common equity granted in the Order and believes it does not adequately reflect today's financial conditions and the returns investors expect to receive on their investment. An allowed return on common equity of 11.0 percent only marginally exceeds the Company's dividend payout ratio of 10.4 percent on year-end book value. This makes it difficult for the Company to meet dividend requirements because of the implied constraint the return allowed places on the Company's earnings potential. The Company has petitioned the IPUC for reconsideration of its decision with regard to the allowed return on common equity seeking an authorized return on common equity which, if earned, would be sufficient to safely cover the current dividend. However, the Company cannot predict the final outcome of this request for reconsideration. The Company will file a general revenue requirement case in Oregon in early l995. This filing will utilize the same information used in the 1994 filing in Idaho. Cogeneration and Small Power Production Contracts In September 1993, the Company submitted a detailed position paper to its state regulators and other interested parties. This report outlined proposed changes in the Company' s resource acquisition policy. With the potential deregulation of the electric utility industry, and a more competitive power supply marketplace, the Company believes that current resource acquisition policies must be changed to avoid burdening it and its customers with unnecessary future power supply costs. Idaho Power believes that the appropriate criteria for adding future supplies should be power needs at the time of development and that the addition be the least-cost market alternative. Therefore, in December 1993 the Company filed with the IPUC for permission to approve lower published prices for new CSPP contracts. In response to the Company's filing, on January 31, 1995 the IPUC issued an order approving lower published CSPP rates. In the order, the IPUC also determined that negotiated rates for future CSPP projects larger than 1 megawatt should be more closely tied to values determined in the Company's integrated resource planning (IRP) process. In its January 31, l995 order, the IPUC stated, "There is a widely held expectation that there will be increasing competition within the electric utility industry. In light of that, we believe it is especially important that the QF [Qualified Facilities] industry be able to demonstrate that the energy resources offers are as cost effective as those that a utility would construct." Rosebud Enterprises, Inc. (Rosebud) filed a Complaint against the Company with the IPUC, alleging that the Company refused to sign a contract to purchase the output of a 40 MW petroleum waste- fired generating plant that Rosebud proposes to build near Mountain Home, Idaho. Because this facility, known as the Mountain Home Project, was larger than l0 MW, the IPUC's established rates for small CSPP projects were not available to Rosebud. On September 16, 1994, the IPUC issued an order directing the Company to recalculate and offer avoided cost rates as described in the order. In October 1994, the Company transmitted a purchase offer to Rosebud conforming to the IPUC's final order. Rosebud rejected that purchase offer and has appealed the IPUC's final order to the Idaho Supreme Court. Oregon Drought Rate Relief The Company's PCA mechanism applies only to its Idaho jurisdiction. As a result of 1994's high power supply costs, the Company also filed for temporary drought rate relief with the Oregon Public Utility Commission (OPUC). The OPUC issued an accounting order that granted the Company permission to defer with interest 60 percent of Oregon's share of the Company's increased power supply costs incurred between May 13, 1994 and December 31, 1994. The amount deferred at December 31, 1994 was $1.3 million. The Company is required to file a request with the OPUC in early 1995 to recover these deferred costs. Subsidiaries Ida-West Energy Company This wholly-owned subsidiary of the Company owns, through various partnerships, 50 percent of five Idaho hydroelectric projects with a total generating capacity of approximately 34 megawatts (MW). Third parties unaffiliated with Ida-West own the remaining 50 percent of these projects, thus satisfying the "qualifying facility" status under PURPA guidelines. The partnerships have obtained project financing (non-recourse to the Company) for each of these facilities. As a 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 MW gas-fired cogeneration project to be located near Hermiston, Oregon. On June 4, 1993, BPA selected three projects--including that of the partnership--for participation in the program. The partnership and BPA signed an option development agreement granting BPA an option to acquire energy and capacity from the project any time during a five-year option hold period after all option development period tasks, including permitting, have been completed. The option also entitles the partnership to BPA reimbursement for certain development costs, based on the achievement of certain milestones. This option includes an exclusive right to acquire energy and capacity from a second 233 MW unit at the site during the same five-year option hold period. In March 1994, BPA and the partnership reached an additional agreement on the power purchase contract, setting forth the terms and conditions on which BPA will purchase energy and capacity from the project upon exercise of the option. The partnership expects to complete development period tasks by the end of l995. Project financing for construction costs would be non-recourse to the Company. The Company has invested $20 million in Ida-West. Ida-West continues an active search for new projects. Stellar Dynamics In 1994, Idaho Power announced the formation of a fifth subsidiary company. Stellar Dynamics will commercialize the Company's extensive expertise in control technology for electric substations and power plants. The Company approved the new venture after receiving a positive recommendation from Newton- Evans Research Company. The recommendation, based on a market survey conducted by Newton-Evans, was backed by strong interest from potential customers. One-third of the companies surveyed, including several large investor-owned utilities, requested product information. The primary opportunity for Stellar Dynamics' design, consulting, installation, and troubleshooting services lies in the U.S. substation controls market. The Company expects to capitalize Stellar Dynamics in early 1995. LIQUIDITY AND CAPITAL RESOURCES Cash Flow Net cash generation from operations totaled $377.3 million for the three-year period 1992-1994. After deducting common and preferred dividends of $221.7 million, net cash generation from operations provided approximately $155.6 million for the Company's construction program and other capital requirements. Internal cash generation after dividends provided 30 percent of total capital requirements in 1992, 54 percent in 1993, and 41 percent in 1994. Idaho Power expects to continue financing its construction program with both internally generated funds and, to the extent necessary, externally financed capital. Drought conditions hurt the Company's internal cash generation two of the last three years. The Company has first mortgage bond refundings of $20.0 million in 1996 and $30.0 million in 1998. At January 1, 1995, the Company's lines of credit maintained with various banks totaled $70.0 million. The total lines of credit maintained with various banks will increase to $90.0 million at March 1, l995 (see Note 7 of Notes to Consolidated Financial Statements). Construction Program The Company's consolidated cash construction expenditures were $118.0 million in 1992, $122.9 million in 1993, and $110.5 million in 1994. Approximately 42 percent of these expenditures were for generation facilities, 8 percent for transmission facilities, 38 percent for distribution facilities, and 12 percent for general plant and equipment. After completion of the Swan Falls and Twin Falls projects, the Company does not anticipate any new major generation construction projects. Swan Falls Project In early spring of 1994, the Company completed testing of the Swan Falls Project and both units were declared available for commercial operation. At December 31, 1994, the Company had spent approximately $55.0 million for construction of the Swan Falls Project, including allowance for funds used during construction. Additional work to preserve the old power plant as an historical site began during the year, while work to establish a museum on the site is scheduled for completion in 1995. In May, crews completed the federally-mandated stabilization of the dam and began the environmental reclamation of approximately 18 acres of land affected by construction activities. Twin Falls Project Expansion of the Twin Falls Project recently passed the halfway point, with completion estimated for mid-1995. 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. Revised total cash expenditures for the Twin Falls expansion are currently estimated at $38.1 million, with total construction costs at $41.9 million, including an allowance for funds used during construction. At December 31, 1994, the Company had spent approximately $29.4 million on the Twin Falls Project. When completed, it will add 43 MW of new capacity to the Company's generation system. Southwest Intertie Project (SWIP) Idaho Power is continuing to study the economic feasibility of constructing the SWIP to capitalize on its strategic location between the Intermountain West and the Pacific Northwest. The SWIP would serve as a major north-south transmission artery for regional transfers of electric power. The Company's SWIP proposal calls for a 500-mile, 500 kV transmission line that would interconnect the Company's system with those of utilities in California and the Southwest. In December 1994, the U.S. Bureau of Land Management issued a favorable record of decision on the Company's environmental impact statement and granted the project a right-of-way across public lands in Idaho, Nevada, and Utah. At present, the Company is conducting financial and contractual discussions with potential partners in the project. Idaho Power intends to retain up to 20 percent of ownership and capacity in the 1,200 MW project. The SWIP may be built in segments as warranted by demand for its transmission services. Solar and Solar Photovoltaic Projects Solar Two Idaho Power is a member of a consortium supporting the upgrade of an existing solar thermal power plant near Barstow, California. The Company has committed $630,500 in direct support to improve the plant's ability to store the sun's heat and use it later to generate electricity. The Electric Power Research Institute (EPRI), of which the Company is also a member, will contribute an additional $630,500, bringing the Company's credited contribution to approximately $1.3 million. Workers have completed over one- third of the retrofitting to date. When finished, Solar Two will use 1,900 mirrors to track the sun and focus its energy on a central receiving tower. The project will use a molten-salt fluid to store and transfer the collected heat. The main benefit the Company will receive by participating in this 10 MW project, is valuable experience and knowledge in solar power plant design, construction, and operation. Mountain Home Air Force Base The U.S. Air Force retained Idaho Power to design, build, and maintain one of the nation's largest hybrid solar-powered photovoltaic (PV) systems. The $1.2 million project, completed in February 1995, provides electricity to a remote Mountain Home AFB radar training installation near Grasmere, Idaho. Under optimal solar conditions, the PV system produces a peak capacity of 80,000 watts, reducing both the need for combustion generators and the emissions they produce. Under the terms of the contract, the federal government owns the system and pays the Company a monthly maintenance fee. International Photovoltaics Conference The Company has been selected to host an international conference on the emerging global business opportunities associated with photovoltaic power applications. The Executive Conference on Strategic Photovoltaic Business opportunities for Utilities is scheduled for September 17-20, 1995 in Sun Valley, Idaho. Representatives of the utility and PV industries and government agencies will discuss how they and their organizations can plan for and shape the influence of photovoltaics in developing and changing utility markets. Photovoltaic Service Tariff (PST) The PST offers basic electric service for small loads at remote sites as an alternative to either line extensions for grid service or the use of on-site, fossil-fuel generators. In many cases, PV technology offers a cost-effective solution for both the customer and the Company. Idaho Power benefits by reducing the number of costly line extensions to serve small loads that produce little revenue. Under the PST, the customer pays a monthly fee to receive electric service from a PV system designed, installed, owned, and maintained by Idaho Power. The program, which the Company launched in January 1993, is a pilot offering with a $5,000,000 program limit and a $50,000 limit for individual systems. In 1994, the Company made significant operational and technical improvements to its PST systems based on feedback from early PV customers. Customer comments helped to identify obstacles to customer acceptance of PV systems. To date, seven systems have been installed and are operating as designed. Financing Program Capital Structure The Company's capital structure (as illustrated in Selected Financial Data) fluctuated during the three-year period, with common equity growing to 45 percent, preferred rising to 9 percent, and debt falling to 46 percent. The Company's objective is to maintain capitalization ratios of approximately 45 percent common equity, 8-10 percent preferred stock, and the balance in long-term debt. The Company's strategy for achieving this target is through the use of accumulated retained earnings and the issuance of new equity. The Company's pre-tax interest coverage ratios were 2.50 times in 1992, 3.14 times in 1993, and 3.01 times in 1994. The Company has on file a shelf registration statement for the issuance of first mortgage bonds and/or preferred stock, with an aggregate principal amount not to exceed $200.0 million. The Company's primary financial commitments at year-end 1994 were related to contracts for the Company's facility construction and maintenance program. Common Stock During the period of January 1992 through May 1994, the Company issued original issue shares of common stock for its Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan. During 1992, 1993, and 1994, common shares totaling 959,527; 898,528 and 527,296, respectively, were issued to these plans. The net proceeds from these issues were used for the Company's ongoing construction program. Preferred Stock On July 1, 1993, Idaho Power issued $25 million of serial preferred stock. The Company used the net proceeds of this issuance for its ongoing construction program. Long-Term Debt 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 of that year, the Company used the net proceeds 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 Company used the net proceeds to retire early first mortgage bonds totaling $30,000,000, plus premiums and accrued interest. Environmental Issues Salmon Recovery Plan Work continues on the development of a comprehensive and scientifically credible plan to ensure the long-term survival of anadromous fish runs on the Columbia and Lower Snake Rivers. In mid-August 1994, the federal government changed its designation of the Snake River Fall Chinook Salmon from Threatened to Endangered. The Company does not anticipate that the new designation will have any additional effects on its operations. In September 1991, the Company modified operations at its three-dam Hells Canyon Hydroelectric Complex to protect the Fall Chinook downstream during spawning and juvenile emergence. From its start, the Company's Fall Chinook program has exceeded the protection requirements for threatened species, affording the fish the same high level of protection due an endangered species. Pending completion of a final recovery plan by the National Marine Fisheries Service (NMFS), the U.S. Army Corps of Engineers and other governmental agencies operating federally-owned dams and reservoirs on the Snake and Columbia Rivers have consulted the NMFS each year regarding federal system operations. On March 28, 1994, Judge Malcolm Marsh of the U.S. District Court for the District of Oregon ordered the federal agencies to reinitiate the consultation completed for 1993 operations of the federal system. Judge Marsh concluded that the consultations and subsequent operations were "...too heavily geared towards a status quo that has allowed all forms of river activity to proceed..." at the expense of fish. On September 9, 1994, the Ninth Circuit Court of Appeals echoed Judge Marsh's decision when it found that the 1993 Strategy for Salmon proposed by the Northwest Power Planning Council (NWPPC) was in violation of the 1980 Northwest Power Planning Act. The appeals court ordered the NWPPC to focus on saving young salmon and to defer to the expertise of state, federal and tribal fisheries management agencies in developing its salmon recovery program. Pursuant to the Ninth Circuit's opinion, the NWPPC adopted amendments to its Strategy for Salmon on December 15, 1994. The amended Strategy calls for a substantial increase in water from the Snake River to aid juvenile fish in their downstream migration to the sea. The Plan requires the Bureau of Reclamation to acquire 500,000 acre-feet of additional water by 1996 and another 500,000 acre-feet by 1998 for a total of 1,000,000 acre-feet in addition to the present contribution of 427,000 acre-feet. This water is to be acquired from willing sellers and could have a material impact on the Company's power supply costs. The Plan also calls for an additional 237,000 acre-foot contribution from the Company's Brownlee Reservoir for which the Company is to be reimbursed for by the BPA. The Company expects a draft of the final Salmon Recovery Plan from the NMFS by March 1, 1995. It is possible this recovery plan could also have a material impact on the Company. The Company hopes that anadromous fish runs can be restored without placing undue hardship on either the Company or 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 U.S. District Court for the District of Idaho. The Tribe alleged that the Company's construction, operation, and maintenance of the three-dam Hells Canyon Project prevented anadromous fish from reaching their traditional spawning areas, destroyed certain fish runs, and prevented access to certain of the Tribe's usual and accustomed fishing places. These actions allegedly deprived the Nez Perce Tribe of its treaty rights to take fish from the Columbia and Snake Rivers. The Tribe is seeking compensatory and punitive damages, each in an amount to be proven at trial. Idaho Power maintains that the suit is without merit and asked the federal court to issue a summary judgment dismissing the action. The Company believes that the responsibility for concerns expressed by the Nez Perce Tribe lies with the United States. The Hells Canyon Project was licensed by the federal government, was built in accordance with federally approved plans, and is operated subject to federal regulation. The Company has complied with all governmental requirements to mitigate any effects the Project may have had on the fisheries. On January 19, 1993, the Court took the Company's motion for summary judgment under advisement. On July 30, 1993, U.S. Magistrate Judge Larry Boyle issued a Report and Recommendation to the District Judge. Judge Boyle recommended that the District Judge grant that portion of the Company's motion for summary judgment regarding the loss of fish and deny the portion of its motion dealing with the Tribe's claim to compensation for exclusion from its usual and accustomed fishing sites. On March 21, 1994, U.S. District Judge Harold L. Ryan upheld Judge Boyle's recommendation regarding fish losses and took the question of compensation for exclusion from fishing sites under advisement. On September 28, 1994, after reviewing responses and objections on that issue, Judge Ryan rejected the Tribe's claim and granted the final portion of the Company's motion for summary judgment. The Tribe has appealed Judge Ryan's decision to the Ninth Circuit Court of Appeals. No date has been set for oral argument on the appeal. Snake River Mollusk In mid-December, 1992, the U.S. Fish and Wildlife Service (USFWS) listed the Snake River Mollusk as a Threatened and Endangered Species. Since that time, the Company has included this possibility in all of its discussions regarding relicensing and new hydro development. The listing specifically mentions the impact that fluctuating water levels related to hydroelectric operations may have on the snails' habitat. While most of the hydro facilities on that reach of the Snake River are baseload facilities, some of them do provide limited load-following capability. At present, there is no certainty as to the impacts, if any, that water fluctuations caused by these facilities may have on the snails. Idaho Power intends to testify to the USFWS that there is little scientific data in this area and that the Company proposes to study these operations. While it is possible that the listing could affect how Idaho Power operates its existing hydroelectric facilities on the middle reach of the Snake River, the Company believes that such changes will be minor and will not present any undue hardship. Mountaineer In May 1993, the Company was notified that Bridger Coal Company (BCC) was a potential contributor to a Superfund site involving waste motor oil delivered to Mountaineer Refinery in Wyoming. Idaho Energy Resources Company (IERCo), a wholly-owned subsidiary of the Company, owns one-third of BCC. In November 1993, BCC agreed to be included on the list of parties potentially responsible for this site. The current estimated cleanup costs are between $2.6 million and $5.0 million. During the past year, more contributors were added to the list of potentially responsible parties for cleanup of this site. Therefore, BCC's portion of these costs, based on the amount of oil delivered to the site, is estimated now to be approximately 5.0 percent, or between $130,000 and $250,000. IERCo would be liable for one- third of the BCC portion, or between $42,900 and $82,500. In 1994 BCC recorded expenses of $129,450 of which one-third flowed through to the Company's consolidated financials. Of this amount, $42,750 remains on BCC's books as an unfunded liability at December 31, 1994. Clean Air Idaho Power has analyzed the Clean Air Act legislation's effects on the Company and its ratepayers. The Company's coal-fired plants in Oregon and Nevada already meet the federal sulfur dioxide (SO2) emission rate standards. The Company's coal-fired plant in Wyoming meets that state's even more stringent SO2 regulations. Therefore, the Company anticipates no adverse effects on its operations with regard to SO2 emissions. The Company, together with PacifiCorp and Black Hills Corporation, entered into Phase I substitution agreements with Illinois Power Company. The agreements designate Units 1, 2, 3, and 4 of the Company's Jim Bridger thermal facility and facilities owned by PacifiCorp and Black Hills Corporation as substitution units for Baldwin #2, owned by Illinois Power. The substitution agreements will allow the Company to grandfather in less restrictive Phase I nitrous oxide emission requirements at the Jim Bridger units. As part of the agreements, the Company negotiated the sale of a number of its Phase I SO2 emission allowances to Illinois Power. Electric and Magnetic Fields (EMF) While scientific research has yet to establish any conclusive link between EMF and human health, the possibility has caused public concern in the United States and abroad. Electric and magnetic fields are found wherever there is electric current, whether the source is a high-voltage transmission line or the simplest of electrical household appliances. Concerns over possible health effects have prompted regulatory efforts in several states to limit human exposure to EMF. Depending on what researchers ultimately discover and what regulations may be deemed necessary, it is possible that this issue could affect a number of industries, including electric utilities. However, at this time it is difficult to estimate what impacts, if any, the EMF issue could have on the Company and its operations. Competition and Strategic Planning Competition is increasing in the electric utility industry, due to a variety of developments. In response, the Company continues to proceed with a strategic planning process. The goal of this process is to anticipate and fully integrate into Company operations any legislative, regulatory, environmental, competitive, or technological changes. With its low energy production costs, Idaho Power is well-positioned to enter a more competitive environment and is taking action to preserve its low- cost competitive advantage (see Regulatory Issues - Cogeneration and Small Power Production Contracts for a discussion of the Company's revised resource acquisition policy). On June 3, 1994 the IPUC approved the buyout and cancellation of a January 22, 1993 Firm Energy Sales Agreement (FESA) with Meridian Generating Company, L. P. (MGC). The FESA was a 25-year agreement with MGC for a 54 MW natural gas-fired combined cycle cogeneration facility located in Meridian, Idaho. The Company estimates that the revenue requirement savings, including cancellation charges paid to MGC, are between $130 and $170 million. On June 28, 1994, Washington Water Power and Sierra Pacific Resources announced that their respective boards of directors had approved a merger agreement between the two companies. Idaho Power is intervening in the approval process to ensure that the proposed merger has no adverse effects on its operations. In addition, the Company is actively identifying and responding to business opportunities presented by the proposed merger. Internally, the Company continues its commitment to refining its business processes to ensure its ability to offer the greatest possible value to its customers and its shareowners. Among these strategic initiatives are: - - the examination and refinement of the Company's distribution function, work order, and line extension processes; - - the initiation of a four-year, $3 million project to automate and consolidate the operation of the Company's 17 hydroelectric power plants; - - the formation of a Technical Advisory Panel, composed of representatives from public and private interest groups, to advise the Company on such matters as competition, alternative resources, and conservation. The Company will use the panel's advice as it reviews its IRP, due for publication in mid 1995. - - the implementation of a Restricted Stock Plan and Employee Incentive Plan to focus employees' attention on achieving annual financial and operational goals, to promote and reinforce teamwork, and to encourage employee accountability for business results and the Company's responsiveness to a competitive environment. Relicensing of Hydroelectric Projects Idaho Power is vigorously pursuing the relicensing of its hydroelectric projects, a process that will continue for the next 10 to 15 years. The Company will submit its first applications for license renewal to the Federal Energy Regulatory Commission in December 1995. These first applications will seek renewal of the Company's licenses for its Bliss, Upper Salmon Falls, and Lower Salmon Falls Hydroelectric Projects. Although various federal requirements and issues must be resolved through the relicensing process, the Company anticipates that its efforts will be successful. At this point, however, the Company cannot predict what type of environmental or operational requirements it may face, nor can it estimate the eventual cost of relicensing. BOARD OF DIRECTORS On January 12, 1995, the Company welcomed two new members to its Board of Directors. Jack K. Lemley, 59, was Chief Executive officer of Transmanche-Ling, the Anglo-French construction firm that built the motor and rail transportation tunnel beneath the English Channel. A former senior vice president of Morrison- Knudsen Corporation, Mr. Lemley is currently President of Lemley & Associates, Inc. Peter S. O'Neill, 56, is President of Boise- based O'Neill Enterprises, Inc., a real estate development firm. Mr. O'Neill served as a senior vice president of Boise Cascade Corporation and as President of the Columbia-Willamette Development Co. Three directors retired from the board in accordance with the Company's Restated Articles of Incorporation and By-Laws. The articles and by-laws require directors to retire by age 70. Former U.S. Senator James A. McClure and retired plumbing and heating wholesaler Richard T. Norman left the board in December, the same month as their 70th birthdays. Rancher George Coiner retired at the January 12 board meeting. Mr. Coiner turns 70 in February 1995. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES PAGE Management's Responsibility for Financial Statements 58 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 1994, 1993 and 1992 59-60 Consolidated Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 61 Consolidated Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 62 Consolidated Statements of Capitalization as of December 31, 1994, 1993 and 1992 63 Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 64 Notes to Consolidated Financial Statements 65-79 Independent Auditors' Report 80 Supplemental Financial Information (Unaudited) 81 Supplemental Schedule for the Years Ended December 31, 1994, 1993 and 1992: Schedule II- Consolidated Valuation and Qualifying Accounts 90 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 systems of internal accounting controls and related policies and procedures. The systems are designed to provide reasonable assurance that all assets are protected against loss or unauthorized use. Also, the systems provide 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 LLP, 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, 1994 1993 1992 (Thousands of Dollars) ELECTRIC PLANT (Notes 1, 5 and 10): In service (at original cost) $2,383,898 $2,249,723 $2,198,747 Less accumulated provision for depreciation 775,033 728,979 683,332 In service - Net 1,608,865 1,520,744 1,515,415 Construction work in progress 46,628 92,682 66,997 Held for future use 1,150 2,958 3,083 Electric plant - Net 1,656,643 1,616,384 1,585,495 INVESTMENTS AND OTHER PROPERTY 18,034 20,772 11,411 CURRENT ASSETS: Cash and cash equivalents 7,748 8,228 4,966 Receivables: Customer 31,889 29,741 28,687 Allowance for uncollectible accounts (1,377) (1,377) (1,421) Notes 4,962 5,616 1,669 Employee notes receivable 5,444 5,909 5,970 Other 4,316 1,858 1,695 Accrued unbilled revenues (Note 1) 29,115 25,583 27,210 Materials and supplies (at average cost) 24,141 23,372 25,762 Fuel stock (at average cost) 11,310 11,553 14,282 Prepayments (Note 9) 21,398 20,975 22,171 Regulatory assets associated with income taxes (Note 1) 5,674 4,914 - Total current assets 144,620 136,372 130,991 DEFERRED DEBITS: American Falls and Milner water rights 32,605 32,755 32,890 Company-owned life insurance (Note 9) 49,510 45,294 40,228 Regulatory assets associated with income taxes (Note 1) 179,311 171,569 - Regulatory assets - other (Note 1) 67,713 35,036 - Other 43,380 39,235 61,292 Total deferred debits 372,519 323,889 134,410 TOTAL $2,191,816 $2,097,417 $1,862,307 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1994 1993 1992 (Thousands of Dollars) CAPITALIZATION (see Page 63): Common stock equity (Note 3): Common stock - $2.50 par value (shares authorized 50,000,000; shares outstanding 1994 - 37,612,351; 1993 - 37,085,055; 1992 - 36,186,527) $94,031 $92,713 $90,466 Premium on capital stock 363,063 350,882 326,338 Capital stock expense (4,132) (4,128) (3,806) Retained earnings 220,838 222,900 212,404 Total common stock equity 673,800 662,367 625,402 Preferred stock (Note 4) 132,456 132,751 107,874 Long-term debt (Note 5) 693,206 693,780 701,948 Total capitalization 1,499,462 1,488,898 1,435,224 CURRENT LIABILITIES: Long-term debt due within one year 517 466 464 Notes payable (Note 7) 55,000 4,000 6,000 Accounts payable 32,063 31,912 34,821 Taxes accrued 16,394 15,452 16,182 Interest accrued 14,755 14,920 18,287 Other 12,574 13,731 12,125 Total current liabilities 131,303 80,481 87,879 DEFERRED CREDITS: Accumulated deferred investment tax credits (Notes 1 and 2) 71,593 72,013 73,651 Accumulated deferred income taxes (Notes 1 and 2) 380,926 358,280 210,435 Regulatory liabilities associated with income taxes (Note 1) 35,090 34,968 - Regulatory liabilities - other (Note 1) 626 4,235 - Other (Note 9) 72,816 58,542 55,118 Total deferred credits 561,051 528,038 339,204 COMMITMENTS AND CONTINGENT LIABILITIES (Note 8) TOTAL $2,191,816 $2,097,417 $1,862,307 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME Year Ended December 31, 1994 1993 1992 (Thousands of Dollars) REVENUES (Note 1) $543,658 $540,402 $498,092 EXPENSES: Operation: Purchased power (Notes 8 and 10) 60,216 45,361 58,496 Fuel expense (Note 10) 94,888 87,855 96,710 Other 111,252 121,252 101,659 Maintenance 43,490 43,136 35,888 Depreciation (Note 1) 60,202 58,724 59,823 Taxes other than income taxes 23,945 22,129 20,562 Total expenses 393,993 378,457 373,138 INCOME FROM OPERATIONS 149,665 161,945 124,954 OTHER INCOME: Allowance for equity funds used during construction (Note 1) 1,680 3,060 2,400 Other - Net (Note 9) 10,480 9,924 8,733 Total other income 12,160 12,984 11,133 INTEREST CHARGES: Interest on long-term debt 51,172 53,706 53,408 Other interest (Notes 1 and 7) 3,261 2,750 2,050 Total interest charges 54,433 56,456 55,458 Allowance for borrowed funds used during construction (Note 1) (1,781) (2,465) (2,523) Net interest charges 52,652 53,991 52,935 INCOME BEFORE INCOME TAXES 109,173 120,938 83,152 INCOME TAXES (Notes 1 and 2) 34,243 36,474 23,162 NET INCOME 74,930 84,464 59,990 Dividends on preferred stock (Note 4) 7,398 6,009 5,516 EARNINGS ON COMMON STOCK $ 67,532 $ 78,455 $ 54,474 AVERAGE COMMON SHARES OUTSTANDING (000) 37,499 36,675 35,116 EARNINGS PER SHARE OF COMMON STOCK (Note 3) $ 1.80 $ 2.14 $ 1.55 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Year Ended December 31, 1994 1993 1992 (Thousands of Dollars) RETAINED EARNINGS Beginning of year $222,900 $212,404 $222,973 NET INCOME 74,930 84,464 59,990 Total 297,830 296,868 282,963 DIVIDENDS: Preferred stock (Note 4) 7,398 6,009 5,516 Common stock (per share: 1994 - 1992 - $1.86) (Note 3) 69,594 67,959 65,043 Total dividends 76,992 73,968 70,559 RETAINED EARNINGS End of year $220,838 $222,900 $212,404 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1994 % 1993 % 1992 % (Thousands of Dollars) COMMON STOCK EQUITY (Note 3): Common stock $94,031 $92,713 $90,466 Premium on capital stock 363,063 350,882 326,338 Capital stock expense (4,132) (4,128) (3,806) Retained earnings 220,838 222,900 212,404 Total common stock equity 673,800 45 662,367 44 625,402 44 PREFERRED STOCK (Note 4): 4% preferred stock 17,456 17,751 17,874 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 25,000 - Total preferred stock 132,456 9 132,751 9 107,874 7 LONG-TERM DEBT (Note 5): First mortgage bonds: 5 1/4% Series due 1996 20,000 20,000 20,000 6 1/8% Series due 1996 - - 30,000 5.33 % Series due 1998 30,000 30,000 - 8.65 % Series due 2000 80,000 80,000 80,000 7 3/4% Series due 2002 - - 30,000 6.40 % Series due 2003 80,000 80,000 - 8 3/8% Series due 2004 - - 35,000 8 % Series due 2004 50,000 50,000 50,000 8 1/2% Series due 2006 - - 30,000 9 % Series due 2008 - - 60,000 9.50 % Series due 2021 75,000 75,000 75,000 7.50 % Series due 2023 80,000 80,000 - 8 3/4% Series due 2027 50,000 50,000 50,000 9.52 % Series due 2031 25,000 25,000 25,000 Total first mortgage bonds 490,000 490,000 485,000 Amount due within one year - - - Net first mortgage bonds 490,000 490,000 485,000 Pollution control revenue bonds: 5.90 % Series due 2003 24,650* 25,050* 25,450* 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 170,910 171,310 171,710 *Amount due within one year (450) (400) (400) Net pollution control revenue bonds 170,460 170,910 171,310 Project financing - Ida-West - - 11,243 REA notes 1,768 1,834 1,899 Amount due within one year (67) (66) (64) Net REA notes 1,701 1,768 1,835 American Falls bond guarantee 20,905 21,055 21,190 Milner Dam note guarantee 11,700 11,700 11,700 Unamortized premium/ discount-Net (Note 1) (1,560) (1,653) (330) Total long-term debt 693,206 46 693,780 47 701,948 49 TOTAL CAPITALIZATION $1,499,462 100 $1,488,898 100 $1,435,224 100 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 1994 1993 1992 (Thousands of Dollars) OPERATING ACTIVITIES: Cash received from operations: Retail revenues $ 457,202 $ 434,625 $ 432,594 Wholesale revenues 62,110 84,726 42,541 Other revenues 23,711 23,411 25,531 Fuel paid (94,530) (83,885) (96,839) Purchased power paid (62,592) (50,246) (55,976) Other operation & maintenance paid (171,774) (162,014) (145,518) Interest paid (incl long and short-term debt only) (52,376) (56,348) (52,310) Income taxes paid (16,518) (32,512) (14,859) Taxes other than income taxes paid (21,698) (22,165) (21,399) Other operating cash receipts and payments - Net 2,122 8,213 (5,917) Net cash provided by operating activities 125,657 143,805 107,848 FINANCING ACTIVITIES: First mortgage bonds issued - 188,136 98,870 PC bond fund requisitions/other long- - 5,594 9,583 term debt Common stock issued 13,402 26,781 56,223 Preferred stock issued - 24,781 - Short-term borrowings - Net 51,000 (2,140) (42,500) Long-term debt retirement (466) (191,878) (52,346) Preferred stock retirement (166) (65) (270) Dividends on preferred stock (7,565) (5,914) (5,620) Dividends on common stock (69,594) (67,959) (65,043) Net cash - financing activities (13,389) (22,664) (1,103) INVESTING ACTIVITIES: Additions to utility plant (110,523) (122,949) (118,048) Conservation (6,830) (6,687) (5,287) Other 4,605 11,757 14,327 Net cash - investing activities (112,748) (117,879) (109,008) Change in cash and cash equivalents (480) 3,262 (2,263) Cash and cash equivalents beginning of year 8,228 4,966 7,229 Cash and cash equivalents end of year $7,748 $8,228 $4,966 RECONCILIATION OF NET INCOME TO NET CASH PROVIDED BY OPERATING ACTIVITIES: Net income $74,930 $84,464 $59,990 Adjustments to reconcile net income to net cash: CSPP-Net amortization/(deferral) - (518) (3,587) Depreciation 60,202 58,724 59,823 Deferred income taxes 13,866 6,690 8,179 Investment tax credit - Net (1,064) (1,583) (1,439) Allowance for funds used during construction (3,461) (5,525) (4,923) Postretirement benefits funding (excl pensions) (5,182) (7,481) (11,369) Changes in operating assets and liabilities: Accounts receivable (635) 2,360 2,574 Fuel inventory 358 3,970 (129) Accounts payable (2,376) (4,367) 6,107 Taxes payable 7,296 (1,141) 779 Interest payable 1,656 (1,010) 2,841 Other - Net (19,933) 9,222 (10,998) Net cash provided by operating activities $ 125,657 $ 143,805 $107,848 The accompanying notes are an integral part of these statements.
IDAHO POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL 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., Ida-West Energy Company (Ida-West) and Stellar Dynamics. 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 (FERC) 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 FERC, the Company's weighted average monthly AFDC rates for 1994, 1993 and 1992 were 8.2 percent, 9.6 percent and 8.7 percent, 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 March 29, 1993, the Idaho Public Utilities Commission (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. On January 31, 1994, the Company received an IPUC order authorizing $17.2 million in general rate relief from the IPUC representing a 4.2 percent overall increase in Idaho retail rates. The relief is based on an 11.0 percent allowed return on equity with an overall rate of return of 9.199 percent. The Company had requested $37.1 million in general rate relief representing a 9.09 percent increase in rates, a 12.50 percent return on equity, and a 9.88 percent overall rate of return. These increased rates are effective February 1, 1995. In addition in May 1994, the Company filed for temporary drought rate relief with the Oregon Public Utility Commission (OPUC). The OPUC issued an accounting order that granted the Company permission to defer with interest 60 percent of Oregon's share in the Company's increased power supply costs incurred between May 13, 1994 and December 31, 1994. After the close of 1994, the Company is required to file with the OPUC for an amortization proposal for the $1.3 million deferral. 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 extension 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 2.93 percent in 1994, 2.92 percent in 1993 and 2.91 percent in 1992 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 Statement of Financial Accounting Standards (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 earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties and credits earned on non-regulated assets or investments are recognized in the year earned. 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. REGULATION OF UTILITY OPERATIONS - The Company follows SFAS No 71, "Accounting for the Effects of Certain Types of Regulation", and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating the Company. Pursuant to SFAS 71 the Company capitalizes, as deferred regulatory assets, incurred costs which are expected to be recovered in future utility rates. The Company also records as deferred regulatory liabilities the current recovery in utility rates of costs which are expected to be paid in the future. The following is a breakdown of regulatory assets and liabilities for the years 1994 and 1993 (in millions of dollars): 1994 1993 Millions of Dollars Assets Liabilities Assets Liabilities Income Taxes $185.0 $35.1 $176.5 $35.0 Conservation 29.7 21.2 Postretirement Benefits 5.5 3.5 Postemployment Benefits 4.0 3.9 Other 28.5 0.6 6.4 4.2 Total $252.7 $35.7 $211.5 $39.2 The regulatory environment is becoming more complex resulting from the expanding effects of competition. In the event that recovery of cost through rates becomes unlikely or uncertain, this would force the Company away from the cost of service ratemaking and SFAS 71 would no longer apply. If the Company were to discontinue application of SFAS 71 for some or all of its operations then these items would represent stranded investments. Certain regulators are currently reviewing ways to allow the electric utilities to recover these investments in the event the customers are allowed to choose their energy supplier. However, if the Company was not allowed recovery of its stranded investments it would be required to write off the applicable portion of regulatory assets and the financial effects could be significant. OTHER ACCOUNTING POLICIES _ Debt discount, expense and premium are being amortized over the terms of the respective debt issues. 2. INCOME TAXES: A reconciliation between the statutory federal income tax rate and the effective rate for the years 1994, 1993 and 1992 is as follows: 1994 1993 1992 Amount Rates Amount Rates Amount Rates (Thousands of Dollars) Computed income taxes based on statutory federal income tax rate $38,210 35.0% $42,328 35.0% $28,272 34.0% Change in taxes resulting from: AFUDC (1,211) (1.1) (1,798) (1.5) (1,508) (1.8) Investment tax credits (3,351) (3.1) (2,898) (2.4) (3,446) (4.1) Repair allowance (1,575) (1.4) (2,975) (2.5) (2,278) (2.7) Elimination of amounts provided in prior years (2,607) (2.4) (4,686) (3.9) (1,601) (1.9) Current state income taxes 1,496 1.4 2,693 2.2 973 1.2 Depreciation 2,812 2.6 4,116 3.4 1,738 2.1 Other 469 0.4 (306) (0.1) 1,012 1.1 Total provision for federal and state income taxes $34,243 31.4% $36,474 30.2% $23,162 27.9% The provision for income taxes consists of the following: Income taxes currently payable: Federal $20,016 $27,199 $16,366 State 1,425 4,168 56 Total 21,441 31,367 16,422 Income taxes deferred - Net of amortization: Federal 12,196 6,621 7,688 State 1,670 69 491 Total 13,866 6,690 8,179 Investment and other tax credits: Deferred 1,643 1,315 2,007 Restored (2,707) (2,898) (3,446) Total (1,064) (1,583) (1,439) Total provision for income taxes $34,243 $36,474 $23,162 The provision for deferred income taxes consists of the following: Deferred: Excess of tax over book depreciation normalized $12,813 $14,044 $12,474 Other 11,310 6,384 6,743 Total 24,123 20,428 19,217 Restored (10,257) (13,738) (11,038) Total $13,866 $6,690 $8,179 During 1993, the Company settled federal tax liabilities on all open years through the 1990 tax year; in 1994, it settled federal tax liabilities on the 1991 and 1992 tax years and settled Idaho tax liabilities on the 1987-1992 tax years except for immaterial amounts that relate to a partnership. 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, 1994, the Company has recorded regulatory assets of $185.0 million and regulatory liabilities in the amount of $35.1 million which were offset by an equal amount of accumulated deferred income tax. 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. 3. COMMON STOCK: Changes in shares of the common stock of the Company for 1994, 1993 and 1992 were as follows: Common Stock Premium on $2.50 Capital Shares Par Stock Value (Thousands of Dollars) 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 Gain on reacquired 4% preferred stock (Note 4) - - 126 Stock purchase plans 527,296 1,318 12,055 Balance at December 31, 1994 37,612,351 $94,031 $363,063 During the period of January 1992 through May 1994, the Company issued original issue shares of common stock for its Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan. During 1992, 1993, and 1994 common shares totaling 959,527; 898,528; and 527,296 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, 1994, the Company had 2,791,321 of its authorized but unissued shares of common stock reserved for future issuance under its Dividend Reinvestment and Stock Purchase Plan and Employee Savings 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. A restricted stock plan approved by shareholders at the May 1994 Annual Meeting was implemented January 1, 1995 as an equity-based long-term incentive plan. 4. PREFERRED STOCK: The number of shares of preferred stock outstanding at December 31, 1994, 1993 and 1992 were as follows: Shares Outstanding at December 31 Call Price 1994 1993 1992 Per Share Preferred stock: Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 174,556 177,506 178,735 $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) 250,000 250,000 - $103.535 to $100.354 Auction rate preferred stock, $100,000 stated value, (authorized 500 shares)(c) 500 500 500 $100,000.0 0 Total 825,056 828,006 579,235 (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, 1994 was 5.16% and ranged between 2.55% and 5.16% during the year. During 1994, 1993 and 1992 the Company reacquired and retired 2,950; 1,229 and 3,178 shares of 4% preferred stock resulting in a net addition to premium on capital stock of $126,066; $50,151 and $151,891, respectively. As of December 31, 1994 the overall effective cost of all outstanding preferred stock was 6.55 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. 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 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 only first mortgage bonds maturing during the five-year period ending 1999 are $20,000,000 in 1996 and $30,000,000 in 1998. Sinking fund requirements for the first mortgage bonds outstanding at December 31, 1994 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 1992, 1993 and 1994, $350,000, $400,000, 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 1999 for pollution control bonds outstanding at December 31, 1994 are $450,000 in 1995 and 1996, and $500,000 in 1997, 1998 and in 1999. As of December 31, 1993 and 1994, the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 8.02 percent and 8.33 percent in 1992. 6. 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, $762,575,000 for 1993, and $682,647,000 for 1994. The estimated fair values for long-term debt are based upon quoted market prices of the same or similar issues. 7. NOTES PAYABLE: At January 1, 1995, 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. The total lines of credit maintained with various banks will increase to $90,000,000 at March 1, 1995. Under annual borrowing arrangements with these banks, the Company is required to pay a fee of 1/10 of 1 percent on the available and committed lines of credit. Commercial paper may be issued in an amount not to exceed 25 percent 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, 1994 1993 1992 (Thousands of Dollars) Balance at end of year $55,000 $4,000 $6,000 Effective annual interest rate at end of year 6.1% 6.9%(a) 5.9% (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%. 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 $9,500,000 at December 31, 1994. The commitments are generally revocable by the Company subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges. The Company is currently purchasing energy from 62 on-line cogeneration and small power production facilities with contracts ranging from 1 to 33 years. Under these contracts the Company could be required to purchase up to 692,000 (MWH) annually. During the fiscal year ended December 31, 1994, the Company purchased 543,000 (MWH) at a cost of $30.9 million. 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: Incentive Plan - The Company implemented two annual incentive plans and a long-term incentive plan effective January 1, 1995. The Executive Annual Incentive Plan and the Employee Incentive Plan tie a portion of each employee's compensation to achieving annual operational and financial goals. The plans share common goals designed to promote safety, control capital expenditures, control operation and maintenance expenses and increase annual earnings per share. Restricted Stock Plan - The 1994 Restricted Stock Plan ("Plan") approved by shareholders at the May 1994 Annual Meeting was implemented January 1, 1995 as an equity-based long-term incentive plan. The performance-based grant approach and administrative guidelines for the Plan were developed by the Compensation Committee of the Board of Directors ("Committee") during 1994. The first grant under the Plan was made to all officers during January 1995. For the first grant, the Committee has selected a three-year restricted period beginning January 1, 1995, through December 31, 1997, with a single financial performance goal of Cumulative Earnings Per Share ("CEPS"). To receive a final share award, each officer must be employed by the Company, as an officer, during the entire restricted period, and the Company must achieve the CEPS performance goal established by the Committee. 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 $5.5 million in 1994, $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 supplemental retirement and death benefit payments to the participant and his or her family. The plan is being financed by life insurance policies, of which the Company is the beneficiary, with premiums being paid by the Company. These policies have accumulated cash values of $47.1 million and $42.4 million at December 31, 1994 and 1993, respectively, which do not qualify as plan assets in the actuarial computation of the funded status. Based upon SFAS No. 87, the Company has recorded a liability of $4.6 million as of December 31, 1994. 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 1994 1993 1992 (Thousands of Dollars) Pension plan: Service cost $ 6,049 $ 4,496 $ 3,762 Interest cost 12,263 11,688 10,926 Actual return on plan assets 312 (23,322) (10,877) Deferred gain (loss) on plan assets (15,584) 9,848 (1,861) Net cost $ 3,040 $ 2,710 $ 1,950 Approximate percentage included in operating expenses 67% 66% 64% Net deferred compensation plan costs charged to other income (including life insurance and SFAS No. 87 liability accrual)(a) $ 508 $ 1,372 $ 1,276 (a) These charges to the Income Statement have been reduced by gains from the Company-Owned Life Insurance (COLI) of $2,724,000; $1,638,000; and $1,607,000 for 1994, 1993 and 1992, respectively. Funded status and significant assumptions as of December 31: Deferred Pension Plan Compensation Plan 1994 1993 1994 1993 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $128,162 $134,292 $19,148 $24,024 Accumulated benefit obligation $132,766 $139,270 $19,148 $24,027 Projected benefit obligation $167,103 $179,895 $19,681 $30,114 Plan assets at fair value 165,839 169,920 - - Plan assets in excess of (or less than) projected benefit obligation (1,264) (9,975) (19,681) (30,114) Unrecognized net (gain) loss from past experience different from that assumed 6,040 17,295 2,173 7,295 Unrecognized prior service cost 6,365 1,460 (3,516) 2,546 Unrecognized net (asset) obligation existing at date of initial adoption (19.5 year straight-line amortization) (2,756) (3,019) 6,440 7,053 Minimum liability adjustment - - (4,564) (10,807) Net asset (liability) included in the balance sheet $8,385 $5,761 $(19,148) $(24,027) Discount rate to compute projected benefit obligation 8.0% 7.0% 8.0% 7.0% Rate for future compensation increases 4.5 4.5 4.5 4.5 Expected long-term rate of return on plan assets 9.0 9.0 - - Supplemental Employee Retirement Plan (SERP) - The Company has a nonqualified SERP that provides benefits in excess of Internal Revenue Service limits (Section 401 (a)(17) of the Internal Revenue Code) for highly paid individuals. The projected benefits obligation of this plan was $857,000 and $525,000 at December 31, 1994 and 1993, respectively, with accrued pension costs of $396,000 and $226,000. The Company's net periodic pension cost of this plan was $125,000 and $36,000 for the same periods. Savings Plan _ The Company has an Employee Savings Plan whereby, for each $1 of employee contribution up to 6 percent of their salary the Company will match 100 percent of the first 2 percent employee contribution and 50 percent of the next 4 percent 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 $2,410,200 in 1994, $2,283,200 in 1993 and $2,046,100 in 1992. As of December 31, 1994, a total of 4,214,735 Idaho Power Company common shares were held in this Plan. 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 and was approved by IPUC Order No. 25880. The following tables set forth the amounts to be recognized in the Company's financial statements for year-end 1994 and 1993 and the funded status of the plan in accordance with accounting standard SFAS No. 106 as of December 31, 1993 and 1994. December 31, 1994 December 31, 1993 (Thousands of Dollars) Postretirement Benefit Cost: Service cost $ 855 $ 750 Interest cost 3,334 3,610 Actual return on plan assets (1,114) (860) Amortization of transition obligation 2,040 2,040 Net amortization and deferral - - Regulatory asset (1,907) (3,548) Net cost (a) $ 3,208 $ 1,992 (a) Postretirement benefit costs charged to expense in 1992 was $2,622,300 December 31, 1994 December 31, 1993 (Thousands of Dollars) Funded Status: Accumulated postretirement benefit obligation (APBO) $(45,001) $(48,290) Plan assets at fair value 12,116 11,840 APBO in excess of plan assets (32,885) (36,450) Unrecognized gain/losses 773 4,670 Unrecognized transition obligation 36,720 38,760 Prepaid postretirement benefit cost $ 4,608 $ 6,980 Discount rate 8.25% 7.25% Medical and dental inflation rate 7.25 6.75 Long-term plan assets expected 9.0 9.0 return A one percent change in the medical inflation rate would change the APBO by 7.3 percent and the postretirement expense for 1994 by 9.0 percent. The Company has a retiree medical benefits funding program which 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 $776,400 in 1994, $632,500 in 1993, $1,733,000 in 1992. The funding to the VEBA was $743,600 in 1994, $2,692,000 in 1993, and $2,977,400 in 1992, 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 OPUC 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 FERC deferral of $545,400 was expensed in 1994. The remaining amount deferred, as a regulatory asset, at December 31, 1994 is $5.5 million. The Company received IPUC Order No. 25880 authorizing the amortization of the $5.5 million over a 10-year period. 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 has recorded a liability and a regulatory asset of $4.0 million which represents the costs associated with postemployment benefits at December 31, 1994. The Company received IPUC Order No. 25880 authorizing the amortization of the regulatory asset over a 10- year period. 10. ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS: The following table sets out the major classifications of the Company's electric plant in service and accumulated provision for depreciation for the years 1994, 1993, and 1992. Electric Plant in Service 1994 1993 1992 (Thousands of Dollars) Production $1,301,525 $1,199,188 $1,194,148 Transmission 310,102 328,249 324,222 Distribution 625,149 582,604 545,490 General and Other 147,122 139,682 134,887 Total In Service 2,383,898 2,249,723 2,198,747 Less accumulated provision for depreciation 775,033 728,979 683,332 In Service - Net $1,608,865 $1,520,744 $1,515,415 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, 1994 are as follows: Company Ownership Electric Accumulated Plant In Provision For Name of Plant Location Service Depreciation % MW (Thousands of Dollars) Jim Bridger Units 1-4 Rock Springs, WY $376,928 $150,599 33 693 Boardman Boardman, OR 59,488 24,112 10 53 Valmy Units 1 & 2 Winnemucca, NV 299,865 98,030 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 $46,097,000 in 1994, $45,424,000 in 1993 and $42,291,000 in 1992. The Company has contracts to purchase the energy from five PURPA Qualified Facilities which are 50 percent owned by Ida-West. Power purchased from these facilities amounted to $7,139,000 in 1994, $5,975,093 in 1993 and $1,848,904 in 1992. 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 consolidated financial position of Idaho Power Company and subsidiaries at December 31, 1994, 1993 and 1992, and the results of their operations and their cash flows for 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 LLP Portland, Oregon January 31, 1995 IDAHO POWER COMPANY SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA: The following unaudited information is presented for each quarter of 1994, 1993 and 1992 (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 1994 Revenues $128,810 $128,541 $151,031 $135,277 Income from operations 37,408 33,984 33,609 44,663 Income taxes 9,406 6,554 8,150 10,133 Net income 18,260 17,030 16,289 23,351 Dividends on preferred stock 1,789 1,819 1,862 1,928 Earnings on common stock 16,471 15,211 14,427 21,423 Earnings per share of common 0.44 0.41 0.38 0.57 stock 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 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 SCHEDULE 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 schedule. (b) Reports on SEC Form 8-K. No reports on Form 8-K were filed during the three months ended December 31, 1994. (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 Number Dated 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)(i)1 The Revised Security Plans for Senior Management Employees and for Directors-a non-qualified, deferred compensation plan effective November 30, 1994. 10(n)(ii)1 The Executive Annual Incentive Plan for senior management employees effective January 1, 1995. 10(n)(iii)1 The 1994 Restricted Stock Plan for officers and key executives effective July 1, 1994. *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). ___________________ 1 Compensatory Plan *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. *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. 27 Financial Data Schedule IDAHO POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1994, 1993 and 1992 Column C Column A Column B Additions Column D Column E Balance Charged Charged Balance At to (Credited) At Classification Beginning Income to Other Deductions End Of Of Period Accounts (1) Period (Thousands of Dollars) 1994: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,377 $1,360 $1,018(2) $2,378 $1,377 Other Reserves: Injuries and damages reserve $1,500 $1,804 $ - $1,804 $1,500 Miscellaneous operating reserves $ 748 $ 429 $ (156) $ 81 $ 940 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 NOTES: (1) Represents deductions from the reserves for purposes for which the reserves were created. (2) Represents collections of accounts previously written off. 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 9, 1995 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 9, 1995 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/_ __ By:__/s/__Jon H. Miller ________ " Roger L. Breezley Jon H. Miller Director Director By:__/s/_ John B. Carley_______ By:__/s/__Peter S. O'Neill ______ " John B. Carley Peter S. O'Neill Director Director By:__/s/__Peter T. Johnson_____ By:__/s/__Gene C. Rose _______ " Peter T. Johnson Gene C. Rose Director Director By:__/s/__Jack K. Lemley_____ By:__/s/__Phil Soulen _______ " Jack K. Lemley Phil Soulen Director Director EXHIBIT INDEX Exhibit Page Number Number 10(n)(i) The Revised Security Plans for Senior 93 Management Employees and for Directors- a non-qualified, deferred compensation plan effective November 30, 1994. 10(n)(ii) The Executive Annual Incentive Plan for 126 senior management employees effective January 1, 1995. 10(n)(iii) The 1994 Restricted Stock Plan for 128 officers and key executives effective July 1, 1994. 12 Statement Re: Computation of Ratio of 133 Earnings to Fixed Charges. 12(a) Statement Re: Computation of 134 Supplemental Ratio of Earnings to Fixed Charges. 12(b) Statement Re: Computation of Ratio of 135 Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 12(c) Statement Re: Computation of 136 Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 21 Subsidiaries of Registrant. 137 23 Independent Auditors' Consent. 138 27 Financial Data Schedule 139 EX-10.(N)(I) 2 IDAHO POWER COMPANY SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES Amended and Restated Effective November 30, 1994 TABLE OF CONTENTS ARTICLE I PURPOSE; EFFECTIVE DATE 1 ARTICLE II DEFINITIONS 1 2.1 Actuarial Equivalent 1 2.2 Beneficiary 2 2.3 Board 2 2.4 Change in Control 2 2.5 Committee 3 2.6 Company 3 2.7 Compensation 3 2.8 Contract of Participation 3 2.9 Disability 4 2.10 Early Retirement Date 4 2.11 Employer 4 2.12 Final Average Monthly Compensation 4 2.13 Frozen Retirement Benefit 4 2.14 Frozen Survivor Benefit 5 2.15 Normal Form of Benefit 5 2.16 Normal Retirement Date 6 2.17 Participant 6 2.18 Plan Year 6 2.19 Retirement 6 2.20 Retirement Plan 6 2.21 Supplemental Retirement Benefit 6 2.22 Target Retirement Percentage 6 2.23 Years of Participation 6 ARTICLE III PARTICIPATION AND VESTING 7 3.1 Eligibility and Participation 7 3.2 Vesting 7 3.3 Change in Employment Status 7 ARTICLE IV BENEFIT ELECTION 8 4.1 Benefit Election 8 4.2 Commencement of Benefits 8 ARTICLE V SURVIVOR BENEFITS 8 5.1 Pre-retirement Survivor Benefits 8 5.2 Post-termination Survivor Benefit 9 5.3 Suicide 10 ARTICLE VI SUPPLEMENTAL RETIREMENT BENEFITS 10 6.1 Normal Retirement Benefit 10 6.2 Early Retirement Benefit 10 6.3 Early Retirement Factor 11 6.4 Early Termination Benefits 11 6.5 Termination After Change in Control 12 6.6 Form of Payment 12 ARTICLE VII OTHER RETIREMENT PROVISIONS 13 7.1 Disability 13 7.2 Withholding Payroll Taxes 13 7.3 Payment to Guardian 13 ARTICLE VIII BENEFICIARY DESIGNATION 14 8.1 Beneficiary Designation 14 8.2 Amendments, Marital Status; No Participant Designation 14 8.3 Effect of Payment 15 ARTICLE IX ADMINISTRATION 15 9.1 Committee; Duties 15 9.2 Indemnity of Committee 16 ARTICLE X CLAIMS PROCEDURE 16 10.1 Claim 16 10.2 Denial of Claim 16 10.3 Review of Claim 17 10.4 Final Decision 17 ARTICLE XI TERMINATION, SUSPENSION OR AMENDMENT 17 11.1 Termination, Suspension or Amendment of Plan 17 11.2 Change in Control 18 ARTICLE XII MISCELLANEOUS 18 12.1 Unfunded Plan 18 12.2 Unsecured General Creditor 18 12.3 Trust Fund 19 12.4 Nonassignability 19 12.5 Not a Contract of Employment 19 12.6 Governing Law 20 12.7 Validity 20 12.8 Notice 20 12.9 Successors 20 IDAHO POWER COMPANY SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES AMENDED AND RESTATED EFFECTIVE NOVEMBER 30, 1994 ARTICLE I PURPOSE; EFFECTIVE DATE The purpose of this Security Plan for Senior Management Employees (the "Plan") is to provide supplemental retirement benefits for certain key employees of Idaho Power Company and its subsidiaries and affiliates. It is intended that the Plan will aid in retaining and attracting individuals of exceptional ability by providing them with these benefits. The effective date of this restatement shall be November 30, 1994. ARTICLE II DEFINITIONS For the purposes of this Plan, the following terms shall have the meanings indicated, unless the context clearly indicates otherwise: 2.1 Actuarial Equivalent. "Actuarial Equivalent" shall mean equivalence in value between two (2) or more forms and/or times of payment based on a determination by an actuary chosen by the Company using generally accepted actuarial assumptions, methods and factors as used in the Retirement Plan of Idaho Power Company which may be amended from time to time. 2.2 Beneficiary. "Beneficiary" shall mean the person, persons or entity designated by the Participant or pursuant to Article VI to receive any benefits payable under the Plan. Each such designation shall be made in a written instrument filed with the Committee and shall become effective only when received, accepted and acknowledged in writing by the Committee. 2.3 Board. "Board" shall mean the Board of Directors of the Company. 2.4 Change in Control. "Change in Control" shall mean the earlier of the following to occur: (a) the public announcement by the Company or by any person (which shall not include the Company, any subsidiary of the Company or any employee benefit plan of the Company or of any subsidiary of the Company) ("Person") that such Person, who or which, together with all Affiliates and Associates (within the meanings ascribed to such terms in Rule 12b-2 of the Exchange Act) of such Person, shall be the beneficial owner of twenty percent (20%) or more of the voting stock then outstanding; (b) the commencement of, or after the first public announcement of any Person to commence, a tender or exchange offer the consummation of which would result in any Person becoming the beneficial owner of voting stock aggregating thirty percent (30%) or more of the then outstanding voting stock; (c) the announcement of any transaction relating to the Company required to be described pursuant to the requirements of Item 6(e) of Schedule 14A of Regulation 14A of the Securities and Exchange Commission under the Exchange Act; (d) a proposed change in the constituency of the Board of Directors of the Company such that, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of the Company cease for any reason to constitute at least a majority thereof, unless the election or nomination for election by the shareholders of the Company of each new director was approved by a vote of at least two-third (2/3) of the directors then still in office who were members of the Board of Directors of the Company at the beginning of the period; or (e) any other event which shall be deemed by a majority of the Committee of the Board of Directors of the Company to constitute a "change in control." 2.5 Committee. "Committee" shall mean the Committee appointed by the Board pursuant to Section 9.1 hereof to administer the Plan. 2.6 Company. "Company" shall mean the Idaho Power Company, an Idaho corporation, its successors and assigns. 2.7 Compensation. "Compensation" shall mean the base salary and annual bonuses paid to a Participant and considered to be "wages" for purposes of federal income tax withholding. Compensation shall be calculated before reduction for any amounts deferred by the Participant pursuant to any plan sponsored by the Employer which permits deferral of current compensation. Compensation does not include long-term incentive compensation in any form, expense reimbursements, or any form of noncash compensation or benefits. 2.8 Contract of Participation. "Contract of Participation" shall mean an agreement of participation in the Idaho Power Security Plan for Senior Management Employees between the Participant and Idaho Power Company in the form attached as Appendix A. 2.9 Disability. "Disability" shall mean that a Participant is eligible to receive benefits under the Long-Term Disability Program maintained by the Employer as defined in Section 2.11 hereof. 2.10 Early Retirement Date. "Early Retirement Date" shall mean the date on which a Participant terminates employment with the Employer, as defined in Section 2.11 hereof, if such termination date occurs on or after such Participant's attainment of age fifty-five (55) but prior to Participant's Normal Retirement Date. 2.11 Employer. "Employer" shall mean the Company and any affiliated or subsidiary corporation now in existence or subsequently designated by the Board, or any successors to the business thereof. 2.12 Final Average Monthly Compensation. "Final Average Monthly Compensation" shall mean the total compensation received by the Participant during any sixty (60) consecutive months (during the last ten (10) years of employment) for which the Participant's compensation was the highest divided by sixty (60). In determining Final Average Monthly Compensation, annual bonuses shall be allocated equally to the months in which they were accrued or earned. Final Average Monthly Compensation shall not include any Compensation payable to a Participant pursuant to a written severance agreement with the Employer. 2.13 Frozen Retirement Benefit. "Frozen Retirement Benefit" shall mean the benefit accrued as of November 30, 1994, under the Idaho Power Company Security Plan for Senior Management Employees as amended and restated May 1, 1990. The Frozen Retirement Benefit shall be calculated using compensation through November 30, 1994, and actual age at commencement of benefits. Participation after November 30, 1994, shall be included for calculating vesting for the Frozen Retirement Benefit. The Frozen Retirement Benefit shall be paid in the form and manner set forth in this Plan prior to this amendment. The Frozen Retirement Benefit shall include the Participant's salary reduction with interest as provided in Section 5.5 of the Idaho Power Company Security Plan for Senior Management Employees as amended and restated May 1, 1990. Effective November 30, 1994, there shall be no additional employee contributions or salary reductions under this Plan. The Frozen Retirement Benefit accrued shall not be reduced due to the failure to complete salary reductions for the final benefit class if such failure resulted from removing the salary reduction requirement from the Plan effective November 30, 1994. 2.14 Frozen Survivor Benefit. "Frozen Survivor Benefit" shall mean the survivor benefit accrued as of November 30, 1994, under Article IV of the Idaho Power Company Security Plan for Senior Management Employees as amended and restated May 1, 1990. The Frozen Survivor Benefit shall be calculated using compensation through November 30, 1994, and actual age at commencement of benefits. Participation after November 30, 1994, shall be included for calculating vesting for the Frozen Survivor Benefit. The Frozen Survivor Benefit shall be paid in the form and manner set forth in this Plan prior to this amendment. The Frozen Survivor Benefit accrued shall not be reduced due to the failure to complete salary reductions for the final benefit class if such failure resulted from removing the salary reduction requirement from the Plan effective November 30, 1994. 2.15 Normal Form of Benefit. "Normal Form of Benefit" shall mean the normal form of monthly retirement benefit provided under Section 3.01 of the Employer's Retirement Plan. 2.16 Normal Retirement Date. "Normal Retirement Date" shall mean the date on which the Participant terminates employment with the Employer if the termination date occurs on or after the Participant attains age sixty-two (62). 2.17 Participant. "Participant" shall mean any individual who is participating in or has participated in this Plan as provided in Article III. 2.18 Plan Year. "Plan Year" shall mean the calendar year effective November 30, 1994. 2.19 Retirement. "Retirement" shall mean a Participant's termination from employment with the Employer at the Participant's Early Retirement Date or Normal Retirement Date, as applicable. 2.20 Retirement Plan. "Retirement Plan" shall mean The Retirement Plan of Idaho Power Company as may be amended from time to time. 2.21 Supplemental Retirement Benefit. "Supplemental Retirement Benefit" shall mean the benefit determined under Article VI of this Plan. 2.22 Target Retirement Percentage. "Target Retirement Percentage" shall equal six percent (6%) for each of the first ten (10) years of participation plus an additional one percent (1%) for each Year of Participation, as defined in Section 2.22 hereof, exceeding ten (10). The maximum target shall be seventy- five percent (75%). 2.23 Years of Participation. "Years of Participation" shall be twelve (12) month periods, and portions thereof, which shall begin on the earlier of, the date of the Participant's signature of the Contract of Participation for this Plan or a date designated by the Committee, and shall end at the termination of participation. Partial Years of Participation, if any, shall be used in determining benefits under this Plan. ARTICLE III PARTICIPATION AND VESTING 3.1 Eligibility and Participation. (a) Eligibility. Eligibility to participate in the Plan is limited to those key employees of the Employer that are designated, from time to time, by the Employer. (b) Participation. Participation in the Plan shall continue until such time as the Participant ceases participation in this Plan and as long thereafter as the Participant is eligible to receive benefits under this Plan. 3.2 Vesting. A Participant shall be one hundred percent (100%) vested. 3.3 Change in Employment Status. If the Employer determines that a Participant's employment performance is no longer at a level which deserves reward through participation in this Plan, but does not terminate the Participant's employment with the Employer, participation herein and eligibility to receive benefits hereunder shall be limited to the Participant's accrued benefit as of the date designated by the Committee. In such an event, the benefits payable to the Participant shall be based solely on the Participant's Years of Participation and Final Average Monthly Compensation as of the date designated by the Committee. The benefit shall be calculated under the early retirement provisions pursuant to Sections 6.2 and 6.3(a), with commencement of benefit not earlier than the later of termination of employment or age fifty-five (55). ARTICLE IV BENEFIT ELECTION 4.1 Benefit Election. A Participant or a Beneficiary of a Participant may elect to receive either (a) the Frozen Benefit (the Frozen Retirement Benefit or the Frozen Survivor Benefit); or (b) the benefit accrued under this Plan after November 30, 1994. The election shall be made on a form approved by the Committee and prior to the receipt of any benefits under this Plan. No benefits accrued after November 30, 1994, shall be paid if either the Frozen Retirement Benefit or the Frozen Survivor Benefit is elected. 4.2 Commencement of Benefits. A Participant or a Beneficiary shall determine the date when benefits shall commence within the time authorized by the Plan. ARTICLE V SURVIVOR BENEFITS 5.1 Pre-retirement Survivor Benefits. If a Participant dies while employed by the Employer, the Employer shall pay a survivor benefit to such Participant's Beneficiary as follows: (a) Amount. The pre-termination survivor benefit shall be equal to sixty-six and two-thirds percent (66 2/3%) of the retirement benefit calculated under Article VI assuming retirement occurred at the later of age sixty-two (62) or date of death. Final Average Monthly Compensation shall be determined as of the date of the Participant's death. (b) Payment. If the Participant is married on the date of death, the benefits shall be paid for the life of the spouse. If the spouse's date of birth is more than ten (10) years after the Participant's date of birth, the monthly benefit shall be reduced to the Actuarial Equivalent of the above benefit, assuming the above benefit is payable to a spouse ten (10) years younger than the Participant. If the Participant is unmarried on the date of death, the benefit shall be paid to the Participant's Beneficiary in a lump sum equal to the value of a death benefit payable to an assumed spouse the same age as the Participant. 5.2 Post-termination Survivor Benefit. (a) Death Prior to Commencement of Benefits. (i) Amount. The amount of the post-termination survivor benefit shall be equal to sixty-six and two thirds percent (66 2/3%) of the retirement benefit payable to the Participant. (ii) Payment. If the Participant is married on the date of death, the benefits shall be paid for the life of the spouse. If the spouse's date of birth is more than ten (10) years after the Participant's date of birth, the monthly benefit shall be reduced to the Actuarial Equivalent of the above benefit assuming that the above benefit is payable to a spouse ten (10) years younger than the Participant. If the Participant is unmarried on the date of death, the benefit shall be paid to the Participant's Beneficiary in a lump sum equal to the value of a death benefit payable to an assumed spouse the same age as the Participant. (b) Death After Commencement of Benefits. If a Participant dies after commencement of benefits, a survivor benefit will be paid only if, and to the extent provided for, under the form of benefit elected by the Participant.-- 5.3 Suicide. In the event a Participant commits suicide within one (1) year of initially entering this Plan, no benefits shall be payable hereunder to the Participant's Beneficiaries. ARTICLE VI SUPPLEMENTAL RETIREMENT BENEFITS 6.1 Normal Retirement Benefit. The monthly Supplemental Retirement Benefit shall equal the Target Retirement Percentage multiplied by the Participant's Final Average Monthly Compensation, less 1) the amount of the Participant's retirement benefit under the Retirement Plan Normal Form of Benefit regardless of the form selected by the Participant under the Retirement Plan; and 2) the benefit payable as a single life annuity under the Supplemental Executive Retirement Plan. If the Participant selects an "optional" form of benefit under this Plan, then the benefit shall be the Actuarial Equivalent of the Normal Form of Benefit. 6.2 Early Retirement Benefit. If a Participant retires at an Early Retirement Date, the Employer shall pay to the Participant a monthly Supplemental Retirement Benefit. The Early Retirement Benefit shall be equal to the Target Retirement Percentage, multiplied by the Early Retirement Factor and by the Participant's Final Average Monthly Compensation, less 1) the amount of the Participant's retirement benefit under the Retirement Plan Normal Form of Benefit at the later of, age fifty- five (55) or the Participant's retirement date; and 2) the benefit payable as a single life annuity under the Supplemental Executive Retirement Plan at the later of, age fifty-five (55) or the Participant's Retirement date. If the Participant selects an "optional" form of benefit under this Plan, then the benefit shall be the Actuarial Equivalent of the Normal Form of Benefit. 6.3 Early Retirement Factor. If a Participant retires before the Participant's Normal Retirement Date, the Target Retirement Percentage shall be multiplied by one (1) of the following Early Retirement Factors. (a) If termination occurs with approval or if the Participant terminates within twenty-four (24) months after a Change in Control, the Early Retirement Factor shall be one hundred percent (100%), less .25 of one percent for each full calendar month, between the Participant's benefits commencement date and Normal Retirement Date. (b) If termination occurs without approval and the Participant has not terminated within twenty-four (24) months after a Change in Control, the Early Retirement Factor shall be one hundred percent (100%), less .4167 of one percent for each full calendar month between the Participant's benefits commencement date and Normal Retirement Date, times a fraction equal to the Participant's Years of Participation at termination divided by the Years of Participation the Participant would have had at Participant's Normal Retirement Date if Participant had continued to be employed by the Employer. (c) Authorization to grant approval for early retirement is vested with the Committee for elected officers of the Company and with the Chief Executive Officer of the Company for non-officers. 6.4 Early Termination Benefits. If a vested Participant terminates employment with the Employer prior to Retirement or death, the Employer shall pay to the Participant, commencing not earlier than the later of the Participant's fifty-fifth (55th) birthday or termination of employment, the Supplemental Retirement Benefit as determined under this section. (a) The Target Retirement Percentage shall be calculated based upon the Years of Participation and then multiplied by a fraction equal to the Participant's actual Years of Participation divided by the Years of Participation the Participant would have had at the Normal Retirement Date if the Participant had continued to be employed by the Employer to age sixty-two (62). The adjusted Target Retirement Percentage shall be further reduced by .4167 of one percent for each month between the Participant's benefits commencement date and age sixty-two (62). (b) The Early Termination Benefit shall be offset by: 1) the Retirement Plan Normal Form of Benefit payable on the date of benefit commencement regardless of service; and 2) the benefit payable as a single life annuity under the Supplemental Executive Retirement Plan payable on the date of benefit commencement regardless of service. 6.5 Termination After Change in Control. If a Participant terminates within two (2) years after a Change in Control, the Participant shall receive, beginning on the later of the attainment of age fifty-five (55) or the Participant's actual termination date, the Early Retirement Benefit calculated with the Early Retirement Factors set forth in 6.3(a). 6.6 Form of Payment. The Supplemental Retirement Benefit shall be paid in the basic form provided below unless the Participant elects in the calendar year prior to retirement or termination an Actuarial Equivalent form of benefit provided in this section. (a) Normal Form of Benefit Payment. The normal form of payment shall be a single-life annuity for the lifetime of the Participant. (b) Actuarial Equivalent Forms of Benefit. (i) A joint and survivor annuity with payments continued to the survivor at an amount equal to two-thirds (2/3) of the Participant's benefit. (ii) A joint and survivor annuity with payments continued to the survivor at an amount equal to the Participant's benefit. ARTICLE VII OTHER RETIREMENT PROVISIONS 7.1 Disability. During a period of Disability, a Participant will continue to accrue Years of Participation; and any benefits payable under this Plan shall be based upon the greater of the Participant's Compensation at the time of Disability or Final Average Monthly Compensation. 7.2 Withholding Payroll Taxes. The Employer shall withhold from payments made hereunder any taxes required to be withheld from a Participant's wages under federal, state or local law. 7.3 Payment to Guardian. If a Plan benefit is payable to a minor or a person declared incompetent or to a person incapable of handling the disposition of property, the Committee may direct payment of such Plan benefit to the guardian, legal representative or person having the care and custody of the minor, incompetent or person. The Committee may require proof of incompetency, minority, incapacity or guardianship, as it may deem appropriate, prior to distribution of the Plan benefit. The distribution shall completely discharge the Committee and the Employer from all liability with respect to such benefit. ARTICLE VIII BENEFICIARY DESIGNATION 8.1 Beneficiary Designation. The primary Beneficiary shall be the Participant's spouse. Each Participant, in the event the Participant's spouse predeceases the Participant, or the Participant is unmarried, shall have the right, at any time, to designate any person or persons as Beneficiary or Beneficiaries (both principal as well as contingent) to whom payment under this Plan shall be made in the event of the Participant's death prior to complete distribution to Participant of the benefits due Participant under the Plan. 8.2 Amendments, Marital Status; No Participant Designation. Any Beneficiary designation form may be changed by a Participant by the filing of a written form prescribed by the Committee. The filing of a new Beneficiary designation form will cancel all Beneficiary designations previously filed. Any finalized divorce or marriage (other than common law) of a Participant subsequent to the date of fling of a Beneficiary designation form shall automatically revoke the prior designation. If a Participant fails to designate a Beneficiary as provided above, or if the Beneficiary designation is revoked by marriage or divorce, without execution of a new designation, or if all designated Beneficiaries predecease the Participant or die prior to complete distribution of the Participant's benefits, then Participant's designated Beneficiary shall be deemed to be the person or persons surviving the Participant in the first of the following classes in which there is a survivor, share and share alike: (a) the Participant's surviving spouse; (b) the Participant's children, except that if any of the children predecease the Participant but leaves issue surviving, the issue shall take by right of representation; (c) the Participant's personal representative (executor or administrator). 8.3 Effect of Payment. The payment to the Beneficiary shall completely discharge Employer's obligations under this Plan. ARTICLE IX ADMINISTRATION 9.1 Committee; Duties. This Plan shall be administered by a Committee which shall consist of not less than three (3) nor more than five (5) persons appointed by the Board. Members of the Committee may be Participants under this Plan. The Committee shall have the authority to make, amend, interpret and enforce all appropriate rules and regulations for the administration of this Plan and decide or resolve any and all questions including interpretations of this Plan, as may arise in connection with the Plan. A majority vote of the Committee members shall control any decision. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit and may from time to time consult with counsel who may be counsel to the Employer. Subject to Article X, the decision or action of the Committee in respect of any questions arising out of, or in connection with, the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan. 9.2 Indemnity of Committee. To the extent permitted by applicable law, the Employer shall indemnify, hold harmless and defend the Committee against any and all claims, loss, damage, expense or liability arising from any action or failure to act with respect to this Plan, provided that the Committee was acting in accordance with the applicable standard of care. The indemnity provisions set forth in this Article shall not be deemed to restrict or diminish in any way any other indemnity available to the Committee members in accordance with the Article or By-laws of the Company. ARTICLE X CLAIMS PROCEDURE 10.1 Claim Any person claiming a benefit, requesting an interpretation or ruling under the Plan, or requesting information under the Plan shall present the request in writing to the Committee who shall respond in writing as soon as practicable. 10.2 Denial of Claim. If the claim or request is denied, the written notice of denial shall state: (a) the reason for denial, with specific reference to the Plan provisions on which the denial is based; (b) a description of any additional material or information required and an explanation of why it is necessary; and (c) an explanation of the Plan's claims review procedure. 10.3 Review of Claim. Any person whose claim or request is denied or who has not received a response within thirty (30) days may request a review by notice given in writing to the Committee. The claim or request shall be reviewed by the Committee who may, but shall not be required to, grant the claimant a hearing. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing. 10.4 Final Decision. The decision on review shall normally be made within sixty (60) days. If an extension of time is required for a hearing or other special circumstances, the claimant shall be notified and the time limit shall be one hundred twenty (120) days. The decision shall be in writing and shall state the reason and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned. ARTICLE XI TERMINATION, SUSPENSION OR AMENDMENT 11.1 Termination, Suspension or Amendment of Plan. The Board may, in its sole discretion, terminate or suspend this Plan at any time or from time to time, in whole or in part. The Board may amend this Plan at any time or from time to time. Any amendment may provide different benefits or amounts of benefits from those herein set forth. However, no such termination, suspension or amendment or other action with respect to the Plan shall adversely affect the benefits of Participants which have accrued prior to such action, the benefits of any Participant who has previously retired, or the benefits of any Beneficiary of a Participant who has previously died. Furthermore, no termination, suspension or amendment shall alter the applicability of the vesting schedule in Section 3.2 with respect to a Participant's accrued benefit at the time of such termination, suspension or amendment. 11.2 Change in Control. Notwithstanding Section 11.1 above, in the event of a Change in Control, neither the Board nor the Committee may terminate this Plan with regard to current Participants. No amendment may be made to the Plan following a Change in Control which would adversely affect the benefits of current Participants, the benefits of any Participant who has retired, or the Beneficiary of any Participant who has died. The Plan shall continue to operate and be effective with regard to all current or retired Participants and their Beneficiaries as of the date of the Change in Control. ARTICLE XII MISCELLANEOUS 12.1 Unfunded Plan. This Plan is intended to be an unfunded plan maintained primarily to provide deferred compensation benefits for a select group of "management or highly compensated employees" within the meaning of Sections 201, 301 and 401 of the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), and therefore to be exempt from the provisions of Parts 2, 3 and 4 of Title I of ERISA. 12.2 Unsecured General Creditor. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or claims in any property or asset of the Employer, nor shall they be Beneficiaries of, or have any rights, claims or interests in any life insurance policies, annuity contracts or the proceeds therefrom owned or which may be acquired by the Employer. Except as may be provided in Section 12.3, such policies, annuity contracts or other assets of the Employer shall not be held under any trust for the benefit of Participants, their Beneficiaries, heirs, successors or assigns, or held in any way as collateral security for the fulfilling of the obligation of the Employer under this Plan. Any and all of the Employer's assets and policies shall be, and remain, the general, unpledged, unrestricted assets of the Employer. The Employer's obligation under the Plan shall be that of an unfunded and unsecured promise to pay money in the future. 12.3 Trust Fund. The Employer shall be responsible for the payment of all benefits provided under the Plan. At its discretion, the Employer may establish one or more trusts, with such trustees as the Board may approve, for the purpose of providing for the payment of such benefits. Such trust or trusts may be irrevocable, but the assets thereof shall be subject to the claims of the Employer's creditors. To the extent any benefits provided under the Plan are actually paid from any such trust, the Employer shall have no further obligation with respect thereto, but to the extent not so paid, such benefits shall remain the obligation of, and shall be paid by, the Employer. 12.4 Nonassignability. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and nontransferable. No part of the amount payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of Participant's or any other person's bankruptcy or insolvency. 12.5 Not a Contract of Employment. The terms and conditions of this Plan shall not be deemed to constitute a contract of employment between the Employer and the Participant, and the Participant (or Participant's Beneficiary) shall have no rights against the Employer except as may otherwise be specifically provided herein. Moreover, nothing in this Plan shall be deemed to give a Participant the right to be retained in the service of the Employer or to interfere with the right of the Employer to discipline or discharge the Participant at any time. 12.6 Governing Law. The provisions of this Plan shall be construed, interpreted and governed in all respects in accordance with the applicable federal law and, to the extent not preempted by such federal law, in accordance with the laws of the State of Idaho without regard to the principles of conflicts of laws. 12.7 Validity. If any provision of this Plan shall be held illegal or invalid for any reason, the remaining provisions shall nevertheless continue in full force and effect without being impaired or invalidated in any way. 12.8 Notice. Any notice or filing required or permitted to be given under the Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail or fax. The notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. 12.9 Successors. Subject to Section 11.1, the provisions of this Plan shall bind and inure to the benefit of the Employer and its successors and assigns. The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or otherwise acquire all or substantially all of the business and assets of the Employer, and successors of any such corporation or other business entity. IDAHO POWER COMPANY By: /s/ Joseph W. Marshall Chairman By: /s/ Robert W. Stahman Secretary Dated: October 17, 1994 APPENDIX A CONTRACT OF PARTICIPATION IN THE IDAHO POWER COMPANY SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES NAME OF PARTICIPANT: DATE OF BIRTH: SENIOR MANAGEMENT PLAN ENTRY DATE: BENEFICIARY: This Agreement is made and entered into as of the date written hereinbelow by and between Idaho Power Company and . This Agreement is subject to all of the terms of the Idaho Power Company Security Plan for Senior Management Employees, as amended and restated November 30, 1994 (The "Plan"). By signing this agreement, Participant acknowledges receipt of a copy of the Plan document. PARTICIPANT IDAHO POWER COMPANY BY BY PARTICIPANT CHAIRMAN DATE DATE IDAHO POWER COMPANY SECURITY PLAN FOR BOARD OF DIRECTORS Amended and Restated Effective November 30, 1994 TABLE OF CONTENTS ARTICLE I PURPOSE; EFFECTIVE DATE 1 1.1 Purpose 1 ARTICLE II DEFINITIONS 1 2.1 Actuarial Equivalent 1 2.2 Beneficiary 2 2.3 Board 2 2.4 Change in Control 2 2.5 Committee 3 2.6 Company 3 2.7 Contract of Participation 3 2.8 Employer 3 2.9 Participant 3 2.10 Plan Anniversary Date 3 2.11 Plan Year 3 2.12 Supplemental Retirement Benefit 4 2.13 Year of Service 4 ARTICLE III PARTICIPATION AND VESTING 4 3.1 Participation 4 3.2 Fee Reduction 4 3.3 Vesting 4 ARTICLE IV SURVIVOR BENEFITS 4 4.1 Death Benefit 4 4.2 Suicide 8 ARTICLE V RETIREMENT BENEFITS 8 5.1 Benefit 8 5.2 Form of Payment 8 5.3 Commencement of Benefit Payment 9 5.4 Grandfathered Form of Benefit 9 ARTICLE VI BENEFICIARY DESIGNATION 10 6.1 Beneficiary Designation 10 6.2 Amendments, Marital Status, No Participant Designation 10 6.3 Effect of Payment 11 ARTICLE VII TERMINATION, SUSPENSION OR AMENDMENT OF PLAN 11 7.1 Termination, Suspension or Amendment of Plan 11 7.2 Change in Control 11 ARTICLE VIII ADMINISTRATION 12 8.1 Committee; Duties 12 8.2 Indemnity of Committee 12 ARTICLE IX CLAIMS PROCEDURE 13 9.1 Claim 13 9.2 Denial of Claim 13 9.3 Review of Claim 13 9.4 Final Decision 13 ARTICLE X MISCELLANEOUS 14 10.1 Source of Funding 14 10.2 Unsecured General Creditor 14 10.3 Trust Fund 15 10.4 Nonassignability 15 10.5 Governing Law 15 10.6 Validity 16 10.7 Notice 16 10.8 Successors 16 10.9 Payment to Guardian 16 IDAHO POWER COMPANY SECURITY PLAN FOR BOARD OF DIRECTORS AMENDED AND RESTATED NOVEMBER 30, 1994 ARTICLE I PURPOSE; EFFECTIVE DATE 1.1 Purpose. The purpose of this restated Security Plan for Board of Directors (the "Plan") is to define the terms of the Plan to advance the interests of Idaho Power Company, an Idaho corporation, and its stockholders by furnishing a variety of supplemental benefits designed to attract and retain outstanding individuals as directors of Idaho Power Company, its subsidiaries and affiliates, and to stimulate the efforts of such directors by giving suitable recognition to services which will contribute materially to the success of Idaho Power. The effective date of this restatement shall be November 30, 1994. ARTICLE II DEFINITIONS For the purposes of this Plan, the following terms shall have the meaning indicated, unless the context clearly indicates otherwise. 2.1 Actuarial Equivalent. "Actuarial Equivalent" shall mean equivalence in value between two (2) or more forms and/or times of payment based on a determination by an actuary chosen by the Company using generally accepted actuarial assumptions, methods and factors as used in the Retirement Plan of Idaho Power Company which may be amended from time to time. 2.2 Beneficiary. "Beneficiary" shall mean the person, persons or entity designated by the Participant or pursuant to Article VI to receive any benefits payable under the Plan. Each such designation shall be made in a written instrument filed with the Committee and shall become effective only when received, accepted and acknowledged in writing by the Committee. 2.3 Board. "Board" shall mean the Board of Directors of the Company. 2.4 Change in Control. "Change in Control" shall mean the earlier of the following to occur: (a) the public announcement by the Company or by any person (which shall not include the Company, any subsidiary of the Company or any employee benefit plan of the Company or of any subsidiary of the Company) ("Person") that such Person, who or which, together with all Affiliates and Associates (within the meanings ascribed to such terms in Rule 12b-2 of the Exchange Act) of such Person, shall be the beneficial owner of twenty percent (20%) or more of the voting stock then outstanding; (b) the commencement of, or after the first public announcement of any Person to commence, a tender or exchange offer the consummation of which would result in any Person becoming the beneficial owner of voting stock aggregating thirty percent (30%) or more of the then outstanding voting stock; (c) the announcement of any transaction relating to the Company required to be described pursuant to the requirements of Item 6(e) of Schedule 14A of Regulation 14A of the Securities and Exchange Commission under the Exchange Act; (d) a proposed change in the constituency of the Board of Directors of the Company such that, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of the Company cease for any reason to constitute at least a majority thereof, unless the election or nomination for election by the shareholders of the Company of each new director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were members of the Board of Directors of the Company at the beginning of the period; or (e) any other event which shall be deemed by a majority of the Committee of the Board of Directors of the Company to constitute a "change in control." 2.5 Committee. "Committee" shall mean the committee appointed by the Board pursuant to Section 8.1 hereof to administer the Plan. 2.6 Company. "Company" shall mean the Idaho Power Company, an Idaho corporation, its successors and assigns. 2.7 Contract of Participation. "Contract of Participation" shall mean an agreement of participation in the Idaho Power Security Plan for Board of Directors between the Participant and Idaho Power Company, in the form attached as Appendix A. 2.8 Employer. "Employer" shall mean the Company and any affiliated or subsidiary corporation now in existence or subsequently designated by the Board, or any successors to the business thereof. 2.9 Participant. "Participant" shall mean any individual who is elected to the Board of Directors and who has executed a Contract of Participation. 2.10 Plan Anniversary Date. "Plan Anniversary Date" shall mean August 1 of any year. 2.11 Plan Year. "Plan Year" shall mean the calendar year effective November 30, 1994. 2.12 Supplemental Retirement Benefit. "Supplemental Retirement Benefit" shall mean a benefit determined under Article V of this Plan. 2.13 Year of Service. "Year of Service" shall mean each twelve (12) months of service on the Board of Directors. ARTICLE III PARTICIPATION AND VESTING 3.1 Participation. Effective November 30, 1994, participation in the Plan shall be limited to outside directors who elect to participate in this Plan by executing a Contract of Participation. Inside directors who were Participants on November 30, 1994, shall receive their vested accrued benefit as provided in Section 4.1(b) and Article V. 3.2 Fee Reduction. Effective November 30, 1994, no additional or future fee reduction will be required. 3.3 Vesting. Participants shall be one hundred percent (100%) vested in their accrued benefit. ARTICLE IV SURVIVOR BENEFITS 4.1 Death Benefit. (a) For all Participants who are first elected to the Board of Directors after November 30, 1994, the survivor benefit shall be as follows: (i) If a Participant's death occurs prior to severance from service on the Board and commencement of the Supplemental Retirement Benefit, the Employer shall pay a survivor benefit to such Participant's Beneficiary as follows: (a) Amount. The pre-termination survivor benefit shall be equal to sixty-six and two-thirds percent (66 2/3%) of the Supplemental Retirement Benefit calculated under Article V. A Participant shall be considered to have a minimum of five (5) Years of Service for purposes of this calculation. (b) Payment. If the Participant is married on the date of death, the benefits shall be paid for the life of the spouse. If the spouse's date of birth is more than ten (10) years after the Participant's date of birth, the monthly benefit shall be reduced to the Actuarial Equivalent of the above benefit, assuming the above benefit is payable to a spouse ten (10) years younger than the Participant. If the Participant is unmarried on the date of death, the benefit shall be paid to the Participant's Beneficiary in a lump sum equal to the value of a death benefit payable to an assumed spouse the same age as the Participant. (ii) If a Participant's death occurs after termination from service on the Board but prior to commencement of the Supplemental Retirement Benefit, the Employer shall pay a survivor benefit to said Participant's Beneficiary as follows: (a) Amount. The amount of the post-termination survivor benefit shall be equal to sixty-six and two-thirds percent (66 2/3%) of the Supplemental Retirement Benefit payable to the Participant. (b) Payment. If the Participant is married on the date of death, the benefits shall be paid for the life of the spouse. If the spouse's date of birth is more than ten (10) years after the Participant's date of birth, the monthly benefit shall be reduced to the Actuarial Equivalent of the above benefit, assuming the above benefit is payable to a spouse ten (10) years younger than Participant. If the Participant is unmarried on the date of death, the benefit shall be paid to the Participant's Beneficiary in a lump sum equal to the value of a death benefit payable to an assumed spouse the same age as the Participant. (iii) Death After Commencement of Benefits. If a Participant dies after commencement of benefits, a survivor benefit will be paid only if, and to the extent provided for, under the form of benefit elected by the Participant. (b) For all Participants who are first elected to the Board on or prior to November 30 1994, the survivor benefit shall be as follows: (i) If a Participant's death occurs prior to commencement of the Supplemental Retirement Benefit, the Participant's Beneficiaries shall receive the death benefit described below unless the Participant's Beneficiary elects to receive the death benefits provided for in Section 4.1(a)(i) in lieu of this benefit. The death benefit will be determined by the Participant's Years of Service, including Years of Service after November 30, 1994, at death as set forth in the schedule below: YEARS OF MONTHLY ANNUAL SERVICE BENEFIT BENEFIT 1 $ 291.67 $ 3,500 2 583.33 7,000 3 875.00 10,500 4 1,166.67 14,000 5 and over 1,458.33 17,500 The death benefits shall be paid to the Beneficiary in equal monthly installments for the period of one hundred eighty (180) months without interest. Payments shall commence on the tenth day of the month following receipt by the Committee of proof of Participant's death. (ii) Death After Commencement of Benefits. a) A Participant who did not elect to receive the Supplemental Retirement Benefit in the grandfathered form as provided for in Section 5.4, and dies at any time after severance from service on the Board and after the commencement of the Supplemental Retirement Benefit, the Participant's Beneficiary shall receive a survivor benefit to the extent provided for under the form of benefit elected by the Participant. b) A Participant who elected to receive the Supplemental Retirement Benefit in the grandfathered form as provided for in Section 5.4 and dies at any time after severance from service on the Board and after the commencement of the Supplemental Retirement Benefit, the Participant's Beneficiaries shall receive the balance, if any, of the 180-month Supplemental Retirement Benefit. Receipt by the Participant's Beneficiaries of the benefit under this subparagraph shall be in lieu of all other survivor benefits under this Plan. 4.2 Suicide. In the event a Participant commits suicide within one (1) year of initially entering this Plan, no benefits shall be payable hereunder to the Participant's Beneficiaries. ARTICLE V RETIREMENT BENEFITS 5.1 Benefit. Upon severance of service on the Board, each Participant shall be entitled to receive, at the time specified in Section 5.3 below, a Supplemental Retirement Benefit, the amount of which will be determined by the Participant's Years of Service on the Plan Anniversary Date immediately preceding or coinciding with his severance date as set forth below: YEARS OF MONTHLY ANNUAL SERVICE BENEFIT BENEFIT 1 $ 291.67 $ 3,500 2 583.33 7,000 3 875.00 10,500 4 1,166.67 14,000 5 and over 1,458.33 17,500 5.2 Form of Payment. The Supplemental Retirement Benefit shall be paid in the basic form provided below unless the Participant elects in the calendar year prior to retirement or termination an Actuarial Equivalent form of benefit provided in this section. Participants elected to the Board prior to November 30, 1994, may elect a grandfathered form of benefit as provided in Section 5.4 in lieu of any other form of benefit. (a) Normal Form of Benefit Payment. The normal form of payment shall be a single-life annuity for the lifetime of the Participant. (b) Actuarial Equivalent Forms of Benefit. (i) A joint and survivor annuity with payments continued to the survivor at an amount equal to two-thirds (2/3) of the Participant's benefits. (ii) A joint and survivor annuity with payments continued to the survivor at an amount equal to the Participant's benefits. 5.3 Commencement of Benefit Payment. (a) Outside Directors. The Supplemental Retirement Benefit shall be paid to an outside director Participant commencing on the tenth (10th) day of the month immediately following the later of age sixty-five (65) or severance from service on the Board as an outside director. (b) Inside Directors. The Supplemental Retirement Benefit shall be paid to an inside director Participant commencing on the tenth (10th) day of the month immediately following severance from service on the Board. 5.4 Grandfathered Form of Benefit. A Participant first elected to the Board prior to November 30, 1994, may elect a grandfathered form of benefit. This grandfathered form of benefit shall be paid in 180 equal monthly installments in an amount set forth in Section 5.1. The election shall be made prior to the Participant's termination. ARTICLE VI BENEFICIARY DESIGNATION 6.1 Beneficiary Designation. The Primary Beneficiary shall be the Participant's spouse. Each Participant, in the event the Participant's spouse predeceases the Participant or if the Participant is unmarried, shall have the right, at any time, to designate any person or persons as Beneficiary or Beneficiaries (both principal as well as contingent) to whom payment under this Plan shall be made in the event of death prior to complete distribution to Participant of the benefits due Participant under the Plan. 6.2 Amendments, Marital Status, No Participant Designation. Any Beneficiary designation form may be changed by a Participant by the filing of a written form prescribed by the Committee. The filing of a new Beneficiary designation form will cancel all Beneficiary designations previously filed. Any finalized divorce or marriage (other than common law) of a Participant subsequent to the date of fling of a Beneficiary designation form shall automatically revoke the prior designation. If a Participant fails to designate a Beneficiary as provided above, or if the Beneficiary designation is revoked by marriage or divorce, without execution of a new designation, or if all designated Beneficiaries predecease the Participant or die prior to complete distribution of the Participant's benefits, then Participant's designated Beneficiary shall be deemed to be the person or persons surviving the Participant in the first of the following classes in which there is a survivor, share and share alike: (a) the Participant's surviving spouse; (b) the Participant's children, except that if any of the children predecease the Participant but leaves issue surviving, the issue shall take by right of representation; (c) the Participant's personal representative (executor or administrator). 6.3 Effect of Payment. The payment to the Beneficiary shall completely discharge Employer's obligations under this Plan. ARTICLE VII TERMINATION, SUSPENSION OR AMENDMENT OF PLAN 7.1 Termination, Suspension or Amendment of Plan. The Board may, in its sole discretion, terminate or suspend this Plan at any time or from time to time, in whole or in part. Either the Board or the Committee may amend this Plan at any time or from time to time. Any amendment may provide different benefits or amounts of benefits from those herein set forth. However, no such termination, suspension or amendment shall adversely affect the benefits of Participants vested therein prior to such action, the benefits of any Participant who has retired, or the Beneficiary of any Participant who has died. 7.2 Change in Control. Notwithstanding Section 7.1 above, in the event of a Change in Control, neither the Board nor the Committee may terminate this Plan with regard to current Participants. No amendment may be made to the Plan following a Change in Control which would adversely affect the benefits of current Participants, the benefits of any Participant who has retired, or the Beneficiary of any Participant who has died. The Plan shall continue to operate and be effective with regard to all current or retired Participants and their Beneficiaries as of the date of the Change in Control. ARTICLE VIII ADMINISTRATION 8.1 Committee; Duties. This Plan shall be administered by a Committee which shall consist of not less than three (3) nor more than five (5) persons appointed by the Board. Members of the Committee may be Participants under this Plan. The Committee shall have the authority to make, amend, interpret and enforce all appropriate rules and regulations for the administration of this Plan and decide or resolve any and all questions including interpretations of this Plan, as may arise in connection with the Plan. A majority vote of the Committee members shall control any decision. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit and may from time to time consult with counsel who may be counsel to the Employer. Subject to Article IX, the decision or action of the Committee in respect of any questions arising out of, or in connection with, the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan. 8.2 Indemnity of Committee. To the extent permitted by applicable law, the Employer shall indemnify, hold harmless and defend the Committee against any and all claims, loss, damage, expense or liability arising from any action or failure to act with respect to this Plan, provided that the Committee was acting in accordance with the applicable standard of care. The indemnity provisions set forth in this Article shall not be deemed to restrict or diminish in any way any other indemnity available to the Committee members in accordance with the Article or By-laws of the Company. ARTICLE IX CLAIMS PROCEDURE 9.1 Claim. Any person claiming a benefit, requesting an interpretation or ruling under the Plan, or requesting information under the Plan shall present the request in writing to the Committee which shall respond in writing as soon as practicable. 9.2 Denial of Claim. If the claim or request is denied, the written notice of denial shall state: (a) the reason for denial, with specific reference to the Plan provisions on which the denial is based; (b) a description of any additional material or information required and an explanation of why it is necessary; and (c) an explanation of the Plan's claim review procedure. 9.3 Review of Claim. Any person whose claim or request is denied or who has not received a response within thirty (30) days may request review by notice given in writing to the Committee. The claim or request shall be reviewed by the Committee who may, but shall not be required to, grant the claimant a hearing. On review, the claimant may have representation, examine pertinent documents, and submit issues and comments in writing. 9.4 Final Decision. The decision on review shall normally be made within sixty (60) days. If an extension of time is required for a hearing or other special circumstances, the claimant shall be notified, and the time limit shall be one hundred twenty (120) days. The decision shall be in writing and shall state the reason and the relevant Plan provisions. All decisions on review shall be final and bind all parties concerned. ARTICLE X MISCELLANEOUS 10.1 Source of Funding. The rights of a Participant, or his Beneficiary, to benefits under this Plan shall be solely those of an unsecured creditor of the Employer. The benefits provided by this Plan shall be paid from the general funds of the Employer. The Employer, in its sole discretion, may procure insurance or other property to be used to offset the Employer's cost of these benefits. It is expressly agreed and understood that any assets acquired or held by the Employer in connection with the liabilities assumed by it pursuant to this Plan shall be and remain the sole property of, the Employer; that a Participant shall have no ownership rights of any nature with respect thereto, and that such property shall not be deemed to be held under any trust for the benefit of a Participant or Beneficiary, or to be security for the performance of the obligations of the Employer, but shall be, and remain a general, unpledged and unrestricted asset of the Employer. 10.2 Unsecured General Creditor. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or claims in any property or asset of the Employer, nor shall they be Beneficiaries of, or have any rights, claims or interests in any life insurance policies, annuity contracts or the proceeds therefrom owned or which may be acquired by the Employer. Except as may be provided in Section 12.3, such policies, annuity contracts or other assets of the Employer shall not be held under any trust for the benefit of Participants, their Beneficiaries, heirs, successors or assigns, or held in any way as collateral security for the fulfilling of the obligation of the Employer under this Plan. Any and all of the Employer's assets and policies shall be, and remain, the general, unpledged, unrestricted assets of the Employer. The Employer's obligation under the Plan shall be that of an unfunded and unsecured promise to pay money in the future. 10.3 Trust Fund. The Employer shall be responsible for the payment of all benefits provided under the Plan. At its discretion, the Employer may establish one or more trusts, with such trustees as the Board may approve, for the purpose of providing for the payment of such benefits. Such trust or trusts may be irrevocable, but the assets thereof shall be subject to the claims of the Employer's creditors. To the extent any benefits provided under the Plan are actually paid from any such trust, the Employer shall have no further obligation with respect thereto, but to the extent not so paid, such benefits shall remain the obligation of, and shall be paid by, the Employer. 10.4 Nonassignability. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are, expressly declared to be unassignable and nontransferable. No part of the amount payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of Participant's or any other person's bankruptcy or insolvency. 10.5 Governing Law. The provisions of this Plan shall be construed, interpreted and governed in all respects in accordance with the applicable federal law and, to the extent not preempted by such federal law, in accordance with the laws of the State of Idaho without regard to the principles of conflicts of laws. 10.6 Validity. If any provision of this Plan shall be held illegal or invalid for any reason, the remaining provisions shall nevertheless continue in full force and effect without being impaired or invalidated in any way. 10.7 Notice. Any notice or filing required or permitted to be given under the Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail or fax. The notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification. 10.8 Successors. Subject to Section 7.1, the provisions of the Plan shall bind and inure to the benefit of the Employer and its successors and assigns. The term successors as used herein shall include any corporation or other business entity which shall, whether by merger, consolidation, purchase or otherwise acquire all or substantially all of the business and assets of the Employer, and successors of any such corporation or other business entity. 10.9 Payment to Guardian. If a Plan benefit is payable to a minor or a person declared incompetent or to a person incapable of handling the disposition of property, the Committee may direct payment of such Plan benefit to the guardian, legal representative or person having the care and custody of the minor, incompetent or person. The Committee may require proof of incompetency, minority, incapacity or guardianship, as it may deem appropriate, prior to distribution of the Plan benefit. The distribution shall completely discharge the Committee and the Employer from all liability with respect to such benefit. Adopted this 17th day of October, 1994. IDAHO POWER COMPANY By: /s/ Joseph W. Marshall Chairman APPENDIX A CONTRACT OF PARTICIPATION IN THE IDAHO POWER COMPANY SECURITY PLAN FOR BOARD OF DIRECTORS NAME OF PARTICIPANT: DATE OF BIRTH: SECURITY PLAN ENTRY DATE: BENEFICIARY: This Agreement is made and entered into as of the date written hereinbelow by and between Idaho Power Company and . This Agreement is subject to all of the terms of the Idaho Power Company Security Plan for Board of Directors, as amended and restated November 30, 1994 (The "Plan"). By signing this agreement, Participant acknowledges receipt of a copy of the Plan document. PARTICIPANT IDAHO POWER COMPANY BY BY PARTICIPANT CHAIRMAN DATE DATE EX-10.(N)(II) 3 EXECUTIVE ANNUAL INCENTIVE PLAN The Executive Annual Incentive Plan is designed to recognize and reward Company performance relative to pre-established goals. Eligible employees are those executives and managers whose responsibilities enable them to have a significant impact on the Company's business. Eligible participants are approved on an annual basis by the Compensation Committee of the Board of Directors based on recommendations from the Chief Executive Officer. Plan objectives are to: - - Focus attention on the achievement of key annual goals; - - Strengthen understanding and commitment to key business strategies and goals; - - Promote and reinforce teamwork, and unify executive efforts toward accomplishing business strategies and goals; - - Align executive behavior with shareholder interests, and encourage thinking like an owner; - - Provide annual awards which are commensurate with performance; and - - Encourage accountability for business results, and responsiveness to the competitive environment. The Plan contemplates that the Compensation Committee will establish a performance threshold which must be met before any awards are paid. Final awards will be based on actual performance relative to pre- determined goals. For 1995, the performance threshold is a certain earnings per share level. Performance goals will be established each year by the Compensation Committee and will be: - - Aligned with shareholder interests and the Company's strategic plan to enhance shareholder value; - - Controllable by participants (as much as possible), and achievable with extra "stretch" and effort; - - Measurable and quantifiable, and "outcome-" versus "process-" oriented; - - Balanced with other performance goals, so that achieving a goal does not negatively affect other performance areas that are important to the Company. In 1995, there are financial and safety goals and sub-goals. There are three financial sub-goals related to: (1) O&M expenditures; (2) capital expenditures; and (3) earnings per share. The safety goals measure Company performance against four sub-goals: (1) cumulative accidents; (2) lost time accidents; (3) lost time hours; and (4) zero fatalities. The Plan contemplates a minimum, target and maximum performance level for each goal, each performance level corresponding with an incentive award that is based on a percentage of base salary. There will be no award for performance levels that are below minimum and no additional award for performance that is above the maximum. Awards will be based on actual results at the completion of the performance period assuming the performance threshold is met. To receive an award, eligible participants must be actively employed at the Company through the last pay period of the fiscal year. EX-10.(N)(III) 4 IDAHO POWER COMPANY 1994 RESTRICTED STOCK PLAN PREAMBLE Effective as of July 1, 1994, Idaho Power Company (the "Company"), has adopted the IDAHO POWER COMPANY 1994 RESTRICTED STOCK PLAN (the "Plan") for the benefit of its eligible employees. ARTICLE I PURPOSE AND ELIGIBILITY 1.1 Purpose. The purpose of the Plan is to award shares of common stock to certain officers and executives ("key employees") of Idaho Power Company (the "Company") [and its wholly-owned subsidiaries] to provide an equity-based incentive program to key employees that encourages retention, facilities alignment of business decisions with shareholder interests and recognizes key employees for outstanding performance. 1.2 Eligibility. Subject to the determination of the Committee described in Section 2.2 herein, all officers and key executives of the Company [and its wholly-owned subsidiaries] shall be eligible to receive awards under the Plan. A person who receives an award under the Plan is referred to herein as a "Participant." ARTICLE II AWARDS 2.1 Shares Available for Awards. The maximum number of shares which may be awarded from time to time under the Plan is 370,000. Shares of common stock awarded under the Plan ("Restricted Shares") shall be authorized but unissued shares of common stock of the Company, treasury shares or shares purchased on the open market. Restricted Shares which are not earned or which are forfeited shall again be available for subsequent awards under the Plan. Such shares may be regranted to key employees who are deemed to be insiders under Section 16 ("Section 16") of the Securities Exchange Act of 1934, as amended (the "Exchange Act") to the maximum extent permitted by the rules thereunder. 2.2 The Committee. All awards made hereunder shall be made to such key employees as shall be determined solely by the Compensation Committee of the Board of Directors of the Company, or such other committee as the Board of Directors shall determine (the "Committee"). The Committee shall consist of not less than two members of the Board of Directors who shall, to the extent required, meet the requirements for disinterested administration as set forth in Rule 16b- 3 of the Exchange Act. The Committee shall have full discretion and exclusive power, subject to the provisions of the Plan, to select and determine the key employees to whom awards are made, the times when awards are made, the number of Restricted Shares granted, the length of the restricted period (the "Restricted Period"), the applicable restrictions, forfeiture provisions, performance criteria, if any, dividend rights, if any, voting rights, if any, and any other rights, terms and conditions it may choose to apply to such awards. The Committee shall have full power and authority to interpret and apply the provisions of the Plan, and to prescribe, amend and rescind such rules and regulations relating to the Plan as it shall deem desirable. Any interpretation, determination or other action taken by the Committee shall be final, binding and conclusive. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or awards made hereunder. 2.3 Awards. (a) The terms of each award, as determined solely by the Committee, shall be set forth in a written agreement (a "Restricted Stock Agreement") duly executed on behalf of the Company and the Participant in such form as the Committee shall from time to time approve. (b) A stock certificate representing the number of Restricted Shares granted to a Participant shall be registered in the Participant's name but shall be held in custody by the Company for the Participant's account. The Participant shall not have the right to vote such Restricted Shares or to receive dividends thereon unless such rights are granted by the Committee. In addition, the following restrictions shall apply: (i) the Participant shall not be entitled to delivery of a certificate until the expiration or termination of the Restricted Period and the satisfaction of performance criteria, if any; (ii) none of the Restricted Shares may be sold, transferred, assigned, pledged, or otherwise encumbered or disposed of during the Restricted Period, other than by will or the laws of descent and distribution; and (iii) all of the Restricted Shares shall be forfeited by the Participant without further obligation on the part of the Company as of the date of the Participant's termination of employment in accordance with the provisions of Section 3.1 hereof prior to the expiration or termination of the Restricted Period. Upon the forfeiture of any Restricted Shares, such forfeited shares shall be transferred to the Company without further action by the Participant. (c) Upon the expiration or termination of the Restricted Period and the satisfaction of performance criteria, if any, the restrictions imposed on the appropriate Restricted Shares shall lapse and a stock certificate for the number of Restricted Shares with respect to which the restrictions have lapsed shall be delivered to the Participant, free of all such restrictions, except any that may be imposed by law or by the applicable Restricted Stock Agreement. Except as provided under Section 5.3 hereof, no payment will be required from the Participant upon the issuance or delivery of any Restricted Shares. 2.4 Section 83(b) Election. A Participant who files an election with the Internal Revenue Service to include the fair market value of any Restricted Shares in gross income while they are still subject to restrictions shall promptly furnish the Company with a copy of such election together with the amount of any federal, state, local or other taxes required to be withheld to enable the Company to claim an income tax deduction with respect to such election. 2.5 Adjustment in Event of Changes in Capitalization. In the event of a recapitalization, stock split, stock dividend, stock combination, exchange of shares, merger, consolidation, acquisition or disposition of property or shares, reorganization, liquidation, or other similar changes or transactions, of or by the Company, the aggregate number of Restricted Shares shall be appropriately adjusted and all provisions of this Plan with respect to the number of Restricted Shares shall also be adjusted. ARTICLE III TERMINATION OF EMPLOYMENT; CHANGE IN CONTROL 3.1 Termination of Employment. Subject to the Committee's right to determine otherwise at the time of grant, upon termination of the Participant's employment with the Company by reason of death or disability, or with approval of the Committee upon retiring from the Company prior to attaining age 62, all unvested Restricted Stock shall immediately vest. Upon termination of employment for any other reason, all unvested Restricted Stock shall be forfeited. 3.2 Change in Control. All unvested Restricted Shares shall vest immediately upon a "change in control". "Change in control" shall mean the earlier of the following to occur: (a) the public announcement by the Company or by any person (which shall not include the Company, any subsidiary of the Company or any employee benefit plan of the Company or of any subsidiary of the Company) ("Person") that such Person, who or which, together with all Affiliates and Associates (within the meanings ascribed to such terms in Rule 12b-2 of the Exchange Act) of such Person, shall be the beneficial owner of twenty percent (20%) or more of the voting stock then outstanding; (b) the commencement of, or after the first public announcement of any Person to commence, a tender or exchange offer the consummation of which would result in any Person becoming the beneficial owner of voting stock aggregating thirty percent (30%) or more of the then outstanding voting stock; (c) the announcement of any transaction relating to the Company required to be described pursuant to the requirements of Item 6(e) of Schedule 14A of Regulation 14A of the Securities and Exchange Commission under the Exchange Act; (d) a proposed change in the constituency of the Board of Directors of the Company such that, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board of Directors of the Company cease for any reason to constitute at least a majority thereof, unless the election or nomination for election by the shareholders of the Company of each new director was approved by a vote of at least two-thirds (2/3) of the directors then still in office who were members of the Board of Directors of the Company at the beginning of the period; or (e) any other event which shall be deemed by a majority of the Committee of the Board of Directors of the Company to constitute a "change in control." ARTICLE IV AMENDMENTS AND TERMINATION 4.1 Amendments. The Board of Directors reserves the right at any time and from time to time, and retroactively if deemed necessary or appropriate by it, to amend in whole or in part, and in any manner, any or all of the provisions of this Plan, provided that no amendment shall make it possible for any part of a Participant's Restricted Shares to be used for or diverted to, purposes other than for the exclusive benefit of Participants or their beneficiaries, except to the extent otherwise provided in this Plan. No actions by the Board of Directors pursuant to this Article IV may be taken if it would cause the Plan to fail to meet the "disinterested administration" requirements set forth in Rule 16b-3 of the Exchange Act to the extent required. 4.2 Termination. The Board of Directors reserves the right to terminate this Plan at any time. No Participant shall accrue any additional benefits under this Plan after the effective date of such termination. ARTICLE V MISCELLANEOUS 5.1 Governing Law. All questions pertaining to the validity, construction and administration of the Plan shall be determined in accordance with the laws of the State of Idaho, without regard to conflicts of laws provisions. 5.2 Nonguarantee of Employment. Nothing contained in this Plan shall be construed as a contract of employment between the Company and any Participant, as a right of any Participant to be continued in the employment of the Company, or as a limitation on the right of the Company to discharge any of its employees, with or without cause. 5.3 Taxes. The Company shall make such provisions and take such steps as it may deem necessary or appropriate for the withholding of all federal, state and local taxes required by law to be withheld with respect to awards of Restricted Shares, and the lapse of restrictions on Restricted shares, including but not limited to (i) deducting the amount required to be withheld from any other amount then or thereafter payable to a Participant, former Participant, beneficiary or legal representative, and (ii) requiring a Participant, former Participant, beneficiary or legal representative to pay to the Company the amount required to be withheld as a condition of the delivery of Restricted Shares. For all purposes of this Plan, the fair market value of common stock shall be determined by the Company in good faith, and such determination shall be binding upon the Participants and all other persons for federal, state and local tax purposes. 5.4 Notices. Each notice relating to this Plan shall be in writing and delivered in person or by certified mail to the proper address. All notices to the Company shall be addressed to it at 1221 West Idaho Street, Boise, Idaho 83707, Attention: Manager of Compensation. All notices to Participants, former Participants, beneficiaries or other persons acting for or on behalf of such persons shall be addressed to such person at the last address for such person maintained in the Company's records. 5.5 Headings. The headings and sub-headings in this Plan are inserted for convenience of reference only and are to be ignored in any construction of the provisions hereof. 5.6 Severability. In case any provision of this Plan shall be held illegal or void, such illegality or invalidity shall not affect the remaining provisions of this Plan, but shall be fully severable, and the Plan shall be construed and enforced as if said illegal or invalid provision had never been inserted herein. DATED this 20th day of December, 1994. IDAHO POWER COMPANY By: /s/ J. W. Marshall J. W. Marshall Chairman of the Board and Chief Executive Officer EX-12 5
Idaho Power Company Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1990 1991 1992 1993 1994 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 69,241 $ 57,872 $ 59,990 $ 84,464 $ 74,930 Income taxes: Income taxes (includes amounts charged to other income and deductions) 26,418 24,321 24,601 38,057 35,307 Investment tax credit adjustment (3,184) (3,177) (1,439) (1,583) (1,064) Total income taxes 23,234 21,144 23,162 36,474 34,243 Income before income taxes 92,475 79,016 83,152 120,938 109,173 Fixed Charges: Interest on long-term debt 50,119 54,370 53,408 53,706 51,173 Amortization of debt discount, expense and premium - net 309 374 392 507 567 Interest on short-term bank loans 1,027 935 647 220 1,157 Other interest 2,259 3,297 1,011 2,023 1,537 Interest portion of rentals 902 884 683 1,077 794 Total fixed charges 54,616 59,860 56,141 57,533 55,228 Earnings - as defined $147,091 $138,876 $139,293 $178,471 $164,401 Ratio of earnings to fixed charges 2.69X 2.32X 2.48X 3.10X 2.98X
EX-12.(A) 6
Idaho Power Company Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1990 1991 1992 1993 1994 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 69,241 $ 57,872 $ 59,990 $ 84,464 $ 74,930 Income taxes: Income taxes (includes amounts charged to other income and deductions) 26,418 24,321 24,601 38,057 35,307 Investment tax credit adjustment (3,184) (3,177) (1,439) (1,583) (1,064) Total income taxes 23,234 21,144 23,162 36,474 34,243 Income before income taxes 92,475 79,016 83,152 120,938 109,173 Fixed Charges: Interest on long-term debt 50,119 54,370 53,408 53,706 51,173 Amortization of debt discount, expense and premium - net 309 374 392 507 567 Interest on short-term bank loans 1,027 935 647 220 1,157 Other interest 2,259 3,297 1,011 2,023 1,537 Interest portion of rentals 902 884 683 1,077 794 Total fixed charges 54,616 59,860 56,141 57,533 55,228 Suppl increment to fixed charges* 1,969 1,599 2,487 2,631 2,622 Total supplemental fixed charges 56,585 61,459 58,628 60,164 57,850 Supplemental earnings - as defined $149,060 $140,475 $141,780 $181,102 $167,023 Supplemental ratio of earnings to fixed charges 2.63X 2.29X 2.42X 3.01X 2.89X * Explanation of increment: Interest on the guaranty of American Falls Reservoir District Bonds and Milner Dam Inc. Notes which are already included in operating expense.
EX-12.(B) 7
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) 1990 1991 1992 1993 1994 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 69,241 $ 57,872 $ 59,990 $ 84,464 $ 74,930 Income taxes: Income taxes (includes amounts charged to other income and deductions) 26,418 24,321 24,601 38,057 35,307 Investment tax credit adjustment (3,184) (3,177) (1,439) (1,583) (1,064) Total income taxes 23,234 21,144 23,162 36,474 34,243 Income before income taxes 92,475 79,016 83,152 120,938 109,173 Fixed Charges: Interest on long-term debt 50,119 54,370 53,408 53,706 51,173 Amortization of debt discount, expense and premium - net 309 374 392 507 567 Interest on short-term bank loans 1,027 935 647 220 1,157 Other interest 2,259 3,297 1,011 2,023 1,537 Interest portion of rentals 902 884 683 1,077 794 Total fixed charges 54,616 59,860 56,141 57,533 55,228 Preferred dividend requirements 5,685 6,663 7,611 8,547 10,682 Total fixed charges and preferred dividends 60,301 66,523 63,752 66,080 65,910 Earnings - as defined $147,091 $138,876 $139,293 $178,471 $164,401 Ratio of earnings to fixed charges preferred dividends 2.44X 2.09X 2.18X 2.70X 2.49X
EX-12.(C) 8
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) 1990 1991 1992 1993 1994 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 69,241 $ 57,872 $ 59,990 $ 84,464 $ 74,930 Income taxes: Income taxes (includes amounts charged to other income and deductions) 26,418 24,321 24,601 38,057 35,307 Investment tax credit adjustment (3,184) (3,177) (1,439) (1,583) (1,064) Total income taxes 23,234 21,144 23,162 36,474 34,243 Income before income taxes 92,475 79,016 83,152 120,938 109,173 Fixed Charges: Interest on long-term debt 50,119 54,370 53,408 53,706 51,173 Amortization of debt discount, expense and premium - net 309 374 392 507 567 Interest on short-term bank loans 1,027 935 647 220 1,157 Other interest 2,259 3,297 1,011 2,023 1,537 Interest portion of rentals 902 884 683 1,077 794 Total fixed charges 54,616 59,860 56,141 57,533 55,228 Suppl increment to fixed charges* 1,969 1,599 2,487 2,631 2,622 Supplemental fixed charges 56,585 61,459 58,628 60,164 57,850 Preferred dividend requirements 5,685 6,663 7,611 8,547 10,682 Total supplemental fixed charges and preferred dividends 62,270 68,122 66,239 68,711 68,532 Supplemental earnings - as defined $149,060 $140,475 $141,780 $181,102 $167,023 Supplemental ratio of earnings to fixed charges and preferred dividends 2.39X 2.06X 2.14X 2.64X 2.44X * Explanation of increment: Interest on the guaranty of American Falls Reservoir District Bonds and Milner Dam Inc. Notes which are already included in operating expense.
EX-21 9 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 5. Stellar Dynamics, an Idaho Corporation EX-23 10 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 Registration Statement No. 33-56071 of Idaho Power Company on Form S-8 of our report dated January 31, 1995 (which expresses an unqualified opinion and includes an explanatory paragraph relating to the change in the Company's method of accounting for income taxes and other postretirement benefits) appearing in this Annual Report on Form 10-K of Idaho Power Company for the year ended December 31, 1994. DELOITTE & TOUCHE LLP Portland, Oregon March 7, 1995 EX-27 11 FIN, DATA SCHEDULE FOR 10-K
UT This Schedule Contains Summary Financial Information 1,000 DEC-31-1994 JAN-01-1994 DEC-31-1994 12-MOS Per-book 1,656,643 18,034 144,620 372,519 0 2,191,816 94,031 358,931 220,838 673,800 0 132,456 679,738 0 13,468 55,000 517 0 0 0 636,837 2,191,816 543,658 34,243 393,993 428,236 115,422 12,160 127,582 52,652 74,930 7,398 67,532 69,594 51,173 125,657 1.80 1.80
-----END PRIVACY-ENHANCED MESSAGE-----