-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, S8D4ax1UybdyEf75y8/ZoPaen/NS4cGaoTPewezQn2RQ2zyZd14lR+9wLBLwZcrf dXEI7yov84c5kjwNrFqq4w== 0000049648-97-000005.txt : 19970317 0000049648-97-000005.hdr.sgml : 19970317 ACCESSION NUMBER: 0000049648-97-000005 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970314 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-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-03198 FILM NUMBER: 97556413 BUSINESS ADDRESS: STREET 1: 1221 W IDAHO ST STREET 2: PO BOX 70 CITY: BOISE STATE: ID ZIP: 83707 BUSINESS PHONE: 2083882200 10-K405 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K405 (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, 1996 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 (I.R.S. Employer jurisdiction of Identification No.) incorporation or organization) 1221 W. Idaho Street, 83702-5627 Boise, Idaho (Address of principal (Zip Code) executive offices) 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 New York and Pacific value) 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. X Aggregate market value of voting stock held by nonaffiliates (January 31, 1997) $1,195,163,000 Number of shares of common stock outstanding at February 28, 1997 37,612,351 Documents Incorporated by Reference: Part III, Item 10 Portions of the definitive proxy statement of the Registrant to be filed pursuant to Item 11 Regulation 14A for the 1996 Annual Meeting of Shareowners to be held on May 7, 1997. Item 12 Item 13 TABLE OF CONTENTS PART I Page Item 1. Business 2 The Company 2 Power Supply 5 Fuel 10 Water Rights 10 Regulation 11 Environmental Regulation 12 Rates 13 Construction Program 15 Financing Program 16 Item 2. Properties 17 Item 3. Legal Proceedings 19 Item 4. Submission of Matters to a Vote of Security Holders 22 Executive Officers of the Registrant 22 Part II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters 23 Item 6. Selected Financial Data 24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 26 Item 8. Financial Statements of Supplementary Data 40 Item 9. Changes in and Disagreements with Accountants and Financial Disclosure 63 Part III Item 10. Directors and Executive Officers of the Registrant* 63 Item 11. Executive Compensation* 63 Item 12. Security Ownership of Certain Beneficial Owners and Management* 63 Item 13. Certain Relationships and Related Transactions* 63 Part IV Item 14. Exhibits, Fianancial Statement Schedule and Reports on Form 8-K 63 Signatures 70 *Incorporated by Reference. The exhibit index is located on Page 71. This document contains 145 pages. PART I ITEM 1. BUSINESS THE COMPANY This Form 10-K contains "forward-looking statements" intended to qualify for safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-K at Part II, Item 7. Management's Discussion and Analysis of financial condition and Results of Operations - Forward-Looking Information. Forward- looking statements are all statements other than statements of historical fact, including without limitation those that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," and similar expressions. 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 754,000 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 changing weather, precipitation and streamflow 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 operating results are more dependent upon general regulatory, economic, temperature and competitive conditions and less on precipitation 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. As of December 31, 1996, the Company supplied electric energy to 352,487 general business customers and employed 1,645 people in its operations (1,565 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, 1996, total system electric revenues from residential customers accounted for 35 percent of the Company's total operating revenues. Commercial customers with less than 1,000 kW demand including street lighting customers accounted for 19 percent, industrial customers with 1,000 kW demand and over accounted for 19 percent and irrigation customers accounted for 11 percent. Public utilities and interchange arrangements accounted for 12 percent and other operating revenues accounted for 4 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. Subsidiaries - The Company has six wholly-owned subsidiary companies: Ida-West Energy Company (Ida-West), Idaho Energy Resources Co. (IERCo), Idaho Utility Products Company (IUPCo), IDACORP, Inc., Idaho Power Resources Corporation (IPRC) and Stellar Dynamics, Inc. (Stellar). Ida-West was formed in 1989 to participate through partnership interests in cogeneration and small power production (CSPP) projects. Ida-West holds investments in thirteen operating hydroelectric plants with a total generating capacity of approximately 72 megawatts (MW). In January 1996, Ida-West made an investment by acquiring all of the outstanding bonds that were issued to finance three hydroelectric plants known collectively as the Friant Power Project. This project is located at the U.S. Bureau of Reclamation's Friant Dam on the headwaters of the San Joaquin River in Madera and Fresno Counties, California. It has an aggregate generating capacity of 27.4 MW. The project is owned and operated by Friant Power Authority, a quasi-governmental entity consisting of six irrigation districts, a water district, and a municipal utility district. In November 1996, Ida-West purchased an interest in five hydroelectric projects located in Shasta County, California, with a total generating capacity of 11.2 MW. Ida-West acquired the projects through a limited liability company in which it holds a 50 percent interest. In addition, Ida-West has an interest in the Hermiston Power Project, a 460 MW, gas-fired cogeneration project to be located near Hermiston, Oregon. Ida-West has been responsible for managing all permitting and development activities relating to the project since its inception in 1993, and has obtained all permits necessary for construction and operation of the project. The partnership is exploring various alternatives for marketing the project's output. Project financing for construction costs would be non-recourse to Idaho Power. The Company has purchased all of the power from five Idaho hydroelectric entities of Ida-West, totaling approximately $9.0 million. Ida-West continues to actively seek to develop new projects. At December 31,1996 the Company's total investment in Ida-West was $21.8 million. (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 power plant near Rock Springs, Wyoming (see "Fuel"). As of December 31, 1996, the Company's total investment in IERCo was $4.4 million. IDACORP, Inc. was organized in 1986 to pursue a non-regulated diversification program. At the end of 1996 IDACORP was participating in five affordable housing programs which provide a return primarily by reducing federal income taxes through tax credits and tax depreciation benefits. As of December 31, 1996, the total investment in IDACORP was $6.2 million. IPRC, is a wholly-owned subsidiary, incorporated in March 1996 to provide guidance, resources, and long-term strategic planning to projects or business proposals that are not subject to regulation by the FERC and the state regulatory commissions. IPRC's goals are to establish, acquire, and expand business operations in sustainable infrastructure technology and services including energy, water, waste disposal, telecommunications, and information systems. The Company has invested approximately $4.0 million in development and acquisition activities in IPRC. IPRC has a Memorandum of Understanding signed by Idaho Power and representatives from the government of Indonesia on March 6, 1996, clearing the way to conduct a detailed feasibility study on using solar photovoltaic (PV) technology, micro hydroelectric systems, and other renewable energy systems to provide electricity to various locations throughout Indonesia's complex of islands. IPRC is currently reviewing results of the completed business plan. If the project is deemed workable and receives the required approvals, IPRC would likely begin to develop services in late 1997. In October 1996, IPRC acquired a majority interest in Applied Power Corporation (APC), a Lacey, Washington-based, company that designs, supplies, and distributes photovoltaic (PV) systems. Stellar was formed in 1995 to commercialize the Company's extensive expertise in control technology for electric substations and power plants. Today, the market focus lies in the integration of complex control and automation systems for both the electric utility sector and industrial applications. Stellar also provides design and engineering for complete electric substations. The geographic market for Stellar is mainly in the western U.S. with some emphasis in the remaining U.S., Canada and abroad. As of December 31, 1996, total investment in Stellar was $0.8 million. IUPCO was formed in 1983 to develop and market products to the utility industry. The Company's total investment was $0.4 million in IUPCO at December 31, 1996. Research and Development and Renewable Energy Sources - During 1996, the Company spent approximately $1.8 million on research and development of which $1.5 million was through the Company's membership in Electric Power Research Institute (EPRI). EPRI's mission is to discover, develop and deliver advances in science and technology. Some of the projects benefits to the Company include: electrification technologies, power quality, electric transportation systems, EMF assessment/risk management and air quality issues. The Company also has an internal research and development effort called the Emerging Technology (ET) Program. The ET program was established to maintain an active and coordinated response to new technology of interest to the Company. In 1992, the Company joined Southern California Edison, the U.S. Department of Energy and others in retrofitting an existing 10- megawatt central receiver solar thermal experimental power plant now called Solar Two near Barstow, California. The Company will have contributed $630,500 through 1997 and the EPRI will contribute an additional $630,500 of matching funds, bringing the Company's credited contribution to approximately $1.3 million. Solar Two was first synchronized to Southern California Edison's system in May 1996. The main benefit the Company will receive by participating in this project is valuable experience and knowledge in solar plant design, construction and operation. The Company offers Photovoltaics for basic electric service on small loads at remote sites as an alternative to either line extensions for grid service or the use of on-site, fossil-fuel generators. The customer pays a monthly fee to receive electric service from a solar PV system designed, installed, owned, and maintained by Idaho Power. The service, 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. To date, Idaho Power has installed 32 solar photovoltaic (PV) systems. All of these systems are operating as designed. In 1996, the Company's newly-formed subsidiary, IPRC, acquired a majority interest in APC, a company that would partner with interested electric utilities to provide energy services to remote locations within their service territories. This company would work on behalf of the utilities to offer solar PV energy systems at the lowest possible cost to the consumer. While the domestic utility market is promising in itself, IPRC is also pursuing international opportunities for its renewable energy expertise (see "Subsidiaries"). Energy Efficiency - The Company continues to promote the efficient use of electrical energy. 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 1996, the Company expended $4.4 million on its various energy- efficiency programs. 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, below normal precipitation created drought conditions reducing reservoir storage. In 1995 and 1996, however, the Company's service territory experienced above average water years. The system peak demand for 1996 was 2,661 megawatts set on July 9, 1996. Peak demand for 1995 and 1994 were 2,393 and 2,392 megawatts respectively. The following table sets forth the total energy sources of the Company for the last three years: Total Energy Sources (000's of MWH) 1996 % 1995 % 1994 % Generation - net station output - Hydro 10,713.5 58 9,277.2 58 6,213.2 40 Coal-fired 4,783.0 26 4,591.9 29 7,221.8 46 Purchased and interchange 3,067.3 16 2,155.9 13 2,287.0 14 Total 18,563.8 100 16,025.0 100 15,722.0 100 Historically, under normal water conditions, the Company's hydro system supplies approximately 57 percent, thermal generation accounts for 34 percent and purchased power and other interchanges contribute the remaining 9 percent of total system requirements. Preliminary 1997 reports indicate the mountain snowpack is well above normal for this time of year and the carryover reservoir storage throughout the Snake River Basin is close to 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. Purchased power expenses fluctuated during the three-year period reflecting necessity purchases from neighboring utilities due to the 1994 drought. Purchased power expenses were lower in 1995, reflecting better hydro conditions for the year. In 1996, purchased power expenses were higher as the Company took advantage of low wholesale market prices due to the abundance of hydro generation in the West, which allowed the Company to remarket this energy to others. Increased purchases from CSPP projects also increased purchased power expenses in 1996. The Company periodically updates its load and resource projections and now expects total Company energy requirements over the next 10 years to grow at an annual rate of 1.8 percent. 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, PacifiCorp, The Montana Power Company and Sierra Pacific Power Company (SPPCo). 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 Western Systems Coordinating Council, the Western Systems Power Pool, the Northwest Power Pool, the Western Regional Transmission Association and the Northwest Regional Transmission Association. Competition - Competition is increasing in the electric utility industry. The National Energy Policy Act of 1992, FERC rule-makings, state initiatives, customer demands, and pending legislation at the national and state level, all indicate increasing wholesale and ultimately retail competition. With its low energy production costs, the Company believes it is well-positioned to enter a more competitive environment and is taking action to preserve its low- cost competitive advantage. The legislatures and/or the regulatory commissions in several states, and at a national level, 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. While proposals have been advanced, the Idaho Legislature has not yet addressed retail wheeling but the Idaho Public Utilities Commission (IPUC) has conducted an issues dialogue process and established workshops for discussing retail wheeling issues among affected parties in 1996 (see "Regulation"). In response to increased competition in the industry, the potential ability of retail customers to choose their electric provider and the apparent deregulation of the electric power industry, the Company has adjusted 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 in the market. 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 and other utilities, the Company has access to all the major electric systems in the West. Marketing Business Unit - To accommodate its customers and allow itself to compete in the rapidly evolving competitive market, the Company formed a Marketing Business Unit in January 1997. This new business unit will be responsible for all purchases and sales of electric energy, market research and the planning and implementation of marketing strategies. There are three core components to the new business unit: Product development, which is responsible for creating and commercializing all new energy products and services; Supply and logistics, which is responsible for energy supply aggregation, delivery and risk management; and Sales, which is responsible for market aggregation and sales of energy products and service offerings to its customers. The new business unit will offer a comprehensive program of energy supply and management services, and will expand its current product line to include several new energy service options. Existing and planned product offerings include both firm and interruptible short-term, month-to-month, and long-term customized energy supply options and multiple pricing options including fixed, floating, and indexed. The business unit's service options will include energy scheduling, energy reserve products, risk management, load shaping and following service, summary billing and energy analysis for multiple customer facilities, and multi-fuel management service. Fuel management services will provide a means to partially or completely outsource the administrative and operational duties associated with managing all or part of our customers energy supply requirements. Southwest Intertie Project (SWIP) - The Company has been investigating the feasibility of constructing and operating a new transmission line that could serve as a major path for regional transfers of power between the Northwest and desert Southwest. SWIP is a proposed 500-mile, 500- kV transmission line that would interconnect the Company's system with utilities in California and the Southwest. In December 1994, the US Bureau of Land Management (BLM) 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. The Company intends to retain up to a 20 percent ownership in the 1,200 megawatt line. The Company and interested parties have completed ownership allocation and negotiations for the execution of the Memorandum of Agreement (MOA). When the MOA is executed, the Company will require each party to pay its share of the approximately $8.5 million expended for environmental permitting, right-of-way acquisition, and related development activities. The SWIP owners will then form an Executive Committee, with voting rights proportional to each share of the project. The Executive Committee will oversee development activities for the SWIP and related projects. As of December 31, 1996, the Company's Southwest Intertie Project (SWIP) is on hold. At the current time, an order from the Public Service Commission of Nevada is still pending, that would allow Nevada Power to participate in the project. The final development of SWIP may be impacted by regional efforts to form an independent transmission and operator to eliminate market control and provide improved transmission access for all system users (see "Independent Grid Operator"). Transmission Services - The Company has long had an informal open-access transmission policy and is experienced in providing reliable, high quality, economical transmission service. The Company provides various firm and non-firm wheeling services for several surrounding utilities. In July 1996, the Company filed an open-access tariff with the FERC, in compliance with Order 888. The terms and conditions of the tariff were approved for use beginning in 1997. 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 is advantageous both in providing transmission service and reaching a broad power sales market. The Company is a member of both the Western Regional Transmission Association and the Northwest Regional Transmission Association. These associations will help facilitate transmission access and planning throughout the power system. Independent Grid Operator - Recently a group of seven investor-owned Northwest electric companies, including Idaho Power, BPA, and five public electric entities signed a memorandum of understanding that will create an independent transmission grid operator called "IndeGO". IndeGO will ensure non-discriminatory, open-access to electricity transmission facilities in compliance with recent FERC rulings. The memorandum of understanding is an agreement to investigate the feasibility of developing a regional transmission grid which would be operated by an entity independent of power market interests. It is believed that the formation of such an entity will facilitate the operation of an evolving competitive electric power market. Operating as one regional system, the utilities will be able to increase the efficiency of transmission operations and provide improved access for all system users. IndeGo is envisioned as an independent transmission company not controlled by any individual power market participant. It is anticipated that IndeGO will operate as a single control area, with pricing based on a single zonal tariff applied equally to all users including the participating companies. IndeGO will not own transmission facilities initially, but will be responsible for the operation of main transmission grid facilities 230 kilovolts (kV) or more that are owned by the participating utilities. The area encompassed by the IndeGo has over 20,000 miles of transmission lines accounting for about 97% of the northwest grid. The group plans to file the IndeGo proposal with FERC by July 1997, and anticipates operation would commence as early as 1999. If the FERC's approval arrives by April 1998, an IndeGo Board and Site Procurement could be expected by July 1998. Forecast Energy and Peak Demand - The following tables show how the Company expects to meet its forecast energy and peak demand requirements through 2001 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) 1997 1998 1999 2000 2001 Generation capability 2,681 2,681 2,681 2,681 2,681 Less net peak load 2,438 2,493 2,541 2,590 2,635 Plus contract power(b) 313 313 313 313 313 Peak capability margin 556 501 453 404 359 Percent capability margin(c) 22.8% 20.1% 17.8% 15.6% 13.6% (a) Based upon median hydro conditions. (b) Sum of exchange and CSPP contracts. (c) Capability margin divided by the net peak load. Annual Energy Capability (000's of MWH) (a) 1997 1998 1999 2000 2001 Generation Capability 15,097 15,220 15,279 15,313 15,471 Contracts: Cogeneration and small power production 832 832 832 832 832 Annual firm load (15,572) (15,905) (15,965) (16,040) (16,271) Energy capability margin 357 147 146 105 32 Percent (b) 2.3% 0.9% 0.9% 0.7% 0.2% (a) Forecast based upon average of 68 historical water conditions. (b) Energy capability margin divided by the generating capability. During the 1997-2001 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 and through purchases of power from neighboring utilities or marketing entities. 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 67 CSPP projects on-line as of December 31, 1996, is $55.9 million. During 1996, the Company purchased 776.4 million kilowatt-hours of power from these private developers at a blended price of 5.6 cents per kilowatt-hour. With the potential deregulation of the electric utility industry and a more competitive power supply marketplace, the Company believes that resource acquisition policies must avoid burdening the Company and its customers with unnecessary future power supply costs. In 1993, the Company requested, and in 1995 received approval, to lower published CSPP rates for new projects. In addition, the IPUC determined that negotiated rates for future CSPP projects larger than 1 megawatt (MW) should be tied more closely to values determined in the Company's integrated resource planning process. In a subsequent order issued on September 4, 1996, the IPUC further recognized the coming changes by limiting the contract term which a new CSPP project larger than 1 MW could request to a maximum of five years (see "Rates"). Firm Wholesale Power Sales - The Company has firm wholesale power sales contracts with several entities in the West. These contracts are for various amounts of energy, ranging from 6 to 75 average megawatts, and are of various lengths presently scheduled to expire between 1997 and 2009. The Company is actively marketing this power to other entities as it becomes available. FUEL The Company, through Idaho Energy Resources Co., owns a one-third interest in the Bridger Coal Company which owns 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 and provides for delivery of coal over a 51-year period that began in 1974. The original contract of 41 years was extended for 10 years on January 1, 1996. (See Item 2 "Properties".) The Jim Bridger Coal Mine has sufficient reserves to provide coal deliveries pursuant to the sales agreement. 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 (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. 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 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 acquired under applicable provisions of state law for all waters used in its hydroelectric generating facilities. In addition, the Company holds water rights for domestic, irrigation, commercial and other necessary purposes related to other land and facility holdings within the state. The exercise and use of all of these water rights are subject to prior rights and, with respect to certain hydroelectric facilities, the Company's water rights for power generation are subordinated to future upstream diversions of water for irrigation and other recognized consumptive uses. Over time, increased irrigation development and other consumptive diversions have resulted in some reduction in the stream flows available to fulfill the Company's water rights at certain hydroelectric generating facilities. In reaction to these reductions, the Company initiated and continues to pursue a course of action to determine and protect its water rights. As part of this process, the Company and the state of Idaho signed the Swan Falls agreement on October 25, 1984 which provided a level of protection for the Company's hydropower water rights at specified plants by setting minimum stream flows and establishing an administrative process governing the future development of water rights that may affect the Company's hydroelectric generation. In 1987, Congress passed and the President signed into law House Bill 519. This legislation permitted implementation of the Swan Falls agreement and further provided that during the remaining term of certain of the Company's project licenses that the relationship established by the agreement would not be considered by the FERC as being inconsistent with the terms of the Company's project licenses or imprudent for the purposes of determining rates under Section 205 of the Federal Power Act. The FERC entered an order implementing the legislation on March 25, 1988. In addition to providing for the protection of the Company's hydropower water rights, the Swan Falls agreement contemplated the initiation of a general adjudication of all water uses within the Snake River basin. In 1987, the director of the Idaho Department of Water Resources filed a petition in state district court asking that the court adjudicate all claims to water rights, whether based on state or federal law, within the Snake River basin. A commencement order initiating the Snake River Basin Adjudication was signed by the court on November 19, 1987. This legal proceeding was authorized by state statute based upon a determination by the Idaho Legislature that the effective management of the waters of the Snake River basin required a comprehensive determination of the nature, extent and priority of all water uses within the basin. The adjudication is expected to continue past the turn of the century. The Company has filed claims to its water rights within the basin and is actively participating in the adjudication to ensure that its water rights and the operation of its hydroelectric facilities 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 under the regulatory jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the FERC, the IPUC, the Oregon Public Utilities Commission (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 1997 and during the period 1998-2001 will total approximately $0.7 million and $29.1 million, respectively. Mitigation of environmental concerns due to relicensing of hydro facilities will be a major portion of these expenditures. The Company also anticipates spending approximately $21 million a year in operating expenses for environmental facilities during the 1997-2001 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's legislation and its effects upon the Company and its rate payers. The Company's coal- fired plants in Nevada and Oregon already meet the federal emission rate standards for sulfur dioxide (SO2) and the Company's coal-fired plant in Wyoming meets that state's even more stringent SO2 regulations. The Company anticipates no material adverse effect upon its operations. The Company has entered into a joint arrangement with PacifiCorp and Black Hills Corporation 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 super saturating 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 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 has also installed and operates water quality monitors at the Milner and Twin Falls hydroelectric projects, in order to meet compliance standards for water quality. 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 1996, the investment in these facilities was $12.2 million and the operation of these facilities pursuant to the FERC License 1971 cost approximately $2.2 million annually. 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, 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 TSCA for the continued use of equipment containing PCBs. The Company has a program to make the 200-plus substations on its system non-PCB. While the Company's use of equipment containing PCBs falls well within the federal 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. Total Company costs for the disposal of PCBs from the Company's system were $1.3 million, $0.4 million and $0.9 million for 1994, 1995 and 1996 respectively. RATES Idaho Jurisdiction Since 1993, the IPUC has permitted Idaho Power to use a PCA mechanism in its Idaho jurisdiction. The PCA enables the Company to collect or to refund a portion of the difference between net power supply costs actually incurred and those allowed in the Company's base rates. The current balance is adjusted monthly as actual conditions are compared to the PCA forecasted net power supply costs. For the period May 1996 through May 1997, the IPUC approved tariffs, reducing Idaho jurisdictional PCA rates by $25.7 million (5.9 percent), including the true-up for the PCA period May 1995 through May 1996. The reduction reflects anticipated lower power supply costs in the coming year due to above-average hydroelectric generating conditions. The 1996 PCA forecast reflects power supply costs below those established for PCA expenses in the Company's last general rate proceeding. At December 31, 1996, the Company had recorded as a deferred asset and reduction in operating expenses $11.4 million of power supply costs above those projected in the 1996 forecast. On January 31, 1995, the Company received IPUC Order No. 25880, which authorized $17.2 million in general rate relief, representing a 4.2 percent overall increase in Idaho retail rates. The relief was based on an 11.0 percent allowed return on equity and an overall rate of return of 9.2 percent. The increase in Idaho retail rates went into effect on February 1, 1995. It also allows Idaho Power to realign its overall rate structure to a price, more closely associated with the cost of serving the different customer classes. On May 24, 1995, Idaho Power filed another application with the IPUC to increase rates in its Idaho jurisdiction. In August 1995, the IPUC issued an order authorizing the Company to increase its Idaho retail rates on an annual basis by $3.8 million (0.9 percent). This increase was uniform to all customer classes, as well as to special contract customers. The Company originally applied for a $6.3 million (l.5 percent) increase to recover capital costs and related expenses associated with the construction of a new 43.5 megawatt (MW) power plant at its Twin Falls hydro facility, along with additional plant investments at the Swan Falls hydro facility since the filing of its last general rate case. The major issue in this case was whether the reduced power supply costs resulting from the inclusion of the Twin Falls hydro expansion would be recognized explicitly through a reduction in base energy rates or implicitly through the PCA. The Company reached a compromise with the IPUC staff on the overall revenue requirement and agreed to recognize benefits up front in base rates, instead of flowing the benefits through the PCA. As a result, the Company's original $6.3 million request was reduced by $1.9 million. The effect on projected Company earnings is only 10 percent of this amount ($190,000), since all but 10 percent of the power supply cost reduction would have been passed through to Idaho customers in the next PCA adjustment. The IPUC action enabled the Company to begin recovering the capital costs of a plant addition within weeks of the plant becoming operational. 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, the IPUC issued an order on January 31, 1995, approving lower published CSPP rates for new projects. In addition, the IPUC determined that negotiated rates for future CSPP projects larger than 1 MW should be tied more closely to values determined in the Company's integrated resource planning process. In a subsequent order issued on September 4, 1996, the IPUC further recognized the coming changes by limiting the contract term which a new CSPP project larger than 1 MW could request to a maximum of five years. On August 3, 1995, Idaho Power filed a proposal with the IPUC to support the Company's organizational redesign. In response to the Company's proposal, the IPUC approved a Settlement that authorizes the Company to defer and amortize costs related to reorganization in return for a general rate freeze through the end of 1999. In addition, the Settlement allows for the accelerated amortization of regulatory liabilities associated with accumulated deferred investment tax credits (ADITCs) to provide a minimum 11.50 percent return on actual year-end common equity for the Idaho jurisdiction. The new rate freeze and the accelerated amortization of regulatory liabilities associated with ADITCs gives the Company time to pursue and to implement its efficiency and growth initiatives with the assurance of at least a reasonable level of financial performance apart from the need to change customer prices. The terms and conditions of the Settlement will remain in effect through 1999. Under the Settlement, when the Company's actual earnings in a given year exceed an 11.75 percent return on year- end common equity, the Company will refund 50 percent of the excess to its Idaho retail customers. In 1996 the Company set aside approximately $4.9 million for refund to its Idaho customers. Other important points in the Settlement are: (1) the Company may accelerate a maximum of $30 million of regulatory liabilities associated with ADITCs over the five-year period; (2) the Company will not be allowed to increase its Idaho general rates prior to January 1, 2000, except under special conditions as defined in the Settlement; and (3) Idaho Power agrees that its quality of service will not decline as a result of corporate reorganization. The Company has received approval from the Idaho State Tax Commission and the Internal Revenue Service on the accounting treatment for the tax credits. No accelerated ADITC was recognized in 1995 or 1996. Oregon Jurisdiction - In response to the Company's April 1995 application, the OPUC granted $1.5 million in drought-related rate relief. The OPUC order allows recovery of the $1.5 million through the continued application of an existing increase authorized in July 1993 (for 1992 drought relief). The rate increase will remain in effect for approximately 34 months beginning in July 1995. The Company had deferred, with interest, increased power supply costs between May 1994 and December 31, 1994. In May 1995, Idaho Power filed an application with the OPUC seeking general rate relief of approximately $3.4 million, or a 16.65 percent increase. The Company later negotiated a Settlement Stipulation with the OPUC staff, the Company's Oregon industrial customers, and the Citizens Utility Board of Oregon. The Settlement grants Idaho Power a $1.3 million general rate increase for its Oregon retail customers. The OPUC Settlement became effective December 5, 1995. Other Jurisdictions - In 1996, the Company did not file any applications for rate relief before the FERC or in its Nevada retail jurisdiction. In July 1996, the Company filed an open-access tariff with the FERC, in compliance with Order 888. The terms and conditions of the tariff were approved for use beginning in 1997 (see "Transmission Services"). CONSTRUCTION PROGRAM The Company's construction program for the 1997-2001 period (excluding allowances for funds used during construction) is presently estimated to require cash funds of approximately $421.7 million as follows: 1997 1998-2001 (a) (Millions of Dollars) Generating Facilities: Hydro $3.9 $32.0 Thermal 8.2 38.2 Total generating facilities 12.1 70.2 Transmission lines and substations 12.0 55.4 Distribution lines and substations 37.8 160.0 General 22.4 51.8 Total cash construction 84.3 337.4 AFUDC 1.1 4.1 Total construction including AFUDC (b) $85.4 $341.5 (a) Escalation rates were not applied to construction expenditures because the level of expenditures has been capped. (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. 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 and (2) purchased power and exchange agreements with other utilities or other power suppliers. 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 estimate of capital requirements and sources of capital is $412.7 million outlined as follows: 1997 1998-2001 (Millions of Dollars) Capital Requirements: Net cash construction expenditures $84.3 $337.4 Conservation expenditures 1.3 - Other cash expenditures (0.3) (10.0) Total $85.3 $327.4 Sources of Capital: Internal generation $72.4 $359.6 Short-term bank loans - Net 13.3 29.3 First mortgage bonds - (60.7) Debt repayment (0.1) (0.3) Common stock - - Cash investments (increase) (0.3) (0.5) Total (a) $85.3 $327.4 (a) Does not include subsidiary financings. These estimates are subject to constant revision in light of changing economic, regulatory and environmental factors and patterns of 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, 5 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. 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, 1996, net earnings were 6.52 times. Additional preferred stock may be issued when earnings for twelve consecutive months within the preceding fifteen months are at least equal to l.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, 1996, the actual preferred dividend earnings coverage was 3.11 times. If the dividends on the shares of Auction Preferred Stock were to reach the maximum allowed, the preferred dividend earnings coverage would be 2.84 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 4,642 miles of high voltage transmission lines; 21 step-up transmission substations located at power plants; 17 transmission substations; 7 transmission switching stations; and 194 energized distribution substations (excludes mobile substations and dispatch centers). 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 Capacity kW Capacity kW Expiration kW 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 1,398,000 1,166,900 2005 Swan Falls 25,547 25,000 2010 American Falls 112,420 92,340 2025 Cascade 14,000 12,420 2031 Twin Falls 54,300 52,737 2041 Milner 59,448 59,448 2038 Other Generating Plants: Other Hydroelectric 10,400 11,300 Jim Bridger (Coal-Fired 693,333 678,077 Valmy (Coal-Fired Station) 260,650 260,650 Boardman (Coal-Fired Station) 53,000 53,000 At December 31, 1996, the composite average ages of the principal parts of the Company's system, based on dollar investment, were: production plant, 17.1 years; transmission system and substations, 18.2 years; and distribution lines and substations, 13.9 years. The Company considers its properties to be well maintained and in good operating condition. The Company owns in fee all of its principle 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. 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. Idaho Power is actively pursuing the relicensing of its hydroelectric projects, a process that will continue for the next 10 to 15 years. The Company submitted its first applications for license renewal to the FERC in December 1995. These first applications seek renewal of the Company's licenses for its Bliss, Upper Salmon Falls, and Lower Salmon Falls Hydroelectric Projects. The Company is also in the process of submitting a draft application for license renewal for its Shoshone Falls Hydroelectric Project. Although various federal requirements and issues must be resolved through the licensing reviewing 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 licensing renewal. 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 holds investments in thirteen operating hydroelectric plants with a total generating capacity of 72 MW. ITEM 3. LEGAL PROCEEDINGS On December 6, 1991, a complaint entitled Nez Perce Tribe, Plaintiff, vs. 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. 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 sought through its Amended Complaint to secure actual, incidental, consequential and punitive damages in amounts to be proven at trial. On September 18, 1992, the Company filed a motion for summary judgment in the hope of securing dismissal of the Tribe's action. The District Court issued an Order of Reference sending the case to a Federal Magistrate. On July 30, 1993, the Magistrate issued a Report and Recommendation that the District Judge granted that portion of the Company's motion for summary judgment regarding the loss of fish. 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. 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 dated July 30, 1993, to grant the Company's motion for summary judgment as to all other claims. On September 28, 1994, the Federal District Judge issued an Order rejecting the Second Report and Recommendation of the Magistrate 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. The Company and the Tribe have reached agreement on a settlement of this case (Settlement Agreement). The Settlement Agreement has been approved by the Nez Perce Tribal Executive Committee and the Company's Board of Directors. Under the terms of the Settlement Agreement, the Company will pay the Nez Perce Tribe $11.5 million in the following manner: - $5 million at which time the Tribe would move for the dismissal of, with prejudice, their legal action against the Company. - $1,625,000 each year for the next four years beginning in 1998. All payments under the Settlement Agreement will be made in 1996 dollars, which allows for adjusted future inflation within a minimum range of 3 percent and a maximum of 7 percent. The first payment of $5.0 million plus inflation adjustment will be paid sometime in 1997. On July 12, 1996 the IPUC issued Order No 26513, and on August 5, 1996, the OPUC issued Order No. 96-207 approving capitalization of their respective jurisdictional share of the $11.5 million. The parties requested Bureau of Indian Affairs (BIA) approval of the Settlement Agreement. However, on November 21, 1996, the Portland Area Director of the BIA issued a decision stating that the Settlement Agreement did not have to be approved by the BIA. On December 19, 1996, the Company filed an administrative appeal of the BIA's decision and have since requested and been granted a stay of said appeal pending pursuit of an alternate federal approval. As a result of the BIA decision, the Tribe and the Company explored alternatives to BIA approval that would help assure the ultimate enforceability of the Settlement Agreement. The parties agreed to request that the Federal District Court for the District of Idaho approve the Settlement Agreement. The Tribe and the Company, by motion, stipulated that the Ninth Circuit Court of Appeals remand the case to the Federal District Court for the District of Idaho, which motion was granted by the Ninth Circuit on February 6, 1997. The parties will now seek Federal District Court approval of the Settlement Agreement. This matter has been previously reported in Form 10-K dated March 16, 1992, March 12, 1993, March 10, 1994, March 9, 1995, March 14, 1996 and other reports filed with the Commission. On November 30, 1995, a complaint entitled Idaho Power Company vs. Cogeneration, Inc., Case No. 98467, was filed by the Company in the District Court of the Fourth Judicial District of the State of Idaho. The proceeding involves an effort by the Company to terminate a firm energy sales agreement (FESA) for a small hydroelectric generating plant. As required by PURPA and the orders of the IPUC, on January 7, 1992, the Company entered into a 35-year FESA with Cogeneration, Inc., to purchase the output of a 43-megawatt hydroelectric generating project known as the Auger Falls Project. The FESA for the Auger Falls Project was approved by the IPUC on January 27, 1992. The FESA required that on or before January 1, 1994, Cogeneration, Inc., post cash or cash equivalent security in the amount of approximately $1.9 million to assure performance of the FESA. Cogeneration, Inc., failed to provide the security amount. Consistent with the FESA, the Company filed a petition for declaratory order with the IPUC requesting that the FESA be terminated as a result of Cogeneration, Inc.'s breach. Cogeneration, Inc., cross petitioned claiming that its failure to perform was excused by the occurrence of an event of force majeure. On April 17, 1995, the IPUC issued its order finding that Cogeneration, Inc.'s failure to post the cash security on January 1, 1994, was a default under the FESA and further finding that the posting of the liquid security was required by the public interest. Based upon those findings, the IPUC ordered Cogeneration, Inc., to post the cash security prior to May 1, 1995. Cogeneration, Inc., failed to comply with the Commission's order and has never posted the $1.9 million amount required by the FESA. After the IPUC's order became final and non-appealable, the Company filed a complaint for declaratory relief in the District Court of the Fourth Judicial District. The Complaint sought a determination by the district court that Cogeneration, Inc.'s failure to provide the cash security and its violation of the IPUC's orders requiring that it expeditiously provide the cash security constituted material breaches of the FESA. The Company asked the district court to find that as a matter of law Idaho Power was entitled to either terminate or rescind the FESA. In response to the Company's complaint, Cogeneration, Inc., filed counterclaims alleging that the Company, by seeking to terminate the FESA, had breached the FESA and was attempting to monopolize the electric generation market and drive Cogeneration, Inc., out of business. Cogeneration, Inc., alleged damages for breach in excess of $50 million and requested that any damages be trebled under the anti-trust laws. On November 30, 1995, the district judge, by memorandum decision found that Cogeneration, Inc., had materially breached the FESA and the Company was entitled to either rescind or terminate the FESA. On February 16, 1996, Cogeneration, Inc., dismissed its anti- trust claims against the Company, and on February 23, 1996, the Idaho Supreme Court granted Cogeneration, Inc.'s request for an expedited appeal of the district court's decision establishing an accelerated briefing schedule and scheduling oral argument for May 10, 1996. On August 12, 1996, the Idaho Supreme Court determined that the District Court's decision that Cogeneration, Inc., had breached the FESA was premature. On February 10, 1997, Cogeneration, Inc. filed an amended Complaint restating its previous claims, requesting a jury trial rather than the court trial it had previously requested and raising several new allegations and claims. While the outcome of litigation is never certain, Idaho Power believes that Cogeneration, Inc.'s counterclaims are without merit. This matter has been previously reported in Form 10-K dated March 14, 1996 and other reports filed with the Commission. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None EXECUTIVE OFFICERS OF THE REGISTRANT The names, ages and positions of all of the executive officers of the Company are listed below along with their business experience during the past five years. Officers are elected annually by the Board of Directors. There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was elected. Name, Age and Position Business Experience During Past Five (5) Years J. W. Marshall, 58 Appointed August 18, 1989. Chairman of the Board and Chief Executive Officer L. R. Gunnoe, 61 Appointed July 12, 1990. President and Chief Operating Officer J. LaMont Keen, 44 Appointed March 14, 1996. Mr. Keen Vice President, Chief was Vice President and Chief Financial Officer Financial Officer prior to March 14, and Treasurer 1996. Douglas H. Jackson, 60 Appointed July 12, 1990. Vice President - Retail Services C. N. Olson, 47 Appointed July 11, 1991. Vice President -Corporate Services J. B. Packwood, 53 Appointed July 11, 1996. Mr. Executive Vice President Packwood was Vice President-Power Supply prior to July 11, 1996. Richard Riazzi, 42 Appointed January 9, 1997. Mr. Vice President - Riazzi was Vice President, Corporate Marketing and Sales Marketing (1995-1996) and was Vice President of the Energy Group (1991- 1995) for Equitable Resources, Inc. Robert W. Stahman, 52 Appointed July 13, 1989. Vice President, General Counsel and Secretary 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 year ended December 31, 1994, 1995 and 1996, cash dividends per share of common stock were $1.86. At the July 1996 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 Company's common stock is listed on the New York and Pacific Stock Exchanges. The following table indicates the reported high and low sales price of the Company's common stock for the years 1995 and 1996, as reported by The Wall Street Journal as composite tape transactions. The Company's year-end common stock price was $31 1/8 per share and the number of stockholders of record at December 31, 1996, was 29,333. 1995 Quarters Common Stock, $2.50 par 1st 2nd 3rd 4th value: High $26 $26 3/4 $27 7/8 $30 Low 23 3/8 23 5/8 23 7/8 27 1/4 Dividends paid per share (cents) 46.5 46.5 46.5 46.5 ______________________________ 1996 Quarters Common Stock, $2.50 par 1st 2nd 3rd 4th value: High $31 1/4 $31 1/8 $34 1/4 $32 Low 27 1/4 27 5/8 29 3/4 29 7/8 Dividends paid per share (cents) 46.5 46.5 46.5 46.5 ITEM 6. SELECTED FINANCIAL DATA SUMMARY OF OPERATIONS 1996 1995 1994 (Thousands of Dollars) Revenues: General business $ 484,145 $ 461,594 $ 457,354 Sales to other utilities 70,222 57,418 59,923 Other revenues 24,078 26,609 26,381 Total revenues 578,445 545,621 543,658 Expenses: Purchased power 69,038 54,586 60,216 Fuel expense 63,334 54,691 94,888 Other operation and maintenance 168,539 169,959 154,742 Depreciation 69,705 67,415 60,202 Taxes other than income taxes 20,658 22,979 23,945 Total expenses 391,274 369,630 393,993 Income from operations 187,171 175,991 149,665 Other income and deductions - Net (12,534) (14,356) (12,160) Interest charges - Net 56,995 55,014 52,652 Income taxes 52,092 48,412 34,243 Cumulative effect of accruing unbilled revenues - - - Net Income 90,618 86,921 74,930 Dividends on preferred stocks 7,463 7,991 7,398 Earnings on common stock 83,155 78,930 67,532 Dividends on common stock 69,924 69,941 69,594 Net change to retained earnings $ 13,231 $ 8,989 $ (2,062) CAPITALIZATION (000 ommitted) % % % First mortgage bonds $ 527,000} $ 470,000} $ 490,000} Other long-term debt 211,550} 48 202,618} 45 203,206} 46 Preferred stock 106,975 7 132,181 9 132,456 9 Common stock (incl. prem. & exp.) 452,486} 452,948} 452,962} Retained earnings 242,088} 45 229,827} 46 220,838} 45 Total capitalization $1,540,099 100 $ 1,487,574 100 $ 1,499,462 100 Short-term borrowings outstanding $ 54,016 $ 53,020 $ 55,000 FINANCIAL STATISTICS Income from operations as a percent of total revenues 32.4% 32.3% 27.5% Times interest charges earned: Before tax 3.49 3.40 3.01 After tax 2.58 2.54 2.38 Market-to-book ratio 169% 165% 131% Payout ratio 84% 89% 103% Return on year-end 11.97% 11.56% 10.02% common equity Common stock data: Earnings per average share outstanding $ 2.21 $ 2.10 $ 1.80 Dividends declared per $ 1.86 $ 1.86 $ 1.86 share Book value per share $ 18.47 $ 18.15 $ 17.91 Average shares outstanding (000 ommitted) 37,612 37,612 37,499 Common shareowners 29,333 30,795 26,209 *Includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kwh (000,000 omitted) 13,035 11,983 12,194 Number of customers 352,487 340,708 330,308 Residential customer data: Number of customers 292,145 282,797 274,187 Average kwh use per customer 13,828 13,475 14,159 Average rate per kwh (cents) 5.07 5.16 4.83 OTHER STATISTICS Total assets (000 omitted) $2,295,337 $ 2,241,753 $2,191,816 Gross plant additions (000 omitted) $ 94,120 $ 87,297 $ 107,667 Number of employees (full-time) 1,565 1,522 1,609 1993 1992 1991 Revenues: General Business $ 428,658 $ 431,818 $ 409,454 Sales to other utilities 86,525 42,000 52,563 Other revenues 25,219 24,274 21,176 Total Revenues 540,402 498,092 483,193 Expenses: Purchased power 45,361 58,496 51,210 Fuel expense 87,855 96,710 75,161 Other operation and maintenance 164,388 137,547 151,593 Depreciation 58,724 59,823 57,597 Taxes other than income taxes 22,129 20,562 21,168 Total expenses 378,457 373,138 356,729 Income from operations 161,945 124,954 126,464 Other income and deductions - Net (12,984) (11,133) (9,453) Interest charges - Net 53,991 52,935 56,901 Income taxes 36,474 23,162 21,144 Cumulative effect of accruing unbilled revenues - - - Net Income: 84,464 59,990 57,872 Dividends of preferred stocks 6,009 5,516 4,904 Earnings on common stock 78,455 54,474 52,968 Dividends on common stock 67,959 65,043 63,197 Net change to retained earnings $ 10,496 (10,569) (10,229) CAPITALIZATION (000 omitted) % % % First mortgage bonds $ 490,000} $ 485,000} $ 435,000} 48 Other long-term debt 203,780} 47 216,948} 49 194,981} Preferred stock 132,751 9 107,874 7 108,191 8 Common stock (incl. prem. & exp.) 439,467} 412,998} 356,824} Retained earnings 222,900} 44 212,404} 44 222,973} 44 Total capitalization $1,488,898 100 $1,435,224 100 $1,317,969 100 Short-term borrowings outstanding $ 4,000 $ 6,000 $ 48,500 FINANCIAL STATISTICS Income from operations as a percent of total revenues 30.0% 25.1% 26.2% Times interest charged earned: Before tax 3.14 2.50 2.34 After tax 2.50 2.08 1.98 Market-to-book ratio 170% 159% 168% Payout ratio 87% 120% 119% Return on year-end common equity 11.84% 8.71% 9.14% Commmon stock data: Earnings per average share outstanding $ 2.14 $ 1.55 $ 1.56 Dividends declared per share $ 1.86 $ 1.86 $ 1.86 Book value per share $ 17.86 $ 17.28 $ 17.07 Average shares outstanding (000 ommitted) 36,675 35,116 33,977 Common Shareowners 26,870 27,834 28,069 *includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kwh (000,000 ommitted) 11,406 11,606 11,266 Number of customers 317,772 307,567 297,808 Residential customer data: Number of customers 263,682 255,022 246,689 Average kwh use per customer 14,587 13,856 14,845 Average rate per kwh (cents) 4.82 4.80 4.72 OTHER STATISTICS Total assets (000 omitted) $2,097,417 $1,862,307 $1,773,674 Gross plant additions (000 omitted) $ 116,972 $ 118,920 $ 135,904 Number of employees (full-time) 1,654 1,638 1,626 1990 1989 1988 Revenues: General business $ 401,350 $ 397,974 $ 362,050 Sales to other utilities 44,368 70,749 32,175 Other revenues 19,217 27,438 18,096 Total revenues 464,935 496,161 412,321 Expenses: Purchased power 43,923 43,845 43,723 Fuel expense 77,606 77,127 74,528 Other operation and maintenance 134,126 132,114 116,230 Depreciation 55,114 53,092 51,691 Taxes other than income taxes 20,752 20,213 19,301 Total expenses 331,521 326,391 305,473 Income from operations 133,414 169,770 106,848 Other income and deductions - Net (11,666) (10,005) (6,552) Interest charges - Net 52,605 52,997 50,762 Income taxes 23,234 42,041 13,558 Cumulative effect of accruing unbilled revenu - - - Net Income 69,241 84,737 49,080 Dividends on preferred stocks 4,279 4,285 4,293 Earnings on common stock 64,962 80,452 44,787 Dividends on common stock 63,197 62,177 61,159 Net change to retained earnings 1,765 18,275 (16,372) CAPITALIZATION (000 omitted) % % % First mortgage bonds $ 367,500} $ 377,000} $ 392,000} Other long-term debt 194,159} 46 165,551} 47 164,426} 47 Preferred stock 58,761 5 58,923 5 59,126 5 Common stock (incl. prem. & exp.) 358,078} 357,986} 357,866} Retained earnings 233,241} 49 231,476} 48 213,201} 48 Total capitalization $1,211,739 100 $1,190,936 100 $1,186,619 100 Short-term borrowings outstanding $ 48,280 $ 31,000 $ 37,000 FINANCIAL STATISTICS Income from operations as a percent of total revenue 28.7% 34.2% 25.9% Times interest charges earned: Before tax 2.72 3.30 2.18 After tax 2.29 2.53 1.93 Market-to-book ratio 148% 169% 138% Payout ratio 97% 77% 137% Return on year-end common equity 10.99% 13.65% 7.84% Common stock data: Earnings per average share outstanding $ 1.91 $ 2.37 $ 1.32 Dividends declared per share $ 1.86 $ 1.83 $ 1.80 Book value per share $ 17.40 $ 17.35 $ 16.81 Average shares outstanding (000 omitted) 33,977 33,977 33,977 Common shareowners 29,080 30,291 32,225 *Includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kwh (000,000 omitted) 11,086 11,069 10,563 Number of customers 291,800 284,363 279,529 Residential customer data: Number of customers 241,790 236,008 232,650 Average kwh use per customer 14,281 14,923 14,364 Average rate per kwh (cents) 4.73 4.69 4.47 OTHER STATISTICS Total assets (000 omitted) $1,680,110 $1,625,120 $1,608,935 Gross plant additions (000 omitted) $ 80,117 $ 62,094 $ 64,358 Number of employees (full-time) 1,574 1,528 1,500 1987 1986 Revenues: General business $ 343,899 $ 336,480 Sales to other utilities 35,447 54,987 Other revenues 15,251 17,394 Total revenues 394,597 408,861 Expenses: Purchased power 30,234 31,849 Fuel expense 65,934 31,260 Other operations and maintenace 114,235 114,407 Depreciation 50,929 49,308 Taxes other than income taxes 19,072 18,539 Total expenses 280,404 245,363 Income from operations 114,193 163,498 Other income and deductions - Net (13,115) (17,064) Interest charges - Net 51,843 51,206 Income taxes 27,246 50,923 Cumulative effect of accruing unbilled revenues (11,302) - Net Income 59,521 78,433 Dividends on preferred stock 4,298 10,553 Earnings on common stock 55,223 67,880 Dividends on common stock 61,159 59,755 Net change to retained earnings (5,936) 8,125 CAPITALIZATION (000 Omitted) % % First mortgage bonds $ 407,000} $ 432,000} Other long-term debt 160,003} 47 153,887} 47 Preferred stock 59,238 5 59,403 5 Common stock (incl. prem. & exp.) 357,797} 357,708} Retained earnings 229,573} 48 235,509} 48 Total capitalization $1,213,611 100 $1,238,507 100 Short-term borrowings outstanding $ 4,000 $ 5,000 FINANCIAL STATISTICS Income from operations as a percent of total revenues 28.9% 40.0% Times interest charges earned: Before tax 2.76* 3.40 After tax 2.10* 2.46 Market-to-book ratio 127% 150% Payout ratio 111% 88% Return on year-end common equity 9.40% 11.44% Common stock data: Earnings per average share outstanding $ 1.63* $ 2.00 Dividends declared per share $ 1.80 $ 1.76 Book value per share $ 17.29 $ 17.46 Average shares outstanding (000 omitted) 33,977 33,961 Common shareowners 33,733 34,456 *Includes cumulative effect of accounting change CUSTOMER DATA General business data: Energy sales - kwh (000,000 omitted) 10,175 9,938 Number of customers 276,249 274,129 Residential customer data: Number of customers 230,486 228,921 Average kwh use per customer 13,785 14,541 Average rate per kwh (cents) 4.34 4.21 OTHER STATISTICS Total assets (000 omitted) $1,602,311 $1,621,887 Gross plant additions (000 omitted) $ 38,929 $ 50,257 Number of employees (full-time) 1,521 1,524 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 six wholly-owned subsidiaries: Idaho Energy Resources Company (IERCo); Ida-West Energy Company (Ida-West); IDACORP, Inc.; Idaho Utility Products Company (IUPCo); Idaho Power Resources Corporation (IPRC); and Stellar Dynamics, Inc. (Stellar). This discussion uses the terms Idaho Power and the Company interchangeably to refer to Idaho Power Company and its subsidiaries. FORWARD-LOOKING INFORMATION - Certain matters discussed in this report are "forward-looking statements" intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Such statements address future plans, objectives, expectations, and events or conditions concerning various matters such as capital expenditures, earnings, litigation, rate and other regulatory matters, liquidity and capital resources, and accounting matters. Actual results in each case could differ materially from those currently anticipated in such statements, by reason of factors such as electric utility restructuring, including ongoing state and federal activities; future economic conditions; legislation; regulation; competition; and other circumstances affecting anticipated rates, revenues and costs. EARNINGS PER SHARE AND BOOK VALUE - Earnings per share of common stock in 1996 totaled $2.21, up from the $2.10 earned in 1995 and the $1.80 earned in 1994. The 1996 earnings equate to a 12.0 percent earned return on year-end common equity, as compared to the 11.6 percent earned in 1995 and the 10.0 percent earned in 1994. At December 31, 1996, the book value per share of common stock was $18.47. A number of factors have affected earnings per share over the last three years: improved hydro conditions, a strong service territory economy, continued customer growth, and resolution of rate cases in 1995. In 1996, under terms and conditions of the regulatory settlement with the Idaho Public Utilities Commission (IPUC), the Company set aside approximately $4.9 million for refund to its Idaho customers. This provision for refund reduced reported earnings per share by approximately eight cents (See "Regulatory Settlement"). RESULTS OF OPERATIONS - Customer Growth and Energy Demand - New customer growth continued at a brisk pace with the Company adding 11,779 new general business customers during 1996. This increase marks 1996 as the Company's second best year in terms of customer growth. This, added to 1994's record-setting 12,536 new customers, and 1995's 10,400, combined for a three-year total of 34,715 (10.9 percent) new general business customers. During 1996, Idaho Power added 9,348 residential customers, 2,090 commercial customers, and 339 irrigation customers. Higher summer temperatures led to increases in energy demand during 1996. In contrast, 1995 had milder winter and summer weather conditions which reduced loads for heating and cooling, while the wet, cool spring reduced irrigation loads. Economy - Idaho's economy continued to outperform the nation in terms of non-agricultural employment growth. Idaho's overall non- agricultural employment growth advanced at a 4.1 percent annual rate through the first eight months of 1996. This compares to 1995's 3.2 percent growth rate. Employment in the manufacturing, construction, service and trade industries posted gains of 1.8 percent, 12.5 percent, 7.6 percent and 3.7 percent, respectively, for the first eight months of 1996. The state's economic performance has fluctuated during the periods presented, but Idaho's economy continues to create jobs and attract new companies to the state. Revenues - For the three-year period 1994-1996, the Company received an average 85 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 customer category were as follows: - - 35 percent from residential customers; - - 30 percent from a combination of irrigation customers, street lighting customers, and commercial customers with less than 1,000 kW demand; - - 19 percent from industrial customers with demand of 1,000 kW or greater; - - 11 percent from off-system sales to other utilities and interchange arrangements; and - - 5 percent from miscellaneous revenue The Company's energy sales to general business customers, increased 6.9 percent in 1994 and 8.8 percent in 1996, but decreased 1.7 percent in 1995. In 1995, residential usage was down l.5 percent, due to the mild weather, despite an increase in customers during the year. Also contributing to the 1995 decline was wet spring weather that reduced irrigation kilowatt sales in that year by 25.2 percent. The year 1996 saw energy sales increase in all customer classes. Residential and commercial sales increased 6.0 percent and 9.3 percent, respectively, due to increased customers, a strong economy, and weather factors providing more heating-and cooling- degree days during the year. Irrigation sales increased 21.0 percent with a return to more normal weather patterns during the summer months. Industrial sales also grew by 7.0 percent in 1996. General business revenues represent approximately 84 percent of the Company's total operating revenues. General business revenues were $457.4 million in 1994, $461.6 million in 1995, and $484.1 million in 1996. The 1995 increase reflects rate increases during the year and increased sales to some industrial customers. The 1996 increase comes primarily from residential, $8.0 million (4.2 percent), commercial $5.0 million (4.9 percent), and irrigation, $6.7 million (12.1 percent). The average residential customer used 14,159 kwh in 1994, 13,475 kwh in 1995, and 13,828 kwh in 1996. These averages reflect changes due to varied weather patterns. Off-System Sales - Off-system sales are composed of firm sales (long-term contracts) and opportunity sales made on a when-available basis. The volume and price of these latter sales depend on the Company's firm energy demand, hydroelectric generating conditions in its service territory, and market conditions throughout the West. Revenues from off-system sales declined $26.6 million in 1994. Off-system revenues declined an additional $2.5 million in 1995, but rose by $12.8 million in 1996. In 1995 and 1996, improved hydroelectric generating conditions created an increase in off-system sales, while drought conditions reduced sales in 1994. In 1995, improved hydroelectric conditions created an increase in off-system sales. However, reduced demand on the off-system market cut the prices of such sales. Expenses - Total operating expenses rose $15.5 million in 1994, decreased by $24.4 million in 1995, and increased $21.6 million in 1996. The increase in expense for 1994 reflects drought conditions, which increased the Company's reliance on thermal generation and purchased power. The decrease in 1995 resulted from improved hydroelectric operating conditions, which lowered purchased power and fuel expense. In 1996, purchased power expense was up $14.5 million. This increase reflects economy purchases made to take advantage of low wholesale market prices during the year and increased purchases from cogeneration and small power production (CSPP) projects which also experienced strong hydroelectric generating conditions. The low market prices were a result of the abundance of hydro generation in the West, which allowed the Company to remarket this energy to others. In 1995, with the return to more normal hydro conditions, purchased power expense was lower when compared to 1994, a year in which drought conditions were experienced. Fuel expense also increased in 1996 by $8.6 million. The largest increase came in the fourth quarter, mainly due to the operation of the Valmy coal-fired plant. A reduction in spot market coal prices allowed the Company to generate additional energy and to be competitive in the off-system market. In 1995, the Company experienced good seasonal hydroelectric conditions, thereby reducing its reliance on thermal generation. The Power Cost Adjustment (PCA) component of expenses was up $19.3 million when comparing 1995 to 1994. However, for 1996, the PCA was down $14.1 million, compared to 1995. The PCA mechanism reduces expenses when power supply costs are above forecast, and increases expenses when power supply costs are below forecast (see "PCA discussion"). All other operation and maintenance expenses fluctuated during the three-year period, with a cumulative increase of $9.5 million. These variations are due, in part, to increases in payroll and benefits, changes in operation and maintenance due to water conditions, as well as reconstruction of Company facilities damaged or destroyed by natural causes. Depreciation expense was up for the three-year period by $10.9 million (18.7 percent), due to a greater plant investment base, while taxes other than income taxes decreased $1.5 million (6.6 percent). Interest Charges - Interest charges on long-term debt fluctuated during the three- year period, with a cumulative decrease of $1.5 million. This decrease reflects the maturity, early redemption, and issuance of several series of first mortgage bonds at reduced or lower interest rates. Additionally, the Company took advantage of lower interest rates to refinance several existing higher-cost Pollution Control Revenue Bond issues with new lower-cost Pollution Control Revenue Bond issues. Refinancing in 1996 reduced interest requirements by $2.2 million over 1995. These amounts will fluctuate as two series of these bonds are variable rate, while the third is fixed. Also, this refinancing lengthened the maturity of these bonds from those originally issued. During 1996, the Company redeemed the 8.375% Series of Serial Preferred Stock and retired at maturity the 5.25% Series of First Mortgage Bonds. This was accomplished by issuing two series of medium term notes. This financing reduced the Company's overall cost of capital (see Note 5 of "Notes to Consolidated Financial Statements"). Interest on short-term debt rose during the three-year period due to fluctuating interest rates, as well as to a higher level of short-term borrowings. At December 31, 1996, the Company's short- term borrowings totaled $54.0 million (see Note 7 of "Notes to Consolidated Financial Statements"). Precipitation and Streamflows - Idaho Power analyzes precipitation and streamflow conditions based on the effect on Brownlee Reservoir, the primary water source for the three Hells Canyon hydroelectric power plants. In normal years, these three projects combine to produce about half of the Company's generated electricity. In 1994, drought conditions reduced the amount of water flowing into the Company's reservoir system. However, in 1995 and 1996, Idaho Power's service territory experienced above average water years. Between April and July 1996, the Company recorded 8.3 million acre feet (MAF) of water flowing into Brownlee Reservoir. This compares with 1994's 2.8 MAF, 1995's 6.6 MAF, and the 66-year median of 4.8 MAF. The early indications for 1997 are promising. As of February 1, 1997, reservoir storage above Brownlee Reservoir was 79 percent of capacity compared to 81 percent of 1995. The average snow-water equivalent for the Snake River above Brownlee Reservoir was 171 percent of the 30-year average at this time of year. Energy Requirements - With precipitation and streamflow conditions above normal in 1996, hydroelectric generation accounted for 58 percent of the Company's total energy requirements. This figure is an improvement over 1994's 40 percent, and is unchanged from 1995. During 1996, thermal generation accounted for 26 percent of total energy requirements, while purchased power and other interchanges supplied 16 percent. Under historically normal conditions, the Company's hydro system supplies approximately 57 percent of its total energy requirements, with thermal generation accounting for 34 percent and purchased power and other interchanges contributing the remaining 9 percent. The Company expects to meet 1997's projected energy loads by using its hydro and coal-fired facilities and its strategic geographic location, which presents excellent opportunities to purchase, sell, exchange, and transmit Northwest energy. Regulatory Issues - Power Cost Adjustment - Since 1993, the IPUC has permitted Idaho Power to use a PCA mechanism in its Idaho jurisdiction. The PCA enables the Company to collect or to refund a portion of the difference between net power supply costs actually incurred and those allowed in the Company's base rates. The current balance is adjusted monthly as actual conditions are compared to the PCA forecasted net power supply costs. For the period May 1996 through May 1997, the IPUC approved tariffs, reducing Idaho jurisdictional PCA rates by $25.7 million (5.9 percent), including the true-up for the PCA period May 1995 through May 1996. The reduction reflects anticipated lower power supply costs in the coming year due to above-average hydroelectric generating conditions. The 1996 PCA forecast reflects power supply costs below those established for PCA expenses in the Company's last general rate proceeding. At December 31, 1996, the Company had recorded as a deferred asset and reduction in operating expenses $11.4 million of power supply costs above those projected in the 1996 forecast. General Revenue Requirement Case - On January 31, 1995, the Company received IPUC Order No. 25880, which authorized $17.2 million in general rate relief, representing a 4.2 percent overall increase in Idaho retail rates. The relief was based on an 11.0 percent allowed return on equity and an overall rate of return of 9.2 percent. The increase in Idaho retail rates went into effect on February 1, 1995. Twin Falls Rate Case - In August 1995, the IPUC issued an order authorizing the Company to increase its Idaho retail rates on an annual basis by $3.8 million (0.9 percent). This increase was uniform to all customer classes, as well as to special contract customers. Regulatory Settlement - On August 3, 1995, Idaho Power filed a proposal with the IPUC to support the Company's organizational redesign. In response to the Company's proposal, the IPUC approved a Settlement that authorizes the Company to defer and amortize costs related to reorganization in return for a general rate freeze through the end of 1999. In addition, the Settlement allows for the accelerated amortization of regulatory liabilities associated with accumulated deferred investment tax credits (ADITCs) to provide a minimum 11.50 percent return on actual year-end common equity for the Idaho jurisdiction. The new rate freeze and the accelerated amortization of regulatory liabilities associated with ADITCs gives the Company time to pursue and to implement its efficiency and growth initiatives with the assurance of at least a reasonable level of financial performance apart from the need to change customer prices. The terms and conditions of the Settlement will remain in effect through 1999. Under the Settlement, when the Company's actual earnings in a given year exceed an 11.75 percent return on year- end common equity, the Company will refund 50 percent of the excess. Other important points in the Settlement are: (1) the Company may accelerate a maximum of $30 million of regulatory liabilities associated with ADITCs over the five-year period; (2) the Company will not be allowed to increase its Idaho general rates prior to January 1, 2000, except under special conditions as defined in the Settlement Agreement; and (3) Idaho Power agrees that its quality of service will not decline as a result of corporate reorganization. The Company has received approval from the Idaho State Tax Commission and the Internal Revenue Service on the accounting treatment for the tax credits. No accelerated ADITC was recognized in 1995 or 1996. Cogeneration and Small Power Production Contracts - In light of the potential deregulation of the electric utility industry and a more competitive power supply marketplace, Idaho Power believes that resource acquisition policies must avoid burdening the Company and its customers with unnecessary future power supply costs. 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, the IPUC issued an order on January 31, 1995, approving lower published CSPP rates for new projects. In addition, the IPUC determined that negotiated rates for future CSPP projects larger than 1 megawatt (MW) should be tied more closely to values determined in the Company's integrated resource planning (IRP) process. In a subsequent order issued on September 4, 1996, the IPUC further recognized the coming changes by limiting the contract term which a new CSPP project larger than 1 MW could request to a maximum of five years. Oregon General Rate Relief - In May 1995, Idaho Power filed an application with the Oregon Public Utilities Commission (OPUC), seeking general rate relief of approximately $3.4 million, or a 16.65 percent increase. The Company later negotiated a Settlement Stipulation with the OPUC staff, the Company's Oregon industrial customers, and the Citizens Utility Board of Oregon. The Settlement grants Idaho Power a $1.3 million general rate increase for its Oregon retail customers. The OPUC approved the Settlement Stipulation on November 28, 1995. Oregon Drought-Related Rate Relief - In response to the Company's April 1995 application, the OPUC granted $1.5 million in drought-related rate relief. The OPUC order allows recovery of the $1.5 million through the continued application of an existing increase authorized in July 1993 (for 1992 drought relief). The rate increase will remain in effect for approximately 34 months beginning in July 1995. The Company had deferred, with interest, increased power supply costs between May 1994 and December 31, 1994. Subsidiaries - Ida-West Energy Company - This wholly owned subsidiary of the Company holds investments in 13 operating hydroelectric plants with a total generating capacity of 72 megawatts (MW). In January 1996, Ida-West made an investment by acquiring all of the outstanding bonds that were issued to finance three hydroelectric plants known collectively as the Friant Power Project. This project is located at the U.S. Bureau of Reclamation's Friant Dam on the headwaters of the San Joaquin River in Madera and Fresno Counties, California. It has an aggregate generating capacity of 27.4 MW. The project is owned and operated by Friant Power Authority, a quasi-governmental entity consisting of six irrigation districts, a water district, and a municipal utility district. In November 1996, Ida-West purchased an interest in five hydroelectric projects located in Shasta County, California, with a total generating capacity of 11.2 MW. Ida-West acquired the projects through a limited liability company in which it holds a 50 percent interest. In addition, Ida-West has an interest in the Hermiston Power Project, a 460 MW, gas-fired cogeneration project to be located near Hermiston, Oregon. Ida-West has been responsible for managing all permitting and development activities relating to the project since its inception in 1993, and has obtained all permits necessary for construction and operation of the project. The partnership is exploring various alternatives for marketing the project's output. Project financing for construction costs would be non-recourse to Idaho Power. To date, the Company has invested $20 million in Ida-West. Ida- West continues an active search for new projects. IDACORP, Inc. - Through this wholly-owned subsidiary, the Company is participating in five affordable housing programs. These investments provide a return to IDACORP by reducing the Company's federal income taxes and by assuring a return on investment through tax credits and tax depreciation benefits. To date, the Company has invested $4.0 million in IDACORP. Idaho Power Resources Corporation - IPRC, is a wholly-owned subsidiary, incorporated in March 1996 to provide guidance, resources, and long-term strategic planning to projects or business proposals that are not subject to regulation by the FERC and the state regulatory commissions. IPRC's goals are to establish, acquire, and expand business operations in sustainable infrastructure technology and services including energy, water, waste disposal, telecommunications, and information systems. The Company has invested approximately $4.0 million in development and acquisition activities in IPRC. IPRC has a Memorandum of Understanding signed by Idaho Power and representatives from the government of Indonesia on March 6, 1996 that cleared the way to conduct a detailed feasibility study on using solar photovoltaic (PV) technology, micro hydroelectric systems, and other renewable energy systems to provide electricity to various locations throughout Indonesia's complex of islands. IPRC is currently reviewing results of the completed business plan. If the project is deemed workable and receives the required approvals, IPRC would likely begin to develop services in 1997. In October 1996, IPRC acquired a majority interest in Applied Power Corporation (APC), a Lacey, Washington-based, company that designs, supplies, and distributes photovoltaic (PV) systems. Stellar Dynamics - Stellar Dynamics core business is to provide products and services to control, protect, and monitor utility and industry processes and equipment. Stellar offers design and integration of high-quality modular process control systems backed with field support, training, documentation, and customer service. The Company has invested $1.5 million in Stellar. As Stellar's capital requirements increase, the Company has approved additional equity investments up to a total of $3.0 million. LIQUIDITY AND CAPITAL RESOURCES - Cash Flow - The Company's net cash generation from operations totaled $468.0 million for the three-year period 1994-1996. After deducting common and preferred dividends of $232.8 million, net cash generation from operations provided approximately $235.2 million for the Company's construction program and other capital requirements. Internal cash generation after dividends provided 41 percent of the Company's total capital requirements in 1994, 101 percent in 1995, and 99 percent in 1996. The Company forecasts that internal cash generation after dividends will provide approximately 85 percent of total capital requirements in 1997 and over 94 percent during the four-year period 1998-2001. Idaho Power expects to continue financing its construction program and other capital requirements with both internally generated funds and, to the extent necessary, externally financed capital. During the forecast period, the Company also has first mortgage bond maturities of $30.0 million in 1998, $80.0 million in 2000, and $30.0 million in 2001. At January 1, 1997, the Company had regulatory authority to incur up to $200.0 million of short-term indebtedness. On December 19, 1996, the Company replaced its committed lines of credit arrangements with a $120.0 million multi-year revolving credit facility under which the Company will pay a facility fee on the commitment, quarterly in arrears, based on the Company's first mortgage bond rating (see Note 7 of "Notes to Consolidated Financial Statements"). Construction Program - The Company's consolidated cash construction expenditures totaled $110.5 million in 1994, $84.0 million in 1995, and $93.6 in 1996. Approximately 25 percent of these expenditures were for generation facilities, 15 percent for transmission facilities, 43 percent for distribution facilities, and 17 percent for general plant and equipment. Twin Falls Project - In July 1995, the Company completed testing of the new expansion turbine at its Twin Falls Hydroelectric Project and declared the unit available for commercial operation. This project added 43.5 MW of capacity to the Company's generation system and a second powerhouse to the Twin Falls site. Southwest Intertie Project - The Company's Southwest Intertie Project (SWIP) is on hold. At the current time, an order from the Public Service Commission of Nevada is still pending, that would allow Nevada Power to participate in the project. The Company's SWIP proposal calls for a 500-mile, 500-kilovolt (kV) transmission line that would serve as a major north-south transmission artery, connecting the Company's system with those of utilities in California and the Southwest. The U.S. Bureau of Land Management has 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. The Company and interested parties have completed ownership allocation and negotiations for the execution of the Memorandum of Agreement (MOA). When the MOA is executed, the Company will require each party to pay its share of the approximately $8.5 million expended for environmental permitting, right-of-way acquisition, and related development activities. The SWIP owners will then form an Executive Committee, with voting rights proportional to each share of the project. The Executive Committee will oversee development activities for the SWIP and related projects. Financing Program - Capital Structure - The Company's capital structure (as illustrated in Selected Financial Data) fluctuated during the three-year period, with common equity ending at 45 percent, preferred stock 7 percent, and long-term debt 48 percent at December 31, 1996. The Company's objective is to maintain capitalization ratios of approximately 45 percent common equity, 5-10 percent preferred stock, and the balance in long-term debt. The Company's pre-tax interest coverage ratios were 3.01 times in 1994, and 3.40 times in 1995, and 3.49 times in 1996. 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 million. On July 29, 1996, the Company issued $30,000,000 principal amount of Secured Medium Term Notes, Series B, 6.93% Series Due 2001. The net proceeds were used for repayment of commercial paper issued in connection with the Company's ongoing construction program. On October 2, 1996, $27,000,000 principal amount of Secured Medium Term Notes, Series B, 6.85% Due 2002 were issued with net proceeds from this sale used to redeem the Company's 250,000 shares 8.375% Series, Serial Preferred Stock, Without Par Value. On August 29, 1996, tax exempt Pollution Control Revenue Refunding Bonds were issued in principal amount of $68,100,000 Series 1996A, $24,200,000 Series 1996B and $24,000,000 Series 1996C. The proceeds were used to retire the $24,200,000 Pollution Control Revenue Bonds Due 2003, $24,000,000 -Pollution Control Revenue Bonds Due 2007 and the $68,100,000 Pollution Control Revenue Bonds Due 2013-2014. Common Stock - During the period of January through May 1994, the Company issued original issue shares of common stock for its Dividend Reinvestment and Stock Purchase Plan, and for its Employee Savings Plan. During 1994, common shares totaling 527,296, were issued under these plans. The Company used the net proceeds from these issues for its ongoing construction program. During 1995 and 1996, no original issue shares were issued pursuant to these plans. 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 Fall Chinook Salmon from Threatened to Endangered. The Company does not anticipate that the new designation will have any major 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. In March of 1995, the National Marine Fisheries Service (NMFS) released a Proposed Recovery Plan for the listed Snake River Salmon. The NMFS accepted public comment on the Plan through December of 1995. As drafted, the Plan would not require any change to the Company's current operations for salmon. Pending completion of a final recovery plan by the NMFS, the U.S. Army Corps of Engineers and other governmental agencies operating federally owned dams and reservoirs on the Snake and Columbia Rivers will continue to consult with the NMFS regarding ongoing system operations. These interim operations are not expected to change the Company's current operations for salmon. The Northwest Power Planning Council (NWPPC) issued its recovery plan for Snake River anadromous fish, the Strategy for Salmon, on December 15, 1994. The NWPPC plan calls on the U. S. Bureau of Reclamation (BOR) to acquire 500,000 acre-feet of water within the Snake River Basin by 1996, and an additional 500,000 acre- feet by 1998. The water is to be acquired from willing sellers. Thus far, the BOR has indicated it does not intend to comply with the request to acquire 1,000,000 acre-feet of additional water. However, if the BOR does comply and successfully implements the request, its movement of additional water could have a material impact on the Company's power supply costs. The strategy for Salmon also calls for the Company to contribute 427,000 acre-feet of water from Brownlee Reservoir as required in the NMFS Proposed Recovery Plan. The Company has negotiated a five-year contract with BPA to replace lost energy and capacity resulting from recovery plans that impact the Company's power supply cost. Nez Perce Lawsuit - In 1996, Idaho Power's Board of Directors and the Nez Perce Tribe approved an Agreement between the Company and the Tribe which would resolve a civil lawsuit filed against Idaho Power in December of 1991, in the United States District Court for the District of Idaho, regarding alleged damages to the Tribe's treaty-reserved fishing rights. The suit arose from the construction, maintenance, and operation of Idaho Power's three-dam Hells Canyon Complex and the project's alleged impact both on fish and the Tribe's treaty-reserved fishing rights. The Agreement required the approval of the United States government (through the Bureau of Indian Affairs (BIA)) acting in its capacity as trustee for the Tribe. Under the terms of the Agreement, Idaho Power will pay the Nez Perce Tribe $11.5 million in the following manner: - $5 million at which time the Nez Perce would move for the dismissal of, with prejudice, their legal action against the Company. - $1,625,000 each year for the next four years. All payments under the Agreement will be made in 1996 dollars, which allows for adjusted future inflation within a minimum range of 3 percent and a maximum of 7 percent. The first payment of $5 million plus inflation adjustment will be paid before the end of 1997. On July 12, 1996 the IPUC issued Order No. 26513, and on August 5, 1996, the OPUC issued Order No. 96-207 approving capitalization of their respective jurisdictional share of the $11.5 million. The Company has recorded the $11.5 million as a regulatory asset due from ratepayers and a liability to the Tribe. The Tribe requested BIA approval. However, on November 21, 1996, the Portland Area Director of the BIA issued a decision stating that the Agreement did not have to be approved by the BIA and declined to review the Agreement. On December 19, 1996, the Company filed an administrative appeal of the BIA's decision. As a result of the BIA decision, the Tribe and the Company are exploring alternatives to BIA approval that would help assure the ultimate enforceability of the Agreement. In connection with settling the litigation, Idaho Power and the Tribe also reached a provisional settlement regarding the license renewal of the Hells Canyon Complex. In return for the Tribe's support of the Company's application to relicense the project, the Company will place $5 million, the majority of which the Tribe has agreed to dedicate to implementable fisheries restoration efforts, in an escrow account on August 3, 2003, the date by which the Company must file its relicense application. The Tribe will be entitled to earnings from investments on this account until the Company accepts or rejects a new federal license for the project. If the Company accepts the new federal license, the Tribe will take ownership of the money in the account. If the Company rejects the license, the money will be returned to the Company. This settlement is provisional because the Tribe retains the right to opt out of this relicensing settlement at any time prior to the Company's acceptance of a new federal license. Threatened and Endangered Snails - In mid-December 1992, the U.S. Fish and Wildlife Service (USFWS) listed five species of Snake River snails as 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. Although 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 effects, if any, that water fluctuations caused by these facilities may have on the snails. 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. In 1995, as a part of its federal hydro relicensing process, Idaho Power obtained a permit from the USFWS to study five species of endangered Snake River snails. The Company's biologists will conduct this study over the next three years, focusing on potential snail habitat in the Middle Snake River. The Company's objective is to gain scientific insight into how or if these snails are affected by a variety of factors, including hydropower production, water quality, and irrigation run-off. The study will review how these and other factors influence the status of the various colonies and their respective habitats. Mountaineer Cleanup - 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 Idaho Power, owns one-third of BCC. In November 1993, BCC agreed to be included on the list of parties potentially responsible for this site. The estimated cleanup costs totaled approximately $4.0 million. BCC's portion of the cleanup costs, based on the amount of oil delivered to the site, was estimated to be approximately 4.63 percent ($185,200). This estimate is likely to be high since the cleanup is substantially complete, with the exception of ground water monitoring. To date, BCC has expended $84,700 in cleanup costs and continues to carry $42,750 as an unfunded liability as of December 31, 1996. IERCo is responsible for one-third of BCC's share of the cleanup costs. Clean Air - Idaho Power has analyzed the Clean Air Act's effects on the Company and its rate payers. The Company's coal-fired plants in Oregon and Nevada already meet the federal emission rate standards for sulfur dioxide (SO2) and Idaho Power's coal-fired plant in Wyoming meets that state's even more stringent SO2 regulations. Therefore, the Company foresees no adverse effects on its operations with regard to SO2 emissions. During 1994, 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 and 3, of the Company's Jim Bridger thermal facility, together with facilities owned by PacifiCorp and Black Hills Corporation, as substitution units for Illinois Power's Baldwin #2. 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 - While scientific research has not established any conclusive link between electric and magnetic fields (EMFs) and human health, the possibility of a link has caused public concern in the United States and abroad. Electric and magnetic fields exist 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 EMFs. Depending on what researchers ultimately discover and any necessary regulations, it is possible that this issue could affect a number of industries, including electric utilities. However, it is difficult at this time to estimate what effects, 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, Idaho Power 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. The Company believes the first meaningful step to a competitive retail energy market is the functional unbundling of costs into the various delivery and energy components. The Company believes that the unbundling of costs will create a real means for our customers to compare energy prices and that cost unbundling will facilitate the establishment of more accurate price signals for service components. The Company is prepared to bring forward cost unbundling filings in its regulatory jurisdictions in the first half of 1997. The Company expects that state regulators may require formal hearings on the cost unbundling issue. The Company further believes that the future of the electric utility industry will be characterized by the right of customers to choose their own electric service provider. To remain successful, Idaho Power must continue to provide value to its shareholders in the face of this new competitive environment. The Company's vision involves three strategies for creating this value: selective and efficient use of capital; an enhanced customer orientation; and innovative, efficient operations. Because future prices for power will be determined more by market forces and less by regulatory administration, the Company must be very selective and efficient in the use and allocation of capital. Idaho Power will invest in improving and expanding its core business, in developing new opportunities beyond its current service territory, and in continuing to develop non-regulated opportunities consistent with the Company's core competencies. Based on this vision and the Company's efforts to increase shareholder and customer value, Idaho Power is transforming its operations to improve both efficiency and customer service. Teams of employees are redesigning work processes. In some cases, these improved processes are successfully in place. During 1995, Idaho Power announced plans for voluntary and involuntary separation packages in the event of workforce reductions resulting from its reorganization efforts. The packages included compensation based on years of service and address medical benefits and transition services. FERC Decisions - On April 24, 1996, the FERC issued its Order Nos. 888 and 889 dealing with Open-Access Non-Discriminatory Transmission Services by Public and Transmitting Utilities, and standards of conduct regarding these issues. These orders require public utilities owning transmission lines to file open-access tariffs available to buyers and sellers of wholesale electricity; to require utilities to use the tariffs for their own wholesale sales; and to allow utilities to recover stranded costs, subject to certain conditions. Public utilities owning transmission lines were required to file compliance tariffs by July 9, 1996. Idaho Power has long had an informal open-access transmission policy, and is experienced in providing reliable, high-quality, economical transmission service. The Company provides various firm and non-firm wheeling services for several surrounding utilities. In November of 1995, the Company filed open-access tariffs with the FERC for Point-to-Point and Network transmission service. The substance of these tariffs was to offer the same quality and character of transmission services that the Company uses in its own operations to anyone seeking them. The Company requested and received permission to implement these tariffs beginning February 1, 1996. On July 8, 1996, the Company filed a new open-access transmission tariff to replace the 1995 tariffs. This provides full compliance with Final Order No. 888. This new filing did not include a rate change. On November 13, 1996, FERC issued an unconditional acceptance of the terms and conditions of this tariff. The rate was not subject to review. Independent Grid Operator - A group of seven investor-owned Northwest electric companies, including Idaho Power, BPA, and three public electric entities have signed a memorandum of understanding that will create an independent transmission grid operator called "IndeGO". It will ensure non-discriminatory, open-access to electricity transmission facilities in compliance with recent FERC rulings. This memorandum of understanding is an agreement to investigate the feasibility of developing a regional transmission grid which would be operated by an entity independent of power market interests. It is believed that the formation of such an entity will facilitate the operation of an evolving competitive electric power market. Operating as one regional system, the utilities will be able to increase the efficiency of transmission operations and provide improved access for all system users. IndeGo is envisioned as an independent transmission company not controlled by any individual power market participant(s). It is anticipated that IndeGO will operate as a single control area, with pricing based on a single zonal tariff applied equally to all users including the participating companies. IndeGO will not own transmission facilities at the onset, but will be responsible for the operation of main transmission grid facilities 230 kilovolts (kV) or more that are owned by the participating utilities. The area encompassed by the IndeGo has over 20,000 miles of transmission lines accounting for about 97% of the northwest grid. The group plans to file the IndeGo proposal with FERC by July 1997, and anticipates operation would commence as early as 1999. If the FERC's approval arrives by April of 1998, an IndeGo Board and Site Procurement could be expected by July of 1998. Marketing Business Unit - To accommodate its customers and allow itself to compete in the rapidly evolving competitive market, the Company has formed a Marketing Business Unit, effective January 1997. This new business unit will be responsible for all purchases and sales of electric energy, market research and the planning and implementation of marketing strategies. To assist the Marketing Business Unit in bringing value to the Company, the Board of Directors gave approval for executive management to form a Risk Management Committee, comprised of executives and senior managers, to oversee a new risk management program. The program is intended to minimize fluctuations in earnings and cash flow while controlling the volatility of the Company's energy prices to its customers. The objectives of the program include setting and achieving commodity price targets, locking in commodity prices related to specific contracts for the sale of electricity, and managing commodity price risk for customers. IPUC Workshops Regarding Industry Changes - In August 1996, the IPUC completed its investigation into changes in the electric utility industry and issued Order No. 26555. The IPUC commended the working group for its effort and for the development of a position paper (an attachment to the order) on the changes affecting the electric utility industry. The position paper was the product of a series of workshops concerning the electric utility industry restructuring and its impact on the state of Idaho. Participants included commissioners and commission staff, electric utility customers and customer group representatives, publicly-and investor-owned utilities, and public interest groups. The position paper set forth regulatory and legal issues that might arise during a transition to a more competitive environment. The IPUC addressed the issues individually in Order No. 26555. In its order, the IPUC described a cautious forward approach, noting that customers of Idaho regulated utilities pay some of the lowest rates in the nation and that low cost hydroelectricity is an existing benefit of Idaho retail customers. The IPUC stated its expectation that many of the specific restructuring issues would be resolved in a case-by-case manner. Relicensing of Hydroelectric Projects - Idaho Power is actively pursuing the relicensing of its hydroelectric projects, a process that will continue for the next 10 to 15 years. The Company submitted its first applications for license renewal to the FERC in December 1995. These first applications 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 license renewing 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 license renewal. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENT AND FINANCIAL STATEMENT SCHEDULE PAGE Management's Responsibility for Financial Statements 41 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 1996, 1995 and 1994 42-43 Consolidated Statements of Income for the Years Ended December 31, 1996, 1995 and 1994 44 Consolidated Statements of Retained Earnings for the Years Ended December 31, 1996, 1995 and 1994 45 Consolidated Statements of Capitalization as of December 31, 1996, 1995 and 1994 46 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 47 Notes to Consolidated Financial Statements 48-60 Independent Auditors' Report 61 Supplemental Financial Information (Unaudited) 62 Supplemental Schedule for the Years Ended December 31, 1996, 1995 and 1994: Schedule II- Consolidated Valuation and Qualifying Accounts 69 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. /s/Joseph W. Marshall /s/J. LaMont Keen Joseph W. Marshall J. LaMont Keen Chairman and Chief Executive Officer Vice President,Chief Financial Officer and Treasurer IDAHO POWER COMPANY CONSOLIDATED BALANCE SHEETS ASSETS December 31, 1996 1995 1994 (Thousands of Dollars) ELECTRIC PLANT: In service (at original cost) $2,537,565 $2,481,830 $2,383,898 Accumulated provision for depreciation (886,885) (830,615) (775,033) In service - Net 1,650,680 1,651,215 1,608,865 Construction work in progress 42,178 20,564 46,628 Held for future use 1,773 1,106 1,150 Electric plant - Net 1,694,631 1,672,885 1,656,643 INVESTMENTS AND OTHER PROPERTY 36,502 16,826 18,034 CURRENT ASSETS: Cash and cash equivalents 7,928 8,468 7,748 Receivables: Customer 34,962 33,357 31,889 Allowance for uncollectible accounts (1,394) (1,397) (1,377) Notes 5,104 5,134 4,962 Employee notes receivable 4,486 4,648 5,444 Other 8,489 10,771 4,316 Accrued unbilled revenues 27,709 25,025 29,115 Materials and supplies (at average cost) 24,639 25,937 24,141 Fuel stock (at average cost) 11,631 13,063 11,310 Prepayments 16,165 20,778 21,398 Regulatory assets associated with income taxes 4,397 5,777 5,674 Total current assets 144,116 151,561 144,620 DEFERRED DEBITS: American Falls and Milner water rights 32,260 32,440 32,605 Company-owned life insurance 57,291 56,066 49,510 Regulatory assets associated with income taxes 196,696 200,379 179,311 Regulatory assets - other 89,507 68,348 67,713 Other 44,334 43,248 43,380 Total deferred debits 420,088 400,481 372,519 TOTAL $2,295,337 $2,241,753 $2,191,816 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1996 1995 1994 (Thousands of Dollars) CAPITALIZATION: Common stock equity: Common stock - $2.50 par value (shares authorized 50,000,000 shares outstanding-37,612,351) $ 94,031 $ 94,031 $ 94,031 Premium on capital stock 362,297 363,044 363,063 Capital stock expense (3,842) (4,127) (4,132) Retained earnings 242,088 229,827 220,838 Total common stock equity 694,574 682,775 673,800 Preferred stock 106,975 132,181 132,456 Long-term debt 738,550 672,618 693,206 Total capitalization 1,540,099 1,487,574 1,499,462 CURRENT LIABILITIES: Long-term debt due within one year 71 20,517 517 Notes payable 54,016 53,020 55,000 Accounts payable 36,370 40,483 32,063 Taxes accrued 17,304 15,409 16,394 Interest accrued 15,886 14,785 14,755 Deferred income taxes 4,397 5,777 5,674 Other 12,439 12,867 12,574 Total current liabilities 140,483 162,858 136,977 DEFERRED CREDITS: Regulatory liabilities associated with deferred investment tax credits 71,283 70,507 71,593 Deferred income taxes 411,890 408,394 375,252 Regulatory liabilities associated with income taxes 35,028 34,554 35,090 Regulatory liabilities - other 616 789 626 Other 95,938 77,077 72,816 Total deferred credits 614,755 591,321 555,377 COMMITMENTS AND CONTINGENT LIABILITIES (Note 8) TOTAL $2,295,337 $2,241,753 $2,191,816 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME Year Ended December 31, 1996 1995 1994 (Thousands of Dollars) REVENUES $578,445 $545,621 $543,658 EXPENSES: Operation: Purchased power 69,038 54,586 60,216 Fuel expense 63,334 54,691 94,888 Power cost adjustment (6,859) 7,292 (12,076) Other 132,667 126,714 123,328 Maintenance 42,731 35,953 43,490 Depreciation 69,705 67,415 60,202 Taxes other than income taxes 20,658 22,979 23,945 Total expenses 391,274 369,630 393,993 INCOME FROM OPERATIONS 187,171 175,991 149,665 OTHER INCOME: Allowance for equity funds used during construction 46 (16) 1,680 Other - Net 12,488 14,372 10,480 Total other income 12,534 14,356 12,160 INTEREST CHARGES: Interest on long-term debt 52,165 51,147 51,172 Other interest 5,183 5,309 3,261 Total interest charges 57,348 56,456 54,433 Allowance for borrowed funds used during construction (353) (1,442) (1,781) Net interest charges 56,995 55,014 52,652 INCOME BEFORE INCOME TAXES 142,710 135,333 109,173 INCOME TAXES 52,092 48,412 34,243 NET INCOME 90,618 86,921 74,930 Dividends on preferred stock 7,463 7,991 7,398 EARNINGS ON COMMON STOCK $83,155 $78,930 $67,532 AVERAGE COMMON SHARES OUTSTANDING (000) 37,612 37,612 37,499 EARNINGS PER SHARE OF COMMON STOCK $ 2.21 $ 2.10 $ 1.80 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Year Ended December 31, 1996 1995 1994 (Thousands of Dollars) RETAINED EARNINGS Beginning of year $229,827 $220,838 $222,900 NET INCOME 90,618 86,921 74,930 Total 320,445 307,759 297,830 DIVIDENDS: Preferred stock 7,463 7,991 7,398 Common stock (per share: 1996 - 1994 - $1.86 69,924 69,941 69,594 Total dividends 77,387 77,932 76,992 PREFERRED STOCK REDEMPTION 970 - - RETAINED EARNINGS End of year $242,088 $229,827 $220,838 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1996 % 1995 % 1994 % (Thousands of Dollars) COMMON STOCK EQUITY: Common stock $ 94,031 $ 94,031 $ 94,031 Premium on capital stock 362,297 363,044 363,063 Capital stock expense (3,842) (4,127) (4,132) Retained earnings 242,088 229,827 220,838 Total common stock equity 694,574 45 682,775 46 673,800 45 PREFERRED STOCK: 4% preferred stock 16,975 17,181 17,456 7.68% Series, serial preferred stock 15,000 15,000 15,000 8.375% Series, serial preferred stock - 25,000 25,000 7.07% Series, serial preferred stock 25,000 25,000 25,000 Auction rate preferred stock 50,000 50,000 50,000 Total preferred stock 106,975 7 132,181 9 132,456 9 First mortgage bonds: 5 1/4 % Series due 1996 - 20,000 20,000 5.33 % Series due 1998 30,000 30,000 30,000 8.65 % Series due 2000 80,000 80,000 80,000 6.93 % Series due 2001 30,000 - - 6.85 % Series due 2002 27,000 - - 6.40 % Series due 2003 80,000 80,000 80,000 8 % Series due 2004 50,000 50,000 50,000 9.50 % Series due 2021 75,000 75,000 75,000 7.50 % Series due 2023 80,000 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 527,000 490,000 490,000 Amount due within one year - (20,000) - Net first mortgage bonds 527,000 470,000 490,000 Pollution control revenue bonds: 5.90 % Series due 2003 - 24,200 24,650 6.0 % Series due 2007 - 24,000 24,000 7 1/4 % Series due 2008 4,360 4,360 4,360 7 5/8 % Series 1083-1984 due 2013-2014 - 68,100 68,100 8.30 % Series 1984 due 2014 49,800 49,800 49,800 6.05 % Series 1996A due 2026 68,100 - - Variable rate Series 1996B due 2026 24,200 - - Variable rate Series 1996C due 2026 24,000 - - Total pollution control revenue bonds 170,460 170,460 170,910 Amount due within one year - (450) (450) Net pollution control revenue bonds 170,460 170,010 170,460 REA notes 1,632 1,700 1,768 Amount due within one year (71) (67) (67) Net REA notes 1,561 1,633 1,701 Subsidiary debt 9,000 - - American Falls bond guarantee 20,560 20,740 20,905 Milner Dam note guarantee 11,700 11,700 11,700 Unamortized premium/discount-Net (1,731) (1,465) (1,560) Total long-term debt 738,550 48 672,618 45 693,206 46 TOTAL CAPITALIZATION $1,540,099 100 $1,487,574 100 $1,499,462 100 The accompanying notes are an integral part of these statements. IDAHO POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 1996 1995 1994 (Thousands of Dollars) OPERATING ACTIVITIES: Cash received from operations: Retail revenues $490,504 $468,821 $457,202 Wholesale revenues 66,551 59,260 62,110 Other revenues 24,469 22,825 23,711 Fuel paid (59,798) (61,741) (94,530) Purchased power paid (70,302) (52,526) (62,592) Other operation & maintenance (177,055) (154,209) (171,774) Interest paid (include long and short-term debt only) (53,273) (54,303) (52,376) Income taxes paid (45,050) (40,402) (16,518) Taxes other than income taxes paid (23,455) (22,939) (21,698) Other operating cash receipts and payments-Net 21,824 3,634 2,122 Net cash provided by 174,415 168,420 125,657 FINANCING ACTIVITIES: First mortgage bonds issued 57,000 - - PC bond fund requisitions/other long-term debt 128,534 - - Common stock issued - - 13,402 Short-term borrowings-Net 1,000 (2,000) 51,000 Long-term debt retirement (140,069) (519) (466) Preferred stock retirement (26,530) (151) (166) Dividends on preferred stock (7,850) (7,888) (7,565) Dividends on common stock (69,923) (69,967) (69,594) Other sources/uses (4,144) (781) - Net cash - financing activities (61,982) (81,306) (13,389) INVESTING ACTIVITIES: Additions to utility plant (93,645) (83,965) (110,523) Conservation (3,839) (5,688) (6,830) Increase in investments (20,153) - - Other 4,664 3,259 4,605 Net cash - investing activities (112,973) (86,394) (112,748) Change in cash and cash equivalents (540) 720 (480) Cash and cash equivalents beginning of year 8,468 7,748 8,228 Cash and cash equivalents end of year 7,928 8,468 7,748 RECONCILIATION OF NET INCOME TO NET CASH PROVIDED BY OPERATING ACTIVITIES: Net income $ 90,618 $ 86,921 $ 74,930 Adjustments to reconcile net income to net cash: Depreciation 69,705 67,415 60,202 Deferred income taxes 7,201 11,698 14,265 Investment tax credit - Net 776 (1,086) (1,064) Allowance for funds used during construction (399) (1,425) (3,461) Postretirement benefits funding (excl pensions) 1,340 (2,857) (5,182) Changes in operating assets and liabilities: Accounts receivable 3,079 5,285 (635) Fuel inventory 3,535 (7,050) 358 Accounts payable (1,264) 2,061 (2,376) Taxes payable (3,696) (2,519) 7,296 Interest payable 3,870 2,100 1,656 Other - Net (350) 7,877 (20,332) Net cash provided by operating activities $174,415 $168,420 $125,657 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 six wholly- owned subsidiaries, Idaho Energy Resources Co. (IERCo), Ida-West Energy Company (Ida-West), IDACORP, Inc., Idaho Utility Products Company (IUPCo), Stellar Dynamics, Inc. (Stellar), and Idaho Power Resources Corporation (IPRC). All significant intercompany transactions and balances have been eliminated in consolidation. Investments in business entities in which the Company and its subsidiaries do not have control, but has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. 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 rate making process over the service life of the related property through increased revenues resulting from higher rate base and higher depreciation expense. Based on the uniform formula adopted by the FERC, the Company's weighted average monthly AFDC rates for 1996, 1995 and 1994 were 6.1 percent, 6.1 percent and 8.2 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. In 1996, under terms and conditions of the Regulatory Settlement with the Idaho Public Utilities Commission (IPUC) , the Company set aside approximately $4.9 million of revenues for the benefit of its Idaho customers. Under the Settlement, when the Company's actual earnings in a given year exceeds an 11.75 percent return on year-end common equity, the Company will refund 50 percent of the excess. POWER COST ADJUSTMENT - The Company has in place, in its Idaho jurisdiction, a Power Cost Adjustment (PCA) mechanism which provides for Idaho's retail customer rates to be based on forecasted net power supply costs. Deviations from forecasted costs are deferred with interest and then adjusted (trued-up) in the subsequent year. DEPRECIATION - All electric plant is depreciated using the straight-line method. Annual depreciation provisions as a percent of average depreciable electric plant in service approximated 2.89 percent in 1996, 2.90 percent in 1995 and 2.93 percent in 1994 and are considered adequate to amortize the original cost over the estimated service lives of the properties. INCOME TAXES - The Company follows the liability method of computing deferred taxes on all temporary differences between book and tax basis of assets and liabilities and adjusts deferred tax assets and liabilities for enacted changes in tax laws or rates. 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. 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 (see Note 2). The state of Idaho allows a three percent investment tax credit (ITC) upon certain qualifying plant additions. ITC earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned. In 1995, the Company received an accounting order from the IPUC approving acceleration of amortization of up to $30.0 million of regulatory liabilities associated with deferred ITC to non- operating income. The Internal Revenue Service and the Idaho State Tax Commission have both approved the application. Acceleration of ITC amortization is to be utilized until the actual return on year-end common equity is 11.5 percent. No accelerated ITC was recognized in 1995 or 1996. 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. MANAGEMENT ESTIMATES - The preparation of financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. REGULATION OF UTILITY OPERATIONS - Electric utilities have historically been recognized as natural monopolies and have operated in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return. This regulatory environment is changing. The generation sector has experienced competition from non-utility power producers, and the FERC is requiring utilities, including the Company, to provide wholesale open-access transmission service to others and may order electric utilities to enlarge their transmission systems to facilitate transmission services. Some state regulatory authorities are in the process of changing utility regulations in response to federal and state statutory changes and evolving competitive markets. The Company believes that these statutory and conforming regulations may result in increased wholesale competition. However, due to the company's low cost structure, increased wholesale competition is not expected to adversely affect it in the near term and may favorably impact it in the long term. The Company is unable to predict what financial impact or effect the adoption of any such legislation would have on its operations. The Company follows Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", and its financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating the Company. Pursuant to SFAS No. 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 1996, 1995 and 1994: 1996 1995 1994 Assets Liab. Assets Liab. Assets Liab. (Millions of Dollars) Income taxes $201.1 $35.0 $206.2 $ 34.6 $185.0 $35.1 Conservation 40.3 36.3 29.7 Employee benefits 7.4 8.3 9.5 PCA deferral and amortizatioin 9.6 2.1 9.1 Other 32.2 0.6 21.6 0.7 19.4 0.6 Accumulated deferred Investment tax credits 71.3 70.5 71.6 Total $290.6 $106.9 $274.5 $105.8 $252.7 $107.3 At December 31, 1996, the Company had $22.6 million of regulatory assets that were not earning a return on investment excluding the $201.1 million that relates to income taxes. In the event that recovery of cost through rates becomes unlikely or uncertain, SFAS No. 71 would no longer apply. If the Company were to discontinue application of SFAS No. 71 for some or all of its operations, then these items may 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 is not allowed recovery of these investments, it would be required to write off the applicable portion of regulatory assets and the financial effects could be significant. DERIVATIVES - The Company has a policy which allows for the use of financial instruments such as commodity futures, options and swaps as a means of hedging against the risks associated with price fluctuations in the electricity market. At December 31, 1996, the Company's hedging transactions did not have a material effect on its financial statements. OTHER ACCOUNTING POLICIES - Debt discount, expense and premium are being amortized over the terms of the respective debt issues. RECLASSIFICATIONS - Certain items previously reported for years prior to 1996 have been reclassified to conform with the current year' s presentation. Net income was not affected by these reclassifications. 2. INCOME TAXES: A reconciliation between the statutory federal income tax 1996 1995 1994 rate and the effective rate is as follows: (Thousands of Dollars) Computed income taxes based on statutory federal income tax rate $ 49,949 $ 47,367 $ 38,210 Change in taxes resulting from: AFDC (140) (504) (1,211) Investment tax credits (2,835) (2,837) (3,351) Repair allowance (2,800) (3,150) (1,575) Elimination of amounts provided in prior years (16) (1,963) (2,607) Current state income taxes 2,823 3,275 1,496 Depreciation 5,945 5,493 2,812 Affordable housing tax credits (1,777) - - Other 943 731 469 Total provision for federal and state income taxes $ 52,092 $ 48,412 $ 34,243 Effective tax rate 36.5% 35.8% 31.4% The provision for income taxes consists of the following: Income taxes currently payable: Federal $40,379 $33,456 $19,617 State 3,746 4,503 1,425 Total 44,125 37,959 21,042 Income taxes deferred - Net of amortization: Federal 6,877 10,904 12,595 State 314 635 1,670 Total 7,191 11,539 14,265 Investment and other tax credits: Deferred 3,611 1,751 1,643 Restored (2,835) (2,837) (2,707) Total 776 (1,086) (1,064) Total provision for income taxes $ 52,092 $ 48,412 $ 34,243 The tax effects of significant items comprising the Company's net deferred tax liability are as follows: Deferred tax assets: Regulatory liability $ 35,028 $ 34,554 $ 35,090 Advances for construction 17,736 14,823 10,542 Other 13,550 10,498 6,387 Total 66,314 59,875 52,019 Deferred tax liabilities: Property, plant and equipment 245,652 237,655 225,444 Regulatory asset 201,093 206,156 184,985 Investment tax credit 71,283 70,507 71,593 Conservation programs 13,720 11,746 4,704 Other 22,136 18,489 17,812 Total 553,884 544,553 504,538 Net deferred tax liabilities $487,570 $484,678 $452,519 The Company has settled Federal and Idaho tax liabilities on all open years through the 1992 tax year except for amounts related to a partnership which, in management's opinion, have been adequately accrued. 3. COMMON STOCK: Changes in shares of the common stock of the Company for 1996, 1995 and 1994 were as follows: Common Stock Premium on $2.50 Capital Shares Par Value Stock (Thousands of Dollars) Balance at December 31, 1993 37,085,055 $92,713 $350,882 Gain on reacquired 4% preferred stock - - 126 Stock purchase plans 527,296 1,318 12,055 Balance at December 31, 1994 37,612,351 94,031 363,063 Gain on reacquired 4% preferred stock - - 117 Restricted stock plans - - (136) Balance at December 31, 1995 37,612,351 94,031 363,044 Gain on reacquired 4% preferred stock - - 83 Restricted stock plans - - (102) Preferred stock redemption - - (728) Balance at December 31, 1996 37,612,351 $94,031 $362,297 During the period of January 1994 through May 1994, the Company issued 527,296 original issue shares of common stock for its Dividend Reinvestment and Stock Purchase Plan and the Employee Savings Plan. As of December 31, 1996, 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. The Company has a Shareowner Rights Plan (Plan) designed to ensure that all shareholders receive fair and equal treatment in the event of any proposal to acquire control of the Company. Under the Plan, the Company declared a distribution of one Preferred Stock Right (Right) for each of the Company's outstanding Common shares held on January 29, 1990 or issued thereafter. The Rights are currently not exercisable and will be exercisable only if a person or group (Acquiring Person) either acquires ownership of 20 percent or more of the Company's Voting Stock or commences a tender offer that would result in ownership of 20 percent or more. The Company may redeem the Rights at a price of $0.01 per Right anytime prior to acquisition by an Acquiring Person of a 20 percent position. Following the acquisition of a 20 percent position, each Right will entitle its holder, subject to regulatory approval, to purchase for $85 that number of shares of Common Stock or Preferred Stock having a market value of $170. If after the Rights become exercisable, the Company is acquired in a merger or other business combination, 50 percent or more of its consolidated assets or earnings power are sold or the Acquiring Person engages in certain acts of self-dealing, each Right entitles the holder to purchase for $85, shares of the acquiring company's Common Stock having a market value of $170. Any Rights that are or were held by an Acquiring Person become void if either of these events occurs. The Rights expire on January 11, 2000. 4. PREFERRED STOCK: The number of shares of preferred stock outstanding at December 31, 1996, 1995 and 1994 were as follows: Shares Outstanding at Call Price December 31, 1996 1995 1994 Per Share Preferred stock: Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 169,753 171,813 174,556 $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) - 250,000 250,000 7.07% Series, $100 stated value, authorized 250,000 shares)(a) 250,000 250,000 250,000 $103.535 to $100.354 Auction rate preferred stock, $100,000 stated value, (authorized 500 shares)(b) 500 500 500 $100,000.00 Total 570,253 822,313 825,056 (a) The preferred stock is not redeemable prior to July 1, 2003. (b) Dividend rate at December 31, 1996 was 4.05% and ranged between 4.00% and 4.31% during the year. During 1996, 1995 and 1994 the Company reacquired and retired 2,060; 2,743; and 2,950 shares of 4% preferred stock resulting in a net addition to premium on capital stock of $82,900, $117,346, and $126,066 respectively. As of December 31, 1996 the overall effective cost of all outstanding preferred stock was 5.54 percent. On November 7, 1996, the Company redeemed the $25,000,000 principal amount of 8.375% Series, serial preferred stock with par value, ($100 stated value) from proceeds of the issuance of $27,000,000 principal amount of secured medium term notes, Series B, 6.85%, Due 2002. The total cost was $26,395,000 which includes a premium of $1,395,000. The redemption premium plus the initial issuance expense of $303,547, was charged $728,541 to premium on capital stock and $970,006 to retained earnings. 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. First mortgage bonds maturing during the five-year period ending 2001 are $30,000,000 in 1998, $80,000,000 in 2000 and $30,000,000 in 2001. On July 29, 1996, the Company issued $30,000,000 principal amount of Secured Medium Term Notes, Series B, 6.93% Series Due 2001. The net proceeds were used for repayment of commercial paper issued in connection with the Company's ongoing construction program. On October 2, 1996, $27,000,000 principal amount of Secured Medium Term Notes, Series B, 6.85% Due 2002 were issued with net proceeds from this sale used to redeem the Company's 250,000 shares of 8.375% Series, Serial Preferred Stock, Without Par Value. On August 29, 1996, tax exempt Pollution Control Revenue Refunding Bonds were issued in principal amount of $68,100,000 Series 1996A, $24,200,000 Series 1996B and $24,000,000 Series 1996C. The proceeds were used to retire the $24,200,000 Pollution Control Revenue Bonds due 2003, $24,000,000 Pollution Control Revenue Bonds due 2007 and the $68,100,000 Pollution Control Revenue Bonds due 2013-2014. At December 31, 1996, 1995 and 1994, the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 7.73 percent, 8.02 percent and 8.02 percent, respectively. 6. FINANCIAL INSTRUMENTS: Fair Value - 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 $773,760,000 for 1996, $731,168,000 for 1995 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, 1997, the Company had regulatory authority to incur up to $200,000,000 of short-term indebtedness. On December 19, 1996, the Company replaced its committed lines of credit arrangements with a $120,000,000 multi-year revolving credit facility, which will expire on December 19, 2001. Under this facility the Company will pay a facility fee on the commitment, quarterly in arrears, based on the Company's First Mortgage Bond rating. Commercial paper may be issued in an amount not to exceed 25 percent of revenues for the latest twelve-month period subject to the $200,000,000 maximum described above 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, 1996 1995 1994 (Thousands of Dollars) Balance at end of year $54,016 $53,020 $55,000 Effective annual interest rate at end of year 5.7% 6.0% 6.1% 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 $2.2 million at December 31, 1996. 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 67 on-line cogeneration and small power production facilities with contracts ranging from 1 to 32 years. Under these contracts the Company is required to purchase all of the output from these facilities. During the fiscal year ended December 31, 1996, the Company purchased 776,368 (MWH) at a cost of $43.7 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 financial position, results of operation or cash flow. 9. BENEFIT PLANS: Incentive Plans - The Company implemented two annual incentive plans 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. For the years 1996 and 1995 total incentive for the plans was $2,467,334 and $2,898,785, respectively. 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. At December 31, 1996, there were 370,000 shares of common stock reserved for the Plan. Grants are offered to all officers. The Committee has selected a three-year restricted period for each grant. A new grant can be offered in each succeeding year with a single financial performance goal of Cumulative Earnings Per Share ("CEPS"). Final award amounts will depend on the attainment by the Company of the CEPS performance goal established by the Committee and may be prorated in the event of death, disability or retirement of an officer based on the number of whole months of service the officer completes during the Restricted Period. Upon the officer's termination of employment during the Restricted Period for any other reason, all such shares will be forfeited by the officer to the Trustee. Effective January 1, 1997, certain senior managers of the Company have become participants in the Plan. Restricted stock awards are compensatory awards and the Company accrues compensation expenses (which are charged to operations) based upon the market value of the granted shares. For the years 1996 and 1995, total compensation for the plan was $184,153 and $91,200, respectively. The following table shows the cumulative amount of grants offered by the Company for the years 1996 and 1995: Balance of shares outstanding at January 1, 1995 - Granted in 1995 9,480 Forfeited in 1995 (360) Balance at December 31, 1995 9,120 Granted in 1996 9,740 Forfeited in 1996 (720) Balance at December 31, 1996 18,140 At December 31, 1996, no shares were vested under the plan. 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 was not required to contribute to the plan in 1996, but funded $5.9 million in 1995 and $5.5 million in 1994. 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 (Security Plan) 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 in excess of the projected benefit obligation and do not qualify as plan assets in the actuarial computation of the funded status. Based upon SFAS No. 87, "Employers' Accounting for Pensions", the Company has recorded a net liability of $21.8 million as of December 31, 1996. 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. Plan Costs for the Year 1996 1995 1994 Pension plan: (Thousands of Dollars) Service cost $ 6,273 $ 5,167 $ 6,049 Interest cost 13,647 12,998 12,263 Actual return on plan assets (30,214) (45,990) 312 Deferred gain (loss) on plan 12,230 31,489 (15,584) Net cost $ 1,936 $ 3,664 $ 3,040 Approximate percentage included in operating expenses 67% 65% 67% Net deferred compensation plan costs charged to other income (including life insurance and SFAS No. 87 liability accrual)(a) $ 794 $ 37 $ 508 (a) These charges to the Income Statement have been reduced by gains from the Company-owned life insurance of $1,697; $2,320 and $2,724, for 1996, 1995 and 1994, respectively. Funded status and significant assumptions as of December 31: Pension Plan Deferred Compensation Plan 1996 1995 1994 1996 1995 1994 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $155,343 $145,334 $128,162 $21,840 $21,530 $19,148 Accumulated benefit obligation 158,349 150,688 132,766 21,840 21,530 19,148 Projected benefit obligation $202,049 $193,133 $167,103 $22,370 $22,111 $19,681 Plan assets at fair value 230,479 204,760 165,839 - - - Plan assets in excess of (or less than) projected benefit obligation 28,430 11,627 (1,264) (22,370) (22,111) (19,681) Unrecognized net (gain) loss from past experience different from that assumed (20,995) (8,341) 6,040 4,376 4,389 2,173 Unrecognized prior service cost 5,517 5,941 6,365 (2,762) (3,097) (3,516) Unrecognized net (asset) obligation existing at date of initial adoption (19.5 years straight- line amortization) (2,230) (2,493) (2,756) 5,214 5,827 6,440 Minimum liability adjustment - - - (6,298) (6,538) (4,564) Net asset (liability) included in the balance sheet $ 10,722 $ 6,734 $ 8,385 $(21,840) $(21,530) $(19,148) Discount rate to compute projected benefit obligation 7.35% 7.25% 8.0% 7.35% 7.25% 8.0% Rate for future compensation increases 4.5 4.5 4.5 4.5 4.5 4.5 Expected long-term rate of return on plan assets 9.0 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 benefit obligation of this plan was $1,752,000, $1,581,000, and $857,000 at December 31, 1996, 1995 and 1994, respectively, with accrued pension costs of $918,000, $682,000, and $396,000. The Company's net periodic pension cost of this plan was $306,000, $184,000, and $125,000 for the same periods. During 1996, the SERP was merged with the Security Plan. Savings Plan - The Company has an Employee Savings Plan whereby, for each $1 of employee contribution up to 6 percent of their base 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 in any or all of seven investment options. The Company's contribution amounted to $2,285,904 in 1996, $2,426,840 in 1995, and $2,410,200 in 1994. 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 following tables set forth the amounts recognized in the Company's financial statements for year-end 1996, 1995 and 1994 and the funded status of the plan in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits other than Pensions", as of December 31: 1996 1995 1994 Postretirement Benefit Cost: (Thousands of Dollars) Service Cost $ 794 $ 763 $ 855 Interest Cost 3,172 3,571 3,334 Actual return on plan assets (1,410) (1,116) (1,114) Amortization of transition obligation (20-year amortization) 2,040 2,040 2,040 Net amortization and deferral (57) - - Regulatory assets - 506 (1,907) Voluntary severance program - 64 - Net cost $ 4,539 $ 5,828 $ 3,208 Funded Status: Accumulated postretirement benefit obligation (APBO) $(44,439) $(48,928) $(45,001) Plan assets at fair value 17,341 15,920 12,116 APBO in excess of plan assets (27,098) (33,008) (32,885) Unrecognized gain/losses (5,478) 378 773 Unrecognized transition obligation 32,640 34,680 36,720 Prepaid postretirement benefit cost $ 64 $ 2,050 $ 4,608 Discount rate 7.50% 7.50% 8.25% Medical and dental inflation rate 6.75 6.75 7.25 Long-term plan assets expected return 9.0 9.0 9.0 A one percent change in the medical inflation rate would change the APBO by 7.2 percent and the post retirement expense for 1996 by 8.6 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 $1,390,800 in 1996, $1,754,300 in 1995 and $776,400 in 1994. The funding to the VEBA was $0 in 1996, $916,200 in 1995, and $743,600 in 1994 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. Post-employment Retirement Benefits - The Company provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. The Company accrues for such post employment benefits. These benefits include salary continuation and related health care and life insurance for both long and short-term disability plans, workmen's compensation and health care for surviving spouse and dependent plan. The Company recognizes a deferred asset which represents future revenue expected to be realized at the time the post employment benefits are included in the Company's rates. The Company has recorded a liability of $4.1 million and a regulatory asset of $3.0 million which represents the costs associated with post employment benefits at December 31, 1996. The Company received an IPUC order 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 1996, 1995, and 1994. 1996 1995 1994 (Thousands of Dollars) Electric Plant in Service: Production $1,323,090 $1,350,239 $1,303,572 Transmission 371,123 330,812 308,055 Distribution 688,232 648,549 625,149 General and Other 155,120 152,230 147,122 Total in service 2,537,565 2,481,830 2,383,898 Less accumulated provision for depreciation 886,885 830,615 775,033 In service - Net $1,650,680 $1,651,215 $1,608,865 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 operation and maintenance expenses applicable to the projects. Each facility and extent of Company participation as of December 31, 1996 are as follows: Company Ownership Accumulated Electric Provision Name of Plant Location In Service for Depreciation % MW (Thousands of Dollars) Jim Bridger Rock Springs, WY Units 1-4 $382,135 $169,126 33 693 Boardman Boardman, OR 60,780 28,028 10 53 Valmy Units 1 Winnemucca, NV and 2 299,156 112,523 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 $34,974,000 in 1996, $44,278,000 in 1995, and $46,097,000 in 1994. 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 $8,953,000 in 1996, $8,696,000 in 1995, and $7,139,000 in 1994. INDEPENDENT AUDITORS' REPORT Board of Directors and Shareowners of Idaho Power Company: 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 schedule at Item 8. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and subsidiaries at December 31, 1996, 1995, and 1994, 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 schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Portland, Oregon January 31, 1997 IDAHO POWER COMPANY SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA: The following unaudited information is presented for each quarter of 1996, 1995 and 1994 (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 operations 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 December 30 31 1996 Revenues $146,629 $140,384 $149,652 $141,781 Income from operations 58,489 46,741 41,780 40,161 Income taxes 17,466 12,828 11,597 10,201 Net income 30,211 23,033 19,151 18,225 Dividends on preferred stock 1,952 1,927 1,954 1,632 Earnings on common stock 28,259 21,106 17,197 16,593 Earnings per share of common stock 0.75 0.56 0.45 0.44 1995 Revenues 131,336 130,254 148,726 135,306 Income from operations 46,552 38,681 45,637 45,122 Income taxes 14,234 10,951 12,442 10,786 Net income 20,727 17,588 23,771 24,833 Dividends on preferred stock 2,026 2,006 1,976 1,982 Earnings on common stock 18,701 15,582 21,795 22,851 Earnings per share of common stock 0.50 0.41 0.58 0.61 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 stock 0.44 0.41 0.38 0.57 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, 1996. (c) Exhibits. *Previously Filed and Incorporated Herein by Reference Exhibit File Number As 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. Exhibit File Number As Exhibit *3(b) 33-41166 4(b) Waiver resolution to Restated Articles of Incorporation adopted by Shareholders on May 1, 1991. *3(c) 33-00440 4(a)(xiv) By-laws of the Company amended on June 30, 1989, and presently in effect. *4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as of October 1, 1937, between the Company and Bankers Trust Company and R. G. Page, as Trustees. *4(a)(ii) Supplemental Indentures to Mortgage and Deed of Trust: Number Dated 1-MD B-2-a First July 1, 1939 2-5395 7-a-3 Second November 15, 1943 2-7237 7-a-4 Third February 1, 1947 2-7502 7-a-5 Fourth May 1, 1948 2-8398 7-a-6 Fifth November 1, 1949 2-8973 7-a-7 Sixth October 1, 1951 2-12941 2-C-8 Seventh January 1, 1957 2-13688 4-J Eighth July 15, 1957 2-13689 4-K Ninth November 15, 1957 2-14245 4-L Tenth April 1, 1958 2-14366 2-L Eleventh October 15, 1958 2-14935 4-N Twelfth May 15, 1959 2-18976 4-O Thirteenth November 15, 1960 2-18977 4-Q Fourteenth November 1, 1961 2-22988 4-B-16 Fifteenth September 15, 1964 2-24578 4-B-17 Sixteenth April 1, 1966 2-25479 4-B-18 Seventeenth October 1, 1966 2-45260 2(c) Eighteenth September 1, 1972 2-49854 2(c) Nineteenth January 15, 1974 2-51722 2(c)(i) Twentieth August 1, 1974 2-51722 2(c)(ii) Twenty-first October 15, 1974 2-57374 2(c) Twenty-second November 15, 1976 2-62035 2(c) Twenty-third August 15, 1978 33-34222 4(d)(iii) Twenty-fourth September 1, 1979 33-34222 4(d)(iv) Twenty-fifth November 1, 1981 33-34222 4(d)(v) Twenty-sixth May 1, 1982 33-34222 4(d)(vi) Twenty-seventh May 1, 1986 33-00440 4(c)(iv) Twenty-eighth June 30, 1989 33-34222 4(d)(vii) Twenty-ninth January 1, 1990 33-65720 4(d)(iii) Thirtieth January 1, 1991 33-65720 4(d)(iv) Thirty-first August 15, 1991 33-65720 4(d)(v) Thirty-second March 15, 1992 33-65720 4(d)(vi) Thirty-third April 16, 1993 1-3198 4 Thirty-fourth December 1, 1993 Form 8-K Dated 12/17/93 Exhibit File Number As Exhibit *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. Exhibit File Number As Exhibit *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(i)(ii) 1-3198 10(i)(ii) Third Restated and Amended Coal Form 10-Q Sales Agreement, dated January 1, for 3/31/96 1996, 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). Exhibit File Number As Exhibit *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 1-3198 10(n)(i) The Revised Security Plans for Form 10-K Senior Management Employees and for for 1994 Directors-a non-qualified, deferred compensation plan effective November 30, 1994. *10(n)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive Plan Form 10-K for senior management employees for 1994 effective January 1, 1995. *10(n)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for Form 10-K officers and key executives for 1994 effective July 1, 1994. 10(n)(iv)1 The Revised Security Plans for Senior Management Employees and for Directors-a non-qualified, deferred compensation plan effective August 1, 1996. *10(o) 33-65720 10(f) Residential Purchase and Sale Agreement, dated August 22, 1981, among the United Stated of American Department of Energy acting by and through the Bonneville Power Administration, and the Company. *10(p) 33-65720 10(g) Power Sales Contact, dated August 25, 1981, including amendments, among the United States of America Department of Energy acting by and through the Bonneville Power Administration, and the Company. *10(q) 33-65720 10(h) Framework Agreement, dated October 1, 1984, between the State of Idaho and the Company relating to the Company's Swan Falls and Snake River water rights. *10(q)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984, between the State of Idaho and the Company relating to the agreement filed as Exhibit 10(q). *10(q)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October 25, 1984, between the State of Idaho and the Company relating to the agreement filed as Exhibit 10(q). *10(r) 33-65720 10(i) Agreement for Supply of Power and Energy, dated February 10, 1988, between the Utah Associated Municipal Power Systems and the Company. 1 Compensatory Plan Exhibit File Number As Exhibit *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. *10(x) 1-3198 10(x) Agreement for design of substation Form 10-Q dated October 4, 1995, between the for 9/30/95 Company and Micron Technology, Inc. 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 Auditor's Consent 27 Financial Data Schedule IDAHO POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1996, 1995 and 1994 Column A Column B Column C Column D Column E Additions Charged Balance at Charged (Credited) Balance at Beginning to to Other Deduction End of Classification of Period Income Accounts (1) Period (Thousands of Dollars) 1996: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,397 $ - $3,003(2) $3,006 $1,394 Other Reserves: Injuries and damages reserve $1,500 $ - $ - $ - $1,500 Miscellaneous operating reserves $1,143 $ 829 $4,874 $ 198 $6,648 1995: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,377 $ 217 $2,927(2) $3,124 $1,397 Other Reserves: Injuries and damages reserves $1,500 $1,364 $ - $1,364 $1,500 Miscellaneous operating reserve $ 940 $ 460 $ (176) $ 81 $1,143 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 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 caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. IDAHO POWER COMPANY (Registrant) March 13, 1997 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 13, 1997 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, Chief Financial " J. LaMont Keen Officer and Treasurer (Principal Financial and Accounting Officer) By:/s/Robert D. Bolinder By:/s/Evelyn Loveless " Robert D. Bolinder Evelyn Loveless Director Director By:/s/Roger L. Breezley By:/s/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)(iv) The Revised Security Plans for Senior Management Employees and for Directors-a 72 non-qualified, deferred compensation plan effective August 1, 1996 12 Statement Re: Computation of Ratio of Earnings to Fixed 139 Charges 12(a) Statement Re: Computation of Supplemental Ratio of 140 Earnings to Fixed Charges 12(b) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred 141 Dividend Requirements 12(c) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed 142 Charges and Preferred Dividend Requirements. 21 Subsidiaries of Registrant 143 23 Independent Auditors' 144 Consent. 27 Financial Data Schedule 145 EX-10 2 Exhibit 10(n)(iv) IDAHO POWER COMPANY SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES Amended and Restated Effective August 1, 1996 TABLE OF CONTENTS ARTICLE I _ PURPOSE; EFFECTIVE DATE 1 ARTICLE II _ DEFINITIONS 2 2.1 Actuarial Equivalent 2 2.2 Administrative Committee 2 2.3 Beneficiary 2 2.4 Board 2 2.5 Change in Control 3 2.6 Change in Control Period 4 2.7 Company 4 2.8 Compensation 5 2.9 Compensation Committee 5 2.10 Contract of Participation 5 2.11 Disability 5 2.12 Early Retirement Date 5 2.13 Employer 5 2.14 Final Average Monthly Compensation 5 2.15 Frozen Retirement Benefit 6 2.16 Frozen Survivor Benefit 7 2.17 Normal Form of Benefit 7 2.18 Normal Retirement Date 7 2.19 Participant 8 2.20 Plan Year 8 2.21 Retirement 8 2.22 Retirement Plan 8 2.23 Security Plan Retirement Benefit 8 2.24 Target Retirement Percentage 8 2.25 Years of Participation 8 ARTICLE III _ PARTICIPATION AND VESTING 9 3.1 Eligibility and Participation 9 3.2 Vesting 9 3.3 Change in Employment Status 9 ARTICLE IV _ BENEFIT ELECTION 10 4.1 Benefit Election 10 4.2 Commencement of Benefits 10 ARTICLE V _ SURVIVOR BENEFITS 11 5.1 Pre-retirement Survivor Benefits 11 5.2 Post-termination Survivor Benefit 12 5.3 Survivor Benefit Election for Participants Prior to December 1, 1994. 12 5.4 Suicide 13 ARTICLE VI _ SECURITY PLAN RETIREMENT BENEFITS 14 6.1 Normal Retirement Benefit 14 6.2 Early Retirement Benefit 14 6.3 Early Retirement Factor 14 6.4 Early Termination Benefits 16 6.5 Termination After Change in Control 16 6.6 Form of Payment 17 ARTICLE VII _ OTHER RETIREMENT PROVISIONS 18 7.1 Disability 18 7.2 Withholding Payroll Taxes 18 7.3 Payment to Guardian 18 7.4 Accelerated Distribution 18 ARTICLE VIII _ BENEFICIARY DESIGNATION 20 8.1 Beneficiary Designation for Participant Not Eligible for Frozen Survivor Benefit 20 8.2 Beneficiary Designation for Participant Eligible for Frozen Survivor Benefit 21 8.3 Beneficiary Designation at Commencement of Benefits 23 8.4 Effect of Payment 23 ARTICLE IX _ ADMINISTRATION 24 9.1 Administrative Committee Duties 24 9.2 Indemnity of Administrative Committee 24 ARTICLE X _ CLAIMS PROCEDURE 26 10.1 Claim 26 10.2 Denial of Claim 26 10.3 Review of Claim 26 10.4 Final Decision 26 ARTICLE XI _ TERMINATION, SUSPENSION OR AMENDMENT 28 11.1 Termination, Suspension or Amendment of Plan 28 11.2 Change in Control 28 ARTICLE XII _ MISCELLANEOUS 29 12.1 Unfunded Plan 29 12.2 Unsecured General Creditor 29 12.3 Trust Fund 29 12.4 Nonassignability 30 12.5 Not a Contract of Employment 30 12.6 Governing Law 30 12.7 Validity 31 12.8 Notice 31 12.9 Successors 31 IDAHO POWER COMPANY SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES AMENDED AND RESTATED EFFECTIVE AUGUST 1, 1996 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, 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 August 1, 1996. 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. For purposes of Section 7.4, Actuarial Equivalent shall be calculated using the Pension Benefit Guaranty Immediate Rate as of the month preceding distribution plus 1% and the mortality table specified in the Retirement Plan of Idaho Power Company which may be amended from time to time. 2.2 Administrative Committee. "Administrative Committee" shall mean the Administrative Committee appointed by the Compensation Committee pursuant to Section 9.1 hereof to administer the Plan. 2.3 Beneficiary. "Beneficiary" shall mean the person, persons or entity designated by the Participant pursuant to Article VIII to receive any benefits payable under the Plan. Each such designation shall be made in a written instrument filed with the Administrative Committee and shall become effective only when received, accepted and acknowledged in writing by the Administrative Committee or its designee. 2.4 Board. "Board" shall mean the Board of Directors of the Company. 2.5 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 Securities Exchange Act of 1933 [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 such that, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board 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 at the beginning of the period; or (e) the Company enters into an agreement of merger, consolidation, share exchange or similar transaction with any other corporation other than a transaction which would result in the Company's voting stock outstanding immediately prior to the consummation of such transaction continuing to represent (either by remaining outstanding or by being converted into voting stock of the surviving entity) at least two-thirds of the combined voting power of the Company's or such surviving entity's outstanding voting stock immediately after such transaction; (f) the Board approves a plan of liquidation or dissolution of the Company or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets to a person or entity which is not an affiliate of the Company other than a transaction(s) for the purpose of dividing the Company's assets into separate distribution, transmission or generation entities or such other entities as the Company may determine. (g) any other event which shall be deemed by a majority of the Executive Committee of the Board to constitute a "Change in Control." 2.6 Change in Control Period. "Change in Control Period" shall mean the period beginning with a Change in Control as defined in Section 2.5 and ending with the earlier of: (i) termination date of the Change in Control as determined by the Compensation Committee or (ii) 24 months following the consummation of a Change in Control. 2.7 Company. "Company" shall mean the Idaho Power Company, an Idaho corporation, its successors and assigns. 2.8 Compensation Committee. "Compensation Committee" shall mean the Board committee assigned responsibility for administering Executive Compensation. 2.9 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. 2.10 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 the Employer in the form attached as Appendix A. 2.11 Disability. "Disability" shall mean that a Participant is eligible to receive benefits under the Long-Term Disability Program maintained by the Employer. 2.12 Early Retirement Date. "Early Retirement Date" shall mean the date on which a Participant terminates employment with the Employer, 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. 2.13 Employer. "Employer" shall mean the Company and any affiliated or subsidiary corporation designated by the Board, or any successors to the business thereof. 2.14 Final Average Monthly Compensation. "Final Average Monthly Compensation" shall mean the 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. 2.15 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. All Participants are 100% vested in their Frozen Retirement Benefit as of November 30, 1994. The Frozen Retirement Benefit shall be paid in the form and manner set forth in this Plan prior to the November 30, 1994 amendment including the early retirement reduction factors in effect under the May 1, 1990 restatement. 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. In addition, the Frozen Retirement Benefit shall also include any benefit payable from the Idaho Power Company Supplemental Employee Retirement Plan (SERP) before August 1, 1996 Restatement. The Participant's age, service and compensation at August 1, 1996 shall be used in determining this additional Frozen Retirement Benefit from the SERP. 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. 2.16 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. All Participants are 100% vested in their Frozen Survivor Benefit as of November 30, 1994. The Frozen Survivor Benefit shall be paid in the form and manner set forth in this Plan prior to the November 30, 1994 amendment. The Frozen Survivor 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. In addition, the Frozen Survivor Benefit shall also include any benefit payable from the Idaho Power Company Supplemental Employee Retirement Plan (SERP) before August 1, 1996 Restatement. The Participant's age, service and compensation at termination shall be used in determining this additional Frozen Survivor Benefit from the SERP. 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. 2.17 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. 2.18 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). 2.19 Participant. "Participant" shall mean any individual who is participating in or has participated in this Plan as provided in Article III. 2.20 Plan Year. "Plan Year" shall mean the calendar year effective November 30, 1994. 2.21 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. 2.22 Retirement Plan. "Retirement Plan" shall mean The Retirement Plan of Idaho Power Company as may be amended from time to time. 2.23 Security Plan Retirement Benefit. "Security Plan Retirement Benefit" shall mean the benefit determined under Article VI of this Plan. 2.24 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, exceeding ten (10). The maximum Target Retirement Percentage shall be seventy-five percent (75%). 2.25 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 employment in a senior management level position or a date designated by the Administrative 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%) immediately vested. 3.3 Change in Employment Status. If the Employer determines that a Participant's employment performance or classification is no longer at a level which deserves 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 of the change in employment status. 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 such date. 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. Participants in this Plan prior to December 1, 1994 or, if the Participant is deceased, the Beneficiary of such Participant, must elect to receive in the 30-day period immediately prior to receipt of any benefits under this Plan, (a) the Frozen Benefit (the Frozen Retirement Benefit or Frozen Survivor Benefit); or (b) the benefit accrued under this Plan as in effect after November 30, 1994. A Participant may at any time prior to death or commencing benefits elect pursuant to Section 5.3(b) that upon their death before commencing benefits, the Frozen Survivor Benefit be paid to the designated Beneficiaries. This election may be revoked by the Participant at any time. This election requires spousal consent if the Participant is married. 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 and the Retirement Plan benefit shall be determined as of the date of the Participant's death. For purposes of this section (a), the Retirement Plan benefit shall be the accrued benefit determined as of the date of death as defined in the Retirement Plan. (b) Payment. If the Participant is married on the date of death, the benefits shall be paid to the spouse of the Participant for the life of the spouse beginning on the first day of the month coincident with or following the date of death. 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 using the Actuarial Equivalent factors to reflect the number of years over ten (10) the spouse is 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 that is the Actuarial Equivalent of 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 to the spouse of the Participant for the life of the spouse beginning on the first day of the month coincident with or following the date of death. 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 using Actuarial Equivalent factors to reflect the number of years over ten (10) the spouse is 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 that is the Actuarial Equivalent of 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 pursuant to Sections 6.6. 5.3 Survivor Benefit Election for Participants Prior to December 1, 1994. (a) Death Prior to Commencing Benefits and Making Frozen Survivor Benefit Election. As described in Section 4.1, if a Participant who participated in this Plan prior to December 1, 1994 dies prior to commencing benefits, the Beneficiary of the Participant must elect to receive (a) the Frozen Survivor Benefit; or (b) the benefit accrued under Section 5.1 of this plan as in effect after November 30, 1994. If the Participant was unmarried at the time of the Participant's death and more than one primary Beneficiary has been designated, the Beneficiaries shall be deemed to have elected the benefit of highest value based on the Actuarial Equivalent basis specified in Section 2.1 of this Plan. (b) Election of Frozen Survivor Benefit Prior to Commencing Benefits. A Participant may at any time prior to commencing benefits elect that, upon their death before commencing benefits, the Frozen Survivor Benefit be paid to the designated Beneficiary(ies). This election, including the Beneficiary(ies) designation, requires spousal consent if married. This election may be revoked by the Participant at any time. If this election is made and the Participant dies before commencing benefits, the Frozen Survivor Benefit shall be paid to the Beneficiary(ies) in lieu of the survivor benefits described in Sections 5.1 and 5.2. 5.4 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 SECURITY PLAN RETIREMENT BENEFITS 6.1 Normal Retirement Benefit. The monthly Security Plan Retirement Benefit shall equal the Target Retirement Percentage multiplied by the Participant's Final Average Monthly Compensation, less the amount of the Participant's retirement benefit under the Retirement Plan Normal Form of Benefit regardless of the form actually selected by the Participant under the 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 Security Plan 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 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. 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 a Change in Control Period, the Early Retirement Factor shall be as described below: Exact Age When Early Payments Begin Retirement Factor 62 100% 61 96% 60 92% 59 87% 58 82% 57 77% 56 72% 55 67% Early retirement factors will be prorated to reflect retirement on other than an exact age (completed months). (b) If termination occurs without approval and the Participant has not terminated within a Change in Control Period, the Early Retirement Factor shall be the factor described in (a) above, 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 Compensation Committee for elected officers of the Employer and with the Chief Executive Officer of the Employer 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 Security Plan 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 the factor described in Section 6.3(a) for each month between the Participant's benefits commencement date and age sixty-two (62). (b) The Early Termination Benefit shall be offset by the Retirement Plan Normal Form of Benefit payable on the date of benefit commencement regardless of service. 6.5 Termination After Change in Control. If a Participant terminates within the Change in Control Period, 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 Security Plan Retirement Benefit shall be paid in the normal form provided below unless the Participant elects twelve months prior to commencement of benefits 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 surviving spouse 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 surviving spouse 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 Administrative 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 Administrative 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 Administrative Committee and the Employer from all liability with respect to such benefit. 7.4 Accelerated Distribution. Notwithstanding any other provision of the Plan, a Participant shall be entitled to receive, upon written request to the Administrative Committee, a lump sum distribution equal to ninety percent (90%) of the Actuarial Equivalent vested accrued Security Plan Retirement Benefit, as of the date thirty (30) days after notice is given to the Administrative Committee. The remaining balance of ten percent (10%) shall be forfeited by the Participant. The amount payable under this section shall be paid in a lump sum with ten (10) days following the thirty (30) day period outlined above. If a Participant requests and obtains an accelerated distribution under this Section 7.4 and remains employed by the Company, participation will cease and there will be no future benefit accruals under this Plan. Following the death of a Participant, the Beneficiary may, at any time, request an accelerated distribution under this section. If the deceased Participant named multiple Beneficiaries, then all named Beneficiaries must consent to the request for an accelerated distribution. The benefit payable to the Beneficiary shall be equal to ninety percent (90%) of the Actuarial Equivalent of the Security Plan Retirement Benefit payable to the Beneficiary. Payment of an accelerated distribution pursuant to this Section 7.4 shall completely discharge the Employer's obligation to the Participant and any Beneficiaries under this Plan. ARTICLE VIII BENEFICIARY DESIGNATION 8.1 Beneficiary Designation for Participant Not Eligible for Frozen Survivor Benefit. If the Participant is married, the Beneficiary shall be the Participant's spouse. Each unmarried Participant shall have the right, at any time, to designate any person or persons as Beneficiary or Beneficiaries (both primary as well as contingent) to whom payment under this Plan shall be made in the event of the Participant's death prior to the discharge of the Employer's obligation under this plan. Any Beneficiary designation may be changed by a Participant by the filing of a written form prescribed by the Administrative 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 filing 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 leave issue surviving, the issue shall take by right of representation; (c) the Participant's personal representative (executor or administrator). 8.2 Beneficiary Designation for Participant Eligible for Frozen Survivor Benefit. (a) Frozen Survivor Benefit Elected. If the Participant elects the Frozen Survivor Benefit pursuant to Section 5.3(b), the Participant shall designate any person or persons as Beneficiary or Beneficiaries (both primary as well as contingent) to whom payment of the Frozen Survivor Benefit shall be made in the event of the Participant's death prior to commencement of benefits under this Plan. If the Participant is married, designation of a Beneficiary other than the spouse shall require spousal consent. Any future change in Beneficiary shall also require spousal consent. (b) Frozen Survivor Benefit Not Elected by Married Participant. If the Participant does not elect the Frozen Survivor Benefit pursuant to Section 5.3(b) and the Participant is married, the Participant's spouse shall be the Beneficiary to whom payment of the Frozen Survivor Benefit shall be made in the event of the Participant's death prior to the commencement of benefits under the Plan. (c) Frozen Survivor Benefit Not Elected by Unmarried Participant. If the Participant does not elect the Frozen Survivor Benefit pursuant to Section 5.3(b) and the Participant is unmarried, the Participant shall designate any person or persons as Beneficiary(ies) (both primary as well as contingent) to whom payment of the Frozen Survivor Benefit shall be made in the event of the Participant's death prior to the commencement of benefits under this Plan. Any Beneficiary designation may be changed by a Participant by filing a written form prescribed by the Administrative 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 filing a Beneficiary designation form shall automatically revoke the prior designation unless the Frozen Survivor Benefit has been elected pursuant to Section 5.3(b) and a nonspouse beneficiary designated. 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 leave issue surviving, the issue shall take by right of representation; (c) the Participant's personal representative (executor or administrator). 8.3 Beneficiary Designation at Commencement of Benefits. Notwithstanding any Beneficiary designation made pursuant to Sections 8.1. and 8.2, a Participant who commences retirement benefits under Article VI shall: (a) If they elect the Frozen Retirement Benefit, designate a Beneficiary or Beneficiaries (primary as well as contingent) to whom any remainder of the payments shall be made in the event of their death prior to receiving 180 payments. (b) If they elect the benefit accrued under Article VI as in effect after November 30, 1994, the Beneficiary shall be the spouse pursuant to an election under Section 6.6. If no election has been made under Section 6.6(b), no benefits are payable upon the Participant's death. 8.4 Effect of Payment. The payment to the Beneficiary shall completely discharge Employer's obligations under this Plan. ARTICLE IX ADMINISTRATION 9.1 Administrative Committee Duties. This Plan shall be administered by an Administrative Committee which shall consist of not less than three (3) nor more than five (5) persons appointed by the Compensation Committee. Members of the Administrative Committee may be Participants under this Plan. The Administrative 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 Administrative Committee members shall control any decision. In the administration of this Plan, the Administrative 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 Administrative 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 Administrative Committee. To the extent permitted by applicable law, the Employer shall indemnify, hold harmless and defend the Administrative 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 Administrative 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 Administrative Committee members in accordance with the Articles 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 Administrative 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 Administrative Committee. The claim or request shall be reviewed by the Administrative 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, during a Change in Control Period, neither the Board nor the Administrative Committee may terminate this Plan with regard to accrued benefits of current Participants. No amendment may be made to the Plan during a Change in Control Period which would adversely affect the accrued 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 during any Change in Control Period. 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: ________________________________ Chairman By: ________________________________ Secretary Dated: _____________________________ 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 August 1, 1996 TABLE OF CONTENTS ARTICLE IPURPOSE; EFFECTIVE DATE 1 1.1 Purpose 1 ARTICLE IIDEFINITIONS 2 2.1 Actuarial Equivalent 2 2.2 Administrative Committee 2 2.3 Beneficiary 2 2.4 Board 3 2.5 Change in Control 3 2.6 Change in Control Period 5 2.7 Company 5 2.8 Compensation Committee 5 2.9 Contract of Participation 5 2.10 Employer 5 2.11 Participant 6 2.12 Plan Anniversary Date 6 2.13 Plan Year 6 2.14 Supplemental Retirement Benefit 6 2.15 Year of Service 6 ARTICLE IIIPARTICIPATION AND VESTING 7 3.1 Participation 7 3.2 Fee Reduction 7 3.3 Vesting 7 ARTICLE IVSURVIVOR BENEFITS 8 4.1 Death Benefit 8 4.2 Suicide 12 ARTICLE V RETIREMENT BENEFITS 13 5.1 Benefit 13 5.2 Form of Payment 13 5.3 Commencement of Benefit Payment 14 5.4 Grandfathered Form of Benefit 14 ARTICLE VIBENEFICIARY DESIGNATION 15 6.1 Beneficiary Designation 15 6.2 Amendments, Marital Status, No Participant Designation 15 6.3 Effect of Payment 16 ARTICLE VIITERMINATION, SUSPENSION OR AMENDMENT OF PLAN 17 7.1 Termination, Suspension or Amendment of Plan 17 7.2 Change in Control 17 ARTICLE VIIIADMINISTRATION 18 8.1 Administrative Committee Duties 18 8.2 Indemnity of Administrative Committee 19 ARTICLE IXCLAIMS PROCEDURE 20 9.1 Claim 20 9.2 Denial of Claim 20 9.3 Review of Claim 20 9.4 Final Decision 20 ARTICLE XMISCELLANEOUS 22 10.1 Unfunded Plan 22 10.2 Unsecured General Creditor 22 10.3 Trust Fund 23 10.4 Nonassignability 23 10.5 Governing Law 23 10.6 Validity 24 10.7 Notice 24 10.8 Successors 24 10.9 Payment to Guardian 24 10.10 Accelerated Distribution. 25 IDAHO POWER COMPANY SECURITY PLAN FOR BOARD OF DIRECTORS AMENDED AND RESTATED AUGUST 1, 1996 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 August 1, 1996. 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. For purposes of Section 10.10, Actuarial Equivalent shall be calculated using the Pension Benefit Guaranty Immediate Rate as of the month preceding distribution plus 1% and the mortality table specified in the Retirement Plan of Idaho Power Company which may be amended from time to time. 2.2 Administrative Committee. "Administrative Committee" shall mean the committee appointed by the Compensation Committee pursuant to Section 8.1 hereof to administer the Plan. 2.3 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 Administrative Committee and shall become effective only when received, accepted and acknowledged in writing by the Administrative Committee or its designee. 2.4 Board. "Board" shall mean the Board of Directors of the Company. 2.5 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 Securities Exchange Act of 1933 [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 such that, during any period of two (2) consecutive years, individuals who at the beginning of such period constitute the Board 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 at the beginning of the period; or (e) the Company enters into an agreement of merger, consolidation, share exchange or similar transaction with any other corporation other than a transaction which would result in the Company's voting stock outstanding immediately prior to the consummation of such transaction continuing to represent (either by remaining outstanding or by being converted into voting stock of the surviving entity) at least two-thirds of the combined voting power of the Company's or such surviving entity's outstanding voting stock immediately after such transaction; (f) the Board approves a plan of liquidation or dissolution of the Company or an agreement for the sale or disposition by the Company (in one transaction or a series of transactions) of all or substantially all of the Company's assets to a person or entity which is not an affiliate of the Company other than a transaction(s) for the purpose of dividing the Company's assets into separate distribution, transmission or generation entities or such other entities as the Company may determine. (g) any other event which shall be deemed by a majority of the Executive Committee of the Board to constitute a "Change in Control." 2.6 Change in Control Period. "Change in Control Period" shall mean the period beginning with a Change in Control as defined in Section 2.5 and ending with the earlier of: (i) termination date of the Change in Control as determined by the Compensation Committee or (ii) 24 months following the consummation of a Change in Control 2.7 Company. "Company" shall mean the Idaho Power Company, an Idaho corporation, its successors and assigns. 2.8 Compensation Committee. "Compensation Committee" shall mean the Board committee assigned responsibility for administering Executive Compensation. 2.9 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 the Employer, in the form attached as Appendix A. 2.10 Employer. "Employer" shall mean the Company and any affiliated or subsidiary corporation designated by the Board, or any successors to the business thereof. 2.11 Participant. "Participant" shall mean any individual who is elected to the Board and who has executed a Contract of Participation. 2.12 Plan Anniversary Date. "Plan Anniversary Date" shall mean February 1 of any year. 2.13 Plan Year. "Plan Year" shall mean the calendar year effective November 30, 1994. 2.14 Supplemental Retirement Benefit. "Supplemental Retirement Benefit" shall mean a benefit determined under Article V of this Plan. 2.15 Year of Service. "Year of Service" shall mean each twelve (12) months of service on the Board. 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%) immediately vested in their accrued benefit. ARTICLE IV SURVIVOR BENEFITS 4.1 Death Benefit. (a) For all Participants who are first elected to the Board 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 Administrative 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 Administrative 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 filing 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 Administrative 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, during a Change in Control Period, neither the Board nor the Administrative Committee may terminate this Plan with regard to accrued benefits of current Participants. No amendment may be made to the Plan during a Change in Control Period which would adversely affect the accrued 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 during any Change in Control Period. ARTICLE VIII ADMINISTRATION 8.1 Administrative Committee; Duties. This Plan shall be administered by an Administrative Committee which shall consist of not less than three (3) nor more than five (5) persons appointed by the Compensation Committee. Members of the Administrative Committee may be Participants under this Plan. The Administrative 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 Administrative Committee members shall control any decision. In the administration of this Plan, the Administrative 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 Administrative 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 Administrative Committee. To the extent permitted by applicable law, the Employer shall indemnify, hold harmless and defend the Administrative 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 Administrative 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 Administrative 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 Administrative 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 Administrative Committee. The claim or request shall be reviewed by the Administrative 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 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. 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 10.3, 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 Administrative 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 Administrative 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 Administrative Committee and the Employer from all liability with respect to such benefit. 10.10 Accelerated Distribution. Notwithstanding any other provision of the Plan, a Participant shall be entitled to receive, upon written request to the Administrative Committee, a lump sum distribution equal to ninety percent (90%) of the Actuarial Equivalent vested accrued Security Plan Retirement Benefit, as of the date thirty (30) days after notice is given to the Administrative Committee. The remaining balance of ten percent (10%) shall be forfeited by the Participant. The amount payable under this section shall be paid in a lump sum with ten (10) days following the thirty (30) day period outlined above. If a Participant requests and obtains an accelerated distribution under this Section 10.10 and remains a director of the Company, participation will cease and therewill be no future benefit accruals under this Plan. Following the death of a Participant, the Beneficiary may, at any time, request an accelerated distribution under this section. If the deceased Participant named multiple Beneficiaries, then all named Beneficiaries must consent to the request for an accelerated distribution. The benefit payable to the Beneficiary shall be equal to ninety percent (90%) of the Actuarial Equivalent of the Security Plan Retirement Benefit payable to the Beneficiary. Payment of an accelerated distribution pursuant to this Section 10.10 shall completely discharge the Employer's obligation to the Participant and any Beneficiaries under this Plan. IDAHO POWER COMPANY By: _________________________ Chairman Dated:_________________________ 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-12 3
Exhibit 12 Idaho Power Company Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1991 1992 1993 1994 1995 1996 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618 Income taxes: Income taxes (includes amounts charged to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316 Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776 Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092 Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710 Fixed Charges: Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165 Amortization of debt discount, expense and premium - net 374 392 507 567 567 594 Interest on short-term bank loans 935 647 220 1,157 3,144 2,269 Other interest 3,297 1,011 2,023 1,538 1,598 2,319 Interest portion of rentals 884 683 1,077 794 925 991 Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338 Earnings - as defined $138,876 $139,293 $178,471 $164,401 $192,714 $201,048 Ratio of earnings to fixed charges 2.32X 2.48X 3.10X 2.98X 3.36X 3.45X
EX-12.A 4
Exhibit 12(a) Idaho Power Company Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1991 1992 1993 1994 1995 1996 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618 Income taxes: Income taxes (includes amounts charged to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316 Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776 Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092 Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710 Fixed Charges: Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165 Amortization of debt discount, expense and premium - net 374 392 507 567 567 594 Interest on short-term bank loans 935 647 220 1,157 3,144 2,269 Other interest 3,297 1,011 2,023 1,538 1,598 2,319 Interest portion of rentals 884 683 1,077 794 925 991 Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338 Suppl increment to fixed charges* 1,599 2,487 2,631 2,622 2,611 2,600 Total supplemental fixed charges 61,459 58,628 60,164 57,850 59,992 60,938 Supplemental earnings - as defined $140,475 $141,780 $181,102 $167,023 $195,325 $203,648 Supplemental ratio of earnings to fixed charges 2.29X 2.42X 3.01X 2.89X 3.26X 3.34X * 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 5
Exhibit 12(b) 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) 1991 1992 1993 1994 1995 1996 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618 Income taxes: Income taxes (includes amounts charged to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316 Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776 Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092 Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710 Fixed Charges: Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165 Amortization of debt discount, expense and premium - net 374 392 507 567 567 594 Interest on short-term bank loans 935 647 220 1,157 3,144 2,269 Other interest 3,297 1,011 2,023 1,538 1,598 2,319 Interest portion of rentals 884 683 1,077 794 925 991 Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338 Preferred dividends requirements 6,663 7,611 8,547 10,682 12,392 12,146 Total fixed charges and preferred dividends 66,523 63,752 66,080 65,910 69,773 70,484 Earnings - as defined $138,876 $139,293 $178,471 $164,401 $192,714 $201,048 Ratio of earnings to fixed charges and preferred dividends 2.09X 2.18X 2.70X 2.49X 2.76X 2.85X
EX-12.C 6
Exhibit 12(c) 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) 1991 1992 1993 1994 1995 1996 Computation of Ratio of Earnings to Fixed Charges: Consolidated net income $ 57,872 $ 59,990 $ 84,464 $ 74,930 $ 86,921 $ 90,618 Income taxes: Income taxes (includes amounts charged to other income and deductions) 24,321 24,601 38,057 35,307 49,498 51,316 Investment tax credit adjustment (3,177) (1,439) (1,583) (1,064) (1,086) 776 Total income taxes 21,144 23,162 36,474 34,243 48,412 52,092 Income before income taxes 79,016 83,152 120,938 109,173 135,333 142,710 Fixed Charges: Interest on long-term debt 54,370 53,408 53,706 51,172 51,147 52,165 Amortization of debt discount, expense and premium - net 374 392 507 567 567 594 Interest on short-term bank loans 935 647 220 1,157 3,144 2,269 Other interest 3,297 1,011 2,023 1,538 1,598 2,319 Interest portion of rentals 884 683 1,077 794 925 991 Total fixed charges 59,860 56,141 57,533 55,228 57,381 58,338 Suppl increment to fixed charges* 1,599 2,487 2,631 2,622 2,611 2,600 Supplemental fixed charges 61,459 58,628 60,164 57,850 59,992 60,938 Preferred dividend requirements 6,663 7,611 8,547 10,682 12,392 12,146 Total supplemental fixed charges and preferred dividends 68,122 66,239 68,711 68,532 72,384 73,084 Supplemental earnings - as defined $140,475 $141,780 $181,102 $167,023 $195,325 $203,648 Supplemental ratio of earnings to fixed charges and preferred dividends 2.06X 2.14X 2.64X 2.44X 2.70X 2.79X * 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 7 EXHIBIT 21 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 Inc., an Idaho Corporation 6. Idaho Power Resources Corporation, an Idaho Corporation EX-23 8 EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-51215, and 333-00139 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, 1997 appearing in the Annual Report on Form 10-K of Idaho Power Company for the year ended December 31, 1996. DELOITTE & TOUCHE LLP Portland, Oregon March 14, 1997 EX-27 9
UT This schedule contains summary financial information extracted from balance sheets, income statements and cash flow statements and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 1,694,631 36,502 144,116 420,088 0 2,295,337 94,031 358,455 242,088 694,574 0 106,975 716,218 0 22,332 54,016 71 0 0 0 701,151 2,295,337 578,445 52,092 391,274 443,366 135,079 12,534 147,613 56,995 90,618 7,463 83,155 69,924 52,165 174,415 2.21 2.21
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