-----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, S9Iksj14mEcWfX64WdpLs/CTNspGvQyGX0xF5gXevszEaMHqxmp0kWWfPVDQWFep LX39oIlIfs7AeCoIhumGIQ== 0000049648-00-000002.txt : 20000307 0000049648-00-000002.hdr.sgml : 20000307 ACCESSION NUMBER: 0000049648-00-000002 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 20000303 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: SEC FILE NUMBER: 001-03198 FILM NUMBER: 560353 BUSINESS ADDRESS: STREET 1: 1221 W IDAHO ST STREET 2: PO BOX 70 CITY: BOISE STATE: ID ZIP: 83702 BUSINESS PHONE: 2083882200 10-K405 1 TABLE OF CONTENTS PART I PAGE ITEM 1. BUSINESS 2 GENERAL 2 POWER SUPPLY 5 DIVERSIFIED BUSINESS OPERATIONS 6 ELECTRIC INDUSTRY RESTRUCTURING 7 FUEL 7 WATER RIGHTS 8 REGULATION 9 ENVIRONMENTAL REGULATION 9 RATES 11 CONSTRUCTION PROGRAM 12 FINANCING PROGRAM 13 ITEM 2. PROPERTIES 14 ITEM 3. LEGAL PROCEEDINGS 16 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 18 EXECUTIVE OFFICERS OF THE REGISTRANTS 18 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS 20 ITEM 6. SELECTED FINANCIAL DATA 21 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 22 ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 36 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 37 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 72 PART III ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS* 72 ITEM 11.EXECUTIVE COMPENSATION* 72 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT* 72 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 72 PART IV ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 72 SIGNATURES 78-79 *INCORPORATED BY REFERENCE. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K-405 (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ................... to ................................................................. Exact name of Registrants as specified in Commissiontheir charters, address of principal executive IRS Employer Iden- File Numberoffices and Registrants' telephone number tification Number 1-14465 IDACORP, Inc. 82-0505802 1-3198 Idaho Power Company 82-0130980 1221 W. Idaho Street Boise, ID 83702-5627 (208) 388-2200 State or other jurisdiction of incorporation: Idaho SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of exchange on which registered IDACORP, Inc.: Common Stock, without par value New York and Pacific SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Idaho Power Company: Preferred Stock Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have 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 registrants' 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 and non-voting common stock held by nonaffiliates (March 1, 1999) IDACORP, Inc.: 37,497,405 Idaho Power Company: None Number of shares of common stock outstanding at February 28, 1999: IDACORP, Inc.: 37,612,351 Idaho Power Company: 37,612,351 shares all of which are held by IDACORP, Inc. Documents Incorporated by Reference: Part III, Item 10 Portions of the joint proxy statement of the Registrants. Item 11 to be filed pursuant to Regulation 14A for the 1999 Annual Meeting of Shareholders to be Item 12 held on May 5, 1999. Item 13 PART I - IDACORP, Inc. and Idaho Power Company: ITEM 1. BUSINESS SAFE HARBOR STATEMENT 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 IDACORP, Inc. (Company), a holding company, was incorporated under the laws of the state of Idaho in 1998. The Company's principal subsidiary is Idaho Power Company (IPC), an electric public utility company that represents over 90 percent of the Company's total assets and is its principal operating subsidiary. The Company's other subsidiaries are Ida-West Energy Company (Ida-West) and IDACORP Energy Solutions Inc. (IES). Subsidiaries of IDACORP - IPC 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. IPC 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 780,000. IPC holds franchises in approximately 70 cities in Idaho and ten cities in Oregon, and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 28 counties in Idaho, three counties in Oregon and one county in Nevada. As of December 31, 1998, IPC supplied electric energy to 373,730 general business customers and employed 1,669 people in its operations. IPC's results of operations, like those of certain other utilities in the Northwest, can be significantly affected by changing weather, precipitation and streamflow conditions. In 1993 a power cost adjustment (PCA) mechanism was implemented in IPC's Idaho jurisdiction. With the implementation of the PCA, which includes a major portion of the operating expenses with the largest variation potential (net power supply costs), IPC'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. IPC operates 17 hydro power plants and shares ownership in three coal-fired generating plants (see Item 2 - "Properties"). IPC 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. IPC has participated in the development of thermal generation in Wyoming, Oregon and Nevada using low- sulfur coal from Wyoming and Utah. For the year ended December 31, 1998, total revenues from residential customers accounted for 41percent of total general business revenues. Commercial customers with less than 1,000 kilowatt (kW) demand accounted for 23 percent, industrial customers with 1,000 kW demand and over accounted for 24 percent, irrigation customers accounted for 11 percent and other revenues accounted for 1 percent. IPC's principal commercial and industrial customers are involved in: elemental phosphorus production; food processing; phosphate fertilizer production; electronics and general manufacturing; lumber; beet sugar refining; and the recreation industry, such as lodges, condominiums, ski lifts and related facilities. The off-system revenue percentage increased in 1998 due primarily to increases in electricity trading activity. Firm energy demand, hydroelectric generating conditions and market conditions throughout the west also affect the volume and price of off-system sales. IPC intends to be a competitive energy provider, including both electricity and natural gas and operates gas trading offices in Houston, Texas to serve the southern and eastern United States and Boise, Idaho, to serve the northwest and Canadian markets. IPC has also significantly increased its participation in the wholesale electricity markets. Ida-West was formed in 1989 to participate through partnership interests in cogeneration and small power production (CSPP) projects. Ida-West holds investments in 13 operating hydroelectric plants with a total generating capacity of approximately 72 megawatts (MW). 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. Ida-West has a partnership interest in the Hermiston Power Project, a 536 MW, gas-fired 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. Construction of this project could begin in 1999. IPC has purchased all of the power from the five Idaho hydroelectric entities that are fifty percent owned by Ida-West, totaling approximately $8.7 million in 1998. At December 31, 1998, total investment in Ida-West was $26.9 million. IES was created in December 1997 to address and pursue opportunities to provide expanded products and services to present and future customers. To date there has been limited activity in this entity. Subsidiaries of IPC - Idaho Energy Resources Company (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, 1998, total investment in IERCo was $10.7 million. IDACORP Financial Services, Inc. (IFS), was organized in 1986 to pursue a non-regulated diversification program. At the end of 1998 IFS was participating in 12 affordable housing programs which provide a return primarily by reducing federal income taxes through tax credits and tax depreciation benefits. As of December 31, 1998, total investment in IFS was $15.0 million. Stellar Dynamics, Inc (Stellar) was formed in 1995 to commercialize expertise in control technology for electric substations and power plants. Currently, Stellar's market focus is in complex control and automation systems for the electric utility sector and industrial applications. Stellar also provides design and engineering for complete electric substations. Stellar markets its products nationally and internationally. As of December 31, 1998, total investment in Stellar was $1.1 million. Applied Power Corporation (APC) is a Lacey, Washington based company that designs, supplies and distributes photovoltaic (PV) systems. APC provides reliable, cost-effective solar electric products and systems for industry, contractors, utilities, government and an international network of solar dealers and distributors. As of December 31, 1998, total investment in APC was $4.7 million. Pathnet/Idaho Equipment, LLC (Pathnet) was formed in 1998 to develop and distribute microwave communication services and products. As of December 31, 1998, total investment in Pathnet was $1.5 million. Research and Development, Renewable Energy Sources and Fuel Cells - During 1998, the Company spent approximately $1.2 million on research and development of which $0.9 million was through membership in Electric Power Research Institute (EPRI). EPRI's mission is to discover, develop and deliver advances in science and technology. Some of the subjects of EPRI projects include: electrification technologies, power quality, electric transportation systems, EMF assessment/risk management and air quality issues. IPC 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 IPC. In 1992, IPC joined Southern California Edison, the U.S. Department of Energy (DOE) and others in retrofitting an existing 10-megawatt central receiver solar thermal experimental power plant now called Solar Two near Barstow, California. IPC has contributed $630,500 through 1998 and EPRI contributed an additional $630,500 of matching funds, bringing credited contribution to approximately $1.3 million. Solar Two was first synchronized to Southern California Edison's system in May 1996. In 1998, IPC entered into an agreement with Proton Energy Systems (PES) to purchase an electrolyzer that produces hydrogen from electricity. IPC is conducting a pilot program with the electrolyzer as part of its efforts to gain experience with fuel cells and to gain first-hand working knowledge and information about the technology. Because of IPC's low cost of electrical power, there is great potential that the electrolyzer can supply high-value hydrogen to consumers at their plant sites and at a lower cost than conventional bottled hydrogen. IPC has an agreement with the DOE, Lockheed and PES to test the electrolyzer and validate the operating characteristics of the unit. In May 1998, a subsidiary of IPC entered into a Research and Development and Option Agreement with Northwest Power Systems (NPS) to provide technical and financial resources to NPS for the on-going development of a fully integrated, small-scale fuel cell. NPS has patented a unique fuel reformer that allows for the processing of a number of fuels into hydrogen that is then used for the generation of electricity. A fully operational prototype has been constructed and successfully tested. Energy Efficiency - As an active member of the Northwest Energy Efficiency Alliance, IPC has been shifting the focus of its conservation, or demand- side management (DSM), activities towards regional market transformation efforts and renewing its commitment to public purpose programs. At the same time, IPC has discontinued many of the traditional DSM programs that required deferral of costs. In 1998, $2.9 million was expended on energy-efficiency programs. POWER SUPPLY IPC meets its system load requirements using a combination of its own system generation, mandated purchases from private developers (see CSPP purchases below) and purchases from other utilities and power producers. IPC's generating stations and capacities are listed in Item 2. Properties. Historically, under normal water conditions, IPC's hydro system supplies approximately 56 percent, thermal generation accounts for 33 percent and purchased power and other interchanges contribute the remaining 11 percent of total system requirements. IPC's system is dual-peaking, with the larger peak demand generally occurring in the summer. The system peak demand for 1998 was 2,747 MW, set on July 14, 1998. Peak demands in 1997 and 1996 were 2,545 MW and 2,661 MW respectively. IPC periodically updates its load and resource projections and now expects total system energy requirements to grow 2.0 percent annually over the next five years. Because of its reliance upon hydroelectric generation, which varies according to streamflows, IPC's generating system is constrained more by resource availability than by capacity. 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 contract that expires in 2000 and with Seattle City Light under a contract that expires in 2003. During the 1999-2003 period, IPC plans to provide all the energy required to serve its firm load requirements by using its hydroelectric and coal-fired generating units, supplemented by purchases of power from neighboring utilities or marketing entities. Even though its significant hydroelectric generation can operate to meet peak demands, seasonal energy requirements are important to IPC because its seasonal energy capability is determined in part by the availability of water. In 1996, 1997 and 1998, IPC's hydro generating system experienced above average water years. Early reports for 1999 indicate that three major factors affecting hydro production, mountain snowpack, carryover reservoir storage and precipitation are all above normal for the time of year. IPC'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. IPC's transmission system 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 interchange, purchase and sale of power among most of the electric systems in the West. IPC 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. CSPP Purchases - As a result of the enactment of the Public Utilities Regulatory Policy Act of 1978 (PURPA) and the adoption of avoided cost standards by the IPUC, IPC has entered into contracts for the purchase of energy from private developers. Because IPC's service territory encompasses substantial irrigation canal development, forest product production facilities, mountain streams, and food processing facilities, considerable amounts of energy are available from these sources. Such energy comes from hydropower 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 66 CSPP projects on-line as of December 31, 1998 is $58.0 million. During 1998, IPC purchased 907.1 million kWh of power from these private developers at a blended price of 6.0 cents per kWh. In 1995 IPC received approval from the IPUC to reduce published CSPP rates for new projects less than one MW. In addition, the IPUC determined that negotiated rates for future CSPP projects larger than one MW should be tied more closely to values determined in IPC's integrated resource planning process. In subsequent orders, the IPUC limited the length of new contracts to a maximum of five years (see "Rates"). Wholesale Power Sales - IPC has firm wholesale power sales contracts with several entities. These contracts are for various amounts of energy, ranging up to 100 average MW, and are of various lengths expiring between 1999 and 2009. IPC is actively participating in the wholesale electricity markets and as a result, has increased significantly the volume of electricity sold and purchased. IPC is actively marketing this power to other entities as it becomes available. Transmission Services - IPC has long had an informal open-access transmission policy and is experienced in providing reliable, high quality, economical transmission service. IPC provides various firm and non-firm wheeling services for several surrounding utilities. In 1996 the FERC issued Order Nos. 888 and 889 dealing with open access non-discriminatory transmission services by public utilities, and standards of conduct regarding these services. 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. In November 1995, IPC 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 IPC uses in its own operations to anyone seeking them. IPC requested and received permission to implement these tariffs beginning February 1, 1996. On July 8, 1996, IPC 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, the FERC issued an unconditional acceptance of the terms and conditions of this tariff. The rate was not subject to review. IPC'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 allows IPC to provide transmission services and reach a broad power sales market. DIVERSIFIED BUSINESS OPERATIONS The Company has been pursuing a strategy of expanding non- regulated activities and separating regulated from non-regulated activities. The following discussion relates to these expanded activities. In 1997 and 1998 IPC greatly increased its participation in the western wholesale electricity markets. In mid-1997, IPC began trading natural gas. By December 1998, natural gas sales volumes exceeded 482 million cubic feet per day. These changes reflect the Company's intent to be a competitive energy provider of both of these commodities. In 1998, the Company began offering two new products to retail customers, satellite television and billpayer insurance. On February 17, 1998, the Company announced it had joined the Allied Utility Network (AUN), a member-supported alliance that provides customer research, marketing and other support services to utilities. Through its relationship with AUN, the Company is developing new products and services to offer to retail customers. Other members of the alliance include Colorado Springs Utilities of Colorado Springs, Colorado, Omaha Public Power District of Omaha, Nebraska, Snapping Shoals EMC of Covington, Georgia and Cobb Electric Membership Corporation of Marietta, Georgia. Collectively, the utilities serve approximately one million customers. By the end of 1999, the Company intends to have transferred IPC's non-utility business activities and unregulated subsidiaries under the holding company or its unregulated subsidiaries. ELECTRIC INDUSTRY RESTRUCTURING Competition is increasing in the electric utility industry. 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 traditional service territory. A requirement to transmit directly to retail customers would permit retail customers to purchase electric capacity and energy from their local electric utility or from any other electric utility or independent power supplier. In 1997, the Idaho Legislature appointed a committee to study restructuring of the electric utility industry. Legislation resulting from this committee required the IPUC to begin an investigation into the unbundling of costs into its various delivery and energy components. IPC filed cost unbundling studies in July and December 1997. The IPUC compiled cost data presented by all the electric utilities and presented that information to the legislature. Although the committee will continue studying a variety of restructuring ideas, it is not expected to recommend restructuring legislation in the foreseeable future. In response to the changing electric utility industry, IPC has adjusted its resource acquisition policy to emphasize resource marketability. IPC 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 IPC's requirements. In practice, this policy will result in the purchase of power from others through the marketplace when purchases are the lowest cost resources, and new investment in resource ownership by IPC only when a Company-owned resource would be cost effective. With a predominantly hydroelectric base and low-cost thermal plants, IPC 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, IPC has access to all the major electric systems in the West. FUEL IPC, through Idaho Energy Resources Co., owns a one-third interest in the Bridger Coal Company, which owns the Jim Bridger coal mine supplying coal to the Jim Bridger generating plant in Wyoming. The mine, located near the Jim Bridger plant, operates under a long- term sales agreement that provides for delivery of coal over a 51- year period ending in 2025 (See Item 2 "Properties"). The Jim Bridger coal mine has sufficient reserves to provide coal deliveries pursuant to the sales agreement. IPC 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 IPC is a ten-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 IPC to take advantage of lower-cost spot market coal for some or all of the Boardman plant's requirements. SPPCo, with whom IPC 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 1981 with Southern Utah Fuel Company, a subsidiary of Canyon Fuel Co., LLC, 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 300,000 tons per year to a maximum of 1,000,000 tons per year. This flexibility accommodates fluctuations in energy demand, hydroelectric generating conditions and purchases of energy from CSPP facilities. WATER RIGHTS Except as discussed below, IPC has acquired valid water rights under applicable state law for all waters used in its hydroelectric generating facilities. In addition, IPC 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, IPC'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 IPC's water rights at certain hydroelectric generating facilities. In reaction to these reductions, IPC initiated and continues to pursue a course of action to determine and protect its water rights. As part of this process, IPC and the state of Idaho signed the Swan Falls agreement on October 25, 1984, which provided a level of protection for IPC'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 IPC'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 IPC's project licenses that the relationship established by the agreement would not be considered by the FERC as being inconsistent with the terms of IPC'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 IPC'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. IPC 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. IPC does not anticipate any modification of its water rights as a result of the adjudication process. REGULATION IPC 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 Utility Commission (OPUC) and the Public Service Commission of Nevada. IPC is also under the regulatory jurisdiction of the IPUC, OPUC and the Public Service Commission of Wyoming as to the issuance of securities. IPC is subject to the provisions of the Federal Power Act as a "licensee" and "public utility" as therein defined. IPC'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 IPC's purchase of power from CSPP facilities. As a licensee under the Federal Power Act, IPC 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 related FERC regulations. These conditions and regulations include 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. IPC'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. With respect to project property located in Oregon, these facilities are subject to the Oregon Hydroelectric Act. IPC has obtained Oregon licenses for these facilities and these licenses are not in conflict with the Federal Power Act or IPC'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 IPC'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 present environmental laws and regulations, IPC estimates its capital expenditures (excluding allowance for funds used during construction) for environmental matters for 1999 and during the period 2000-2003 will total approximately $9.5 million and $48.0 million, respectively. Mitigation of environmental concerns due to relicensing of hydro facilities will be a major portion of these expenditures. IPC anticipates incurring approximately $23.8 million annually of operating expenses for environmental facilities during the period 1999-2003, based upon present environmental laws and regulation. Clean Air - IPC has analyzed the Clean Air Act's legislation and its effects upon IPC and its ratepayers. IPC's coal-fired plants in Nevada and Oregon already meet the federal emission rate standards for sulfur dioxide (SO2) and IPC's coal-fired plant in Wyoming meets that state's even more stringent SO2 regulations. The Company foresees no adverse effects upon its operations with regard to SO2 emissions. On July 16, 1997, the EPA announced new National Ambient Air Quality Standards for ozone and Particulate Matter (PM). In addition to these standards, on July 17, 1997, the EPA proposed regional haze regulations for protection of visibility in national parks and wilderness areas. Impacts of the ozone and PM regulations and the proposed regional haze regulations on IPC's thermal operations are unkown at this time. Although not presently required to meet any federal nitrogen oxide (NOx) limits, North Valmy, Boardman, and Jim Bridger Unit 4 elected to meet Phase I NOx limits beginning in 1998. As a result of this voluntary "early election" these units will not be required to meet the more restrictive Phase II NOx limits until 2008. Had the units not voluntarily "early elected," they would have been required to meet the Phase II NOx beginning in 2000. Jim Bridger Units 1, 2 and 3 were accepted as substitution units in 1995 and subject to NOx limits of Phase I instead of the more restrictive limits of Phase II. Jim Bridger is in the process of installing low NOx burners to reduce NOx levels even lower than currently required. Water - IPC 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. IPC has agreed to meet certain dissolved oxygen standards at its American Falls hydroelectric generating plant. IPC signed amendments to the agreements relating to the operation of the American Falls Dam and the location of water quality monitoring facilities. The amendments were made to provide more accurate and reliable water quality measurements necessary to maintain water quality standards downstream from IPC's plant during the May 15 to October 15 period each year. IPC 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. IPC 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. IPC 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, IPC sponsors ongoing programs for the control of fish disease and improvement of fish production. IPC'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. At December 31, 1998, the investment in these facilities was $12.2 million and the annual cost of operation pursuant to FERC License 1971 was $2.4 million for 1998. Endangered Species - Several species of salmon and Snake River mollusks living within IPC's operating area are listed as threatened or endangered. IPC continues to review and analyze the effect such designation has on its operations. IPC is cooperating with various governmental agencies to resolve issues related to these species. (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. IPC continues to meet all federal requirements of TSCA for the continued use of equipment containing PCBs. IPC has a program to make the 200-plus substations on its system non-PCB. While IPC's use of equipment containing PCBs falls well within the federal standards, IPC has voluntarily decided to virtually eliminate these compounds from its 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 IPC costs for the disposal of PCBs from the Company's system were $0.9 million, $1.0 million and $0.5 million for 1996, 1997 and 1998 respectively. All generation facilities are presently non-PCB. IPC anticipates that all of its substations, except for capacitors, will be non-PCB by the end of 1999. RATES Idaho Jurisdiction The May 1998 adjustment to rates includes the deferred costs from the 1997-98 PCA year as well as the difference between base power supply cost assumptions and forecasted power supply costs. The 1998-99 forecast assumed a return to more normal hydroelectric generating conditions. This resulted in forecasted net power supply costs being near the amounts used to establish base rates in past regulatory proceedings. The May 1998 rate adjustment increases expected annual revenue by $34.0 million above the amount that would have been received at the 1997 rates, and $17.3 million above what would be expected at base rates during this rate period. So far in the current rate period, actual power costs have been less than forecast, due to better than forecast hydroelectric generating conditions. We have recorded a reduction to regulatory assets of $10.4 million as of December 31, 1998. The variance that exists at the end of the 1998-99 rate period will be trued-up in the next annual PCA adjustment. The May 1996 PCA adjustment decreased Idaho jurisdictional PCA rates 5.9%. IPC's May 1997 PCA adjustment, combined with the revenue sharing mechanism described below, decreased rates an additional 0.63%. On August 3, 1995, IPC filed a proposal with the IPUC to support IPC's organizational redesign. In response to IPC's proposal, the IPUC approved a Settlement that authorizes IPC to defer and amortize costs related to reorganization in return for a general rate freeze through the end of 1999. The Settlement gives IPC time to pursue and to implement its efficiency and growth initiatives with the assurance of a reasonable level of financial performance without the need to change customer prices. Under the Settlement, which remains in effect through 1999, when IPC's actual annual earnings exceed an 11.75 percent return on year-end common equity for the Idaho jurisdiction, IPC will share 50 percent of the additional earnings with its Idaho retail customers. IPC set aside approximately $4.9 million and $7.6 million in 1996 and 1997 respectively for the benefit of its Idaho customers. Of the $4.9 million set aside in 1996, $1.4 million was applied against the regulatory asset balance of Idaho demand-side management/conservation (DSM) expenditures while the remaining $3.5 million was refunded. Of the $7.6 million set aside in 1997, $3.0 million was applied against the DSM regulatory asset balance, $2.7 million was used to fund (through May 15, 1999) a DSM-related rate increase, $0.8 million to recover 1997 Northwest Energy Efficiency Alliance (NEEA) expenditures, and the remainder was held in reserve to fund 1998 NEEA expenses once they have been approved for recovery by the IPUC. IPC has set aside approximately $5.4 million in 1998 for the benefit of its Idaho customers. The ultimate disposition of this benefit is yet to be determined. 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. IPC has received approval from the Idaho State Tax Commission and the Internal Revenue Service on the accounting treatment for the tax credits up to a maximum of $30 million of ADITC's. As of December 31, 1998, no ADITCs have been used under the regulatory agreement. Other important points in the Settlement are that IPC 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 that the Company agrees that its quality of service will not decline as a result of corporate reorganization. In 1998, IPC received an order from the IPUC reducing the amortization period for the regulatory assets associated with demand-side management programs from 24 years to 12 years. At the same time the IPUC approved an additional $16 million of Idaho allocated demand-side management expenditures for recovery through rates resulting in an increase of 0.67 percent to Idaho customers effective May 16, 1999. At present this increase is being funded through amounts set aside for 1997 customer revenue sharing. The IPUC order has been appealed to the Idaho Supreme Court by a customer group. In December 1993, IPC filed with the IPUC for permission to approve lower published prices for new CSPP contracts. In response to IPC'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 one MW should be tied more closely to values determined by IPC's integrated resource planning process. In a subsequent order issued on September 4, 1996, the IPUC limited the contract term that a new CSPP project larger than one MW could request to a maximum of five years. Other Jurisdictions - In 1998, IPC received authority from the OPUC to reduce the amortization period for the regulatory assets associated with demand-side management programs from 24 years to five years. The OPUC also approved additional Oregon allocated demand-side management expenditures for recovery through rates. The Oregon costs will be recovered by extending an existing surcharge until the amounts are collected. In 1997, IPC did not file any applications for rate relief before the FERC or in its Oregon or Nevada retail jurisdictions. In July 1996, IPC 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 1999-2003 period (excluding allowances for funds used during construction) is presently estimated to require cash funds of approximately $642.4 million as follows: 1999 2000-2003 (a) (Millions of Dollars) Generating Facilities: Hydro $14.2 $65.2 Thermal 6.5 30.3 Total generating facilities 20.7 95.5 Transmission lines and substations 18.1 62.5 Distribution lines and substations 43.4 198.3 General 28.4 53.7 Total cash construction - IPC 110.6 410.0 Other 4.9 116.9 Total IDACORP $115.5 $526.9 (a) Escalation rates were not applied to construction expenditures because the level of expenditures has been capped. 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 including: (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. The Company will pursue the projects that best meet its future energy needs. FINANCING PROGRAM The five-year estimates of capital requirements and sources of capital are outlined in the following tables: IDACORP, Inc. Idaho Power Company 1999 2000-2003 1999 2000-2003 (Millions of Dollars) Capital Requirements: Net cash construction expenditures $115.5 $526.9 $110.6 $410.0 Conservation expenditures 1.9 0.0 1.9 0.0 Other cash expenditures 3.8 4.8 3.8 4.8 Total $121.2 $531.7 $116.3 $414.8 Sources of Capital: Internal generation $ 94.4 $518.7 $ 94.2 $468.5 Short-term bank loans - Net 23.4 3.8 19.2 5.0 First mortgage bonds (0.1) 9.5 0.0 (58.4) Debt repayment (0.1) (0.3) (0.1) (0.3) Common stock 0.0 0.0 0.0 0.0 Cash investments (increase) 3.5 0.0 3.0 0.0 Total $121.2 $531.7 $116.3 $414.8 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. The Company will continue to take advantage of any refinancing opportunities as they become available. Under the terms of the Indenture relating to IPC'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, 1998, net earnings were 6.40 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, 1998, the actual preferred dividend earnings coverage was 3.15 times. If the dividends on the shares of Auction Preferred Stock were to reach the maximum allowed, the preferred dividend earnings coverage would be 2.88 times. The Indenture and IPC'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 IPC'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 4,644 miles of high voltage transmission lines; 21 step-up transmission substations located at power plants; 17 transmission substations; 7 transmission switching stations; and 205 energized distribution substations (excludes mobile substations and dispatch centers). IPC 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 Project Operating Nameplate License Capacity kW Capacity kW Expiration Properties Subject to Federal Licenses: Lower Salmon 70,000 60,000 1997 (a) Bliss 80,000 75,000 1998 (a) Upper Salmon 39,000 34,500 1998 (a) Shoshone Falls 12,500 12,500 1999 C J Strike 89,000 82,800 2000 Upper Malad 9,000 8,270 2004 Lower Malad 15,000 13,500 2004 Brownlee-Oxbow-Hells Canyon 1,398,000 1,166,900 2005 Swan Falls 25,547 25,000 2010 American Falls 112,420 92,340 2025 Cascade 14,000 12,420 2031 Milner 59,448 59,448 2038 Twin Falls 54,300 52,737 2041 Other Generating Plants: Other Hydroelectric 10,400 11,300 Jim Bridger (coal- fired station) 708,333 709,617 Valmy (coal-fired station) 260,650 260,650 Boardman (coal-fired station) 53,000 56,050 (a)Renewed on a year-to-year basis; application for relicense pending. At December 31, 1998, the composite average ages of the principal parts of IPC's system, based on dollar investment, were: production plant, 18.8 years; transmission system and substations, 19.0 years; and distribution lines and substations, 15.1 years. IPC considers its properties to be well maintained and in good operating condition. IPC owns in fee all of its principal plants and other important units of real property, except for portions of certain projects licensed under the Federal Power Act and reservoirs and other easements. IPC's property is also subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. In addition, IPC's property is subject to minor defects common to properties of such size and character that do not materially impair the value to, or the use by, IPC 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 IPC is the relicensing of its hydro facilities. The relicensing of these projects is not automatic under federal law. IPC 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 IPC continuing to hold the federal licenses. IPC is actively pursuing the relicensing of its hydroelectric projects, a process that will continue for the next 10 to 15 years. IPC submitted its first applications for license renewal to the FERC in December 1995, seeking renewal of IPC's licenses for its Bliss, Upper Salmon Falls and Lower Salmon Falls hydroelectric projects. In May 1997 IPC submitted its application for its Shoshone Falls project. IPC also submitted an application for license renewal for its C J Strike hydroelectric project on November 24, 1998. Although various federal requirements and issues must be resolved through the license renewal process, IPC anticipates that its efforts will be successful. At this point, however, IPC 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 November 30, 1995, a complaint entitled Idaho Power Company vs. Cogeneration, Inc., Case No. 98467, was filed by IPC in the District Court of the Fourth Judicial District of the State of Idaho. The proceeding involves an effort by IPC 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, IPC 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, IPC 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 IPUC order and has never posted the $1.9 million amount required by the FESA. After the IPUC's order became final and non-appealable, IPC 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. IPC asked the district court to find that as a matter of law IPC was entitled to either terminate or rescind the FESA. In response to IPC's complaint, Cogeneration, Inc. filed counterclaims alleging that IPC, 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 IPC was entitled to either rescind or terminate the FESA. On February 16, 1996, Cogeneration, Inc. dismissed its anti-trust claims against IPC with prejudice, 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. Following a court trial, on June 24, 1998 the District Court issued a memorandum decision finding that Cogeneration, Inc. had materially breached the FESA and as a result IPC had properly terminated the FESA. On July 27, 1998, Cogeneration, Inc. filed a Notice of Appeal with the Idaho Supreme Court. Cogeneration, Inc. filed its opening brief in the Idaho Supreme Court on February 16, 1999. IPC's brief is due March 16, 1999. It is likely that oral argument will be set during the court's fall term. This matter has been previously reported in IPC's Form 10-K dated March 12, 1998, and other IPC reports filed with the Securities and Exchange Commission. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None EXECUTIVE OFFICERS OF THE REGISTRANTS The names, ages and positions of all of the executive officers of IDACORP, Inc. and Idaho Power 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. IDACORP, Inc. Name, Age and Position Business Experience During Past Five (5) Years* Joseph W. Marshall, 60 Appointed February 2, 1998. Chairman of the Board and Chief Executive Officer Jan B. Packwood, 55 Appointed February 2, 1998. President and Chief Operating Officer J. LaMont Keen, 46 Appointed February 2, 1998. Vice President, Chief Financial Officer and Treasurer Richard Riazzi, 44 Appointed January 14, 1999. Vice President - Marketing and Sales Robert W. Stahman, 54 Appointed February 2, 1998. Vice President, General Counsel and Secretary *IDACORP, Inc. executive officers serve in the same capacities at Idaho Power Company. For these officers business experience, during the past five years, please refer to the next table. Idaho Power Company Name, Age and Position Business Experience During Past Five (5) Years Joseph W. Marshall, 60 Appointed August 18, 1989. Chairman of the Board and Chief Executive Officer Jan B. Packwood, 55 Appointed September 1, 1997. Mr. President and Chief Packwood was Executive Vice President Operating Officer from July 11, 1996, to September 1, 1997, and Vice President-Power Supply prior to July 11, 1996. J. LaMont Keen, 46 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. Kip W. Runyan, 48 Appointed August 1, 1997. Mr. Runyan Vice President - Delivery was CEO of Ida-West Energy Company prior to August 1, 1997. Richard Riazzi, 44 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. James C. Miller, 44 Appointed July 10, 1997. Mr. Miller Vice President - was General Manager - Generation Generation prior to July 10, 1997. Cliff N. Olson, 49 Appointed July 11, 1991. Vice President -Corporate Services Robert W. Stahman, 54 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 IDACORP, Inc.'s common stock (without par value) is traded on the New York and Pacific Stock Exchanges. At December 31, 1998, there were 25,307 holders of record and the year-end stock price was $36 3/16 per share. The outstanding shares of Idaho Power Company common stock ($2.50 par value) are held by IDACORP, Inc. and are not traded. The following table shows the reported high and low sales price and dividends paid for the years 1998 and 1997 as reported by the Wall Street Journal as composite tape transactions. IDACORP, Inc. became the holding company of Idaho Power Company on October 1, 1998. Amounts reported for periods prior to October 1, 1998, were for Idaho Power Company only. 1998 Quarters Common Stock, without par value: 1st 2nd 3rd 4th High $38 1/16 $37 7/8 $35 $36 1/4 Low 33 15/16 32 15/16 29 7/8 31 1/8 Dividends paid per share (cents) 46.5 46.5 46.5 46.5 ______________________________ 1997 Quarters Common Stock, without par value: 1st 2nd 3rd 4th High $31 7/8 $31 1/2 $32 13/16 $37 3/4 Low 29 3/4 28 1/2 31 30 5/16 Dividends paid per share (cents) 46.5 46.5 46.5 46.5 ITEM 6. SELECTED FINANCIAL DATA SUMMARY OF OPERATIONS (Thousands of Dollars except for per share amounts) IDACORP, Inc. 1998 1997 1996 1995 1994 For the Years Ended December 31, Operating revenues $1,121,976 $ 748,503 $ 578,445 $ 545,621 $ 543,658 Income from operations 191,221 184,749 187,171 175,991 149,665 Net income 89,176 87,098 83,155 78,930 67,532 Earnings per average common share outstanding (basic and diluted) 2.37 2.32 2.21 2.10 1.80 Dividends declared per share 1.86 1.86 1.86 1.86 1.86 At December 31, Total long-term debt* $ 815,937 $ 746,142 $ 769,810 $ 672,618 $ 693,206 Total assets 2,451,620 2,451,816 2,328,738 2,241,753 2,191,816 *Excludes amount due within one year. The above data should be read in conjunction with IDACORP's consolidated financial statements and notes to consolidated financial statements included in this Annual Report on Form 10-K. SUMMARY OF OPERATIONS (Thousands of Dollars except for per share amounts and customer data) IDAHO POWER COMPANY 1998 1997 1996 1995 1994 For the Years Ended December 31, Operating revenues $1,121,976 $ 748,503 $ 578,445 $ 545,621 $ 543,658 Income from operations 191,221 184,749 187,171 175,991 149,665 Net income 95,919 92,274 90,618 86,921 74,930 At December 31, Total long-term debt* $ 815,937 $ 746,142 $ 769,810 $ 672,618 $ 693,206 Total assets 2,421,790 2,451,816 2,328,738 2,241,753 2,191,816 Utility Customer Data: General business customers 373,730 363,085 352,487 340,708 330,308 Average Kwh per customer 36,368 37,080 37,627 35,740 37,616 Average rate per Kwh 3.85 3.63 3.71 3.85 3.75 *Excludes amount due within one year. The above data should be read in conjunction with Idaho Power Company's consolidated financial statements and notes to consolidated financial statements included in this Annual Report on Form 10-K. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS In Management's Discussion and Analysis we explain the general financial condition and results of operations of IDACORP, Inc. and its subsidiaries (IDACORP or the Company). IDACORP is a holding company formed in 1998 as the parent of Idaho Power Company (IPC), Ida-West Energy Company, and IDACORP Energy Solutions, Inc. IPC, an electric utility, is IDACORP's principal operating subsidiary, and accounts for over 90 percent of our assets, revenue and net income. The financial condition and results of operations of IPC are currently the principal factors affecting the financial conditions and results of operations of IDACORP. As you read Management's Discussion and Analysis, it may be helpful to refer to our Consolidated Statements of Income which present our results of operations for the years ended December 31, 1998, 1997 and 1996. In our discussion we explain the significant annual changes between specific line items in the Consolidated Statements of Income. FORWARD-LOOKING INFORMATION In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), we are hereby filing cautionary statements identifying important factors that could cause our actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of the Company in this Annual Report, quarterly report on Form 10-Q, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates", "believes", "estimates", "expects", "intends", "plans", "predicts", "projects", "will likely result", "will continue", or similar expressions) are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions, and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond our control and may cause actual results to differ materially from those contained in forward- looking statements: prevailing governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities Commission (IPUC), the Oregon Public Utilities Commission (OPUC), and the Public Utilities Commission of Nevada (PUCN), with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs): economic and geographic factors including political and economic risks; changes in and compliance with environmental and safety laws and policies; weather conditions; population growth rates and demographic patterns; competition for retail and wholesale customers; Year 2000 issues; pricing and transportation of commodities; market demand, including structural market changes; changes in tax rates or policies or in rates of inflation; changes in project costs; unanticipated changes in operating expenses and capital expenditures; capital market conditions; competition for new energy development opportunities; and legal and administrative proceedings (whether civil or criminal) and settlements that influence the business and profitability of the Company. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. RESULTS OF OPERATIONS Earnings per Share and Book Value Earnings per share of common stock (basic and diluted) were $2.37 in 1998, $2.32 in 1997, and $2.21 in 1996. The 1998 earnings equate to a 12.2 percent return on year-end common equity, as compared to 12.2 percent in 1997 and 12.0 percent in 1996. At December 31, 1998, the book value per share of common stock was $19.42, compared to $18.93 at December 31, 1997 and $18.47 at December 31, 1996. Overview A number of factors have contributed to the increase in earnings per share over the last three years, including excellent hydroelectric generating conditions, a strong service territory economy, and continued cost management. IPC's service territory experienced above average water years from 1996-1998. Hydro generation was 22 percent above normal in 1998, 30 percent above normal in 1997, and 18 percent above normal in 1996. Idaho's economy continued its strong performance over the last three years. Idaho's non-agricultural employment growth for the twelve months ended November 1998 was 2.2 percent; annual growth rates in 1997 and 1996 were 3.2 percent and 3.3 percent, respectively. Within the Boise Metropolitan Statistical Area, the heart of IPC's service territory, non-agricultural employment increased 2.3 percent for the twelve months ended November 1998, 4.2 percent in 1997 and 3.9 percent in 1996. General business customer growth continued in 1998, with a 2.9 percent increase, compared with a 3.0 percent increase in 1997 and 3.5 percent increase in 1996. This growth is attributable to strong overall economic conditions in our service territory. Operating revenues increased $373.5 million in 1998, and $170.1 million in 1997, due primarily to increased sales in the wholesale electricity markets, increased rates, customer growth, and weather conditions in our service territory. As part of a regulatory settlement, IPC set aside approximately $5.4 million in 1998, $7.6 million in 1997, and $4.9 million in 1996 for the benefit of our Idaho customers. We discuss the regulatory settlement below in "Regulatory Issues - Regulatory Settlement." Total operating expenses increased $367.0 million in 1998 and $172.5 million in 1997, due primarily to increased purchases in wholesale electricity markets, and increased purchased power and fuel costs resulting from increased sales. Income taxes decreased $7.4 million from 1996 through 1998, due primarily to an increase in tax credits earned from increasing investments in affordable housing projects. General Business Revenue Our general business revenue is dependent on many factors, including the number of customers we serve, the rates we charge, and weather. The $34.4 million increase in general business revenue in 1998 is due primarily to the annual change to the power cost adjustment component of retail electric rates, other rate adjustments, and to the 2.9 percent increase in general business customers. We discuss the power cost adjustment below in "Regulatory Issues - Power Cost Adjustment." The $3.7 million decrease in general business revenue in 1997 is due primarily to rate decreases, more moderate temperatures and increased precipitation, which reduced average irrigation customer energy sales by 8.2 percent and average residential customer energy sales by 1.2 percent. Precipitation increased 37.1 percent during the 1997 growing season, compared to 1996, and heating and cooling degree days, a common measure used in the electric utility industry to analyze usage, decreased by 3.3 percent in 1997. These factors were partially offset by a 3.0 percent increase in the number of general business customers. Off-System Sales Off-system sales are comprised of sales in the wholesale electricity markets, long-term contracts, and opportunity sales made when market prices make it cost-effective. The volume and price of these latter sales depend on our firm energy demand, hydroelectric generating conditions in our service territory, and market conditions throughout the western United States. Off-system sales increased $336.1 million in 1998 and $173.7 million in 1997. These increases relate primarily to increases in the market price of electricity and sales in the wholesale electricity markets. Off-system MWh sales increased 86 percent in 1998 and 201 percent in 1997. Increases in market prices increased our average price per MWh sold by 28 percent in 1998 and 16 percent in 1997. Expenses Purchased power expense increased $321.0 million in 1998 and $150.2 million in 1997 due primarily to an increase in purchases in the wholesale electricity markets. Total MWhs of purchased power increased 113 percent in 1998 and 213 percent in 1997. These increases reflect our increased focus on the wholesale electricity markets and the availability of low cost energy resulting from the abundance of hydro generation in the West. Fuel expense increased by $15.0 million in 1998 and $7.9 million in 1997 due primarily to increased generation at our coal-fired plants to take advantage of off-system sales opportunities. Total generation at the coal-fired plants was approximately 6.9 million MWhs in 1998, 5.4 million MWhs in 1997 and 4.8 million MWhs in 1996. The PCA mechanism increases expenses when power supply costs are below forecast, and decreases expenses when power supply costs are above forecast. In 1998, the PCA expense increased $27.9 million because our 1998 power supply costs were well below the forecast, where in 1997 they were somewhat above the forecast. The 1998 forecast had anticipated near-normal streamflow conditions in the 1998-9 rate period, but conditions have been significantly better than normal. We discuss the PCA in more detail in "Regulatory Issues - Power Cost Adjustment." The increases in other operation expenses in 1998 and 1997 were due primarily to increased payroll and benefits and increased transmission charges for electricity sold. Maintenance expenses decreased $6.9 million in 1998 and increased $6.0 million in 1997. The decrease in 1998 results from decreased maintenance expense at our steam generation facilities and distribution facilities. The 1997 increase is due to extensive maintenance at our steam generation facilities due to increased utilization, and repairs to hydro facilities and distribution facilities damaged by natural causes. Other Income Other income decreased $6.2 million in 1998 due primarily to costs incurred by new subsidiaries and costs of other diversified business activities. These subsidiaries and activities were created to compete in the non-regulated business environment. Income Taxes Income taxes decreased $1.8 million in 1998 and $5.6 million in 1997. The decrease in 1998 is due primarily to an increase in affordable housing tax credits. The decrease in 1997 is due primarily to an increase in affordable housing tax credits and decreased net income before taxes. Regulatory Issues Power Cost Adjustment (PCA) IPC has a PCA mechanism that provides for annual adjustments to the rates we charge to our Idaho retail customers. These adjustments, which take effect annually on May 16, are based on forecasts of net power supply costs and the true-up of the prior year's forecast. The difference between the actual costs incurred and the forecasted costs is deferred, with interest, and trued-up in the next annual rate adjustment. The May 1998 adjustment to rates includes the deferred costs from the 1997-98 PCA year as well as the difference between base power supply cost assumptions and forecasted power supply costs. The 1998-99 forecast assumed a return to more normal hydroelectric generating conditions. This resulted in forecasted power supply costs being near the amounts used to establish base rates in past regulatory proceedings. The May 1998 rate adjustment increases expected annual revenue by $34.0 million over the amount that would have been received at the 1997 rates, and $17.3 million over what would be recovered if we were charging the base rates during this rate period. So far in the current rate period, actual power costs have been less than forecast, due to better than forecast hydroelectric generating conditions. We have recorded a reduction to regulatory assets of $10.4 million as of December 31, 1998. The variance that exists at the end of the 1998-99 rate period will be trued-up in the next annual PCA adjustment. Regulatory Settlement IPC has a settlement agreement with the IPUC that remains in effect through 1999. Under the terms of the settlement, when our actual earnings in a given year exceed an 11.75 percent return on year- end common equity for the Idaho jurisdiction, we will set aside 50 percent of the excess for the benefit of our Idaho retail customers. In 1998, we set aside $5.4 million for the benefit of our Idaho customers, compared to $7.6 million in 1997 and $4.9 million in 1996. We requested that approximately $5.0 million of the 1997 earnings sharing amount be applied against the balance of deferred demand-side conservation expenditures in order to defer any rate increases associated with the conservation recovery until May 16, 1999, the same date as the next PCA adjustment. In addition, the settlement allows for the accelerated amortization of regulatory liabilities associated with accumulated deferred investment tax credits (ADITCs), up to a maximum of $30 million, to provide a minimum 11.50 percent return on actual year-end common equity for the Idaho jurisdiction. We have received approval from the Idaho State Tax Commission and the Internal Revenue Service on the accounting treatment for the tax credits. As of December 31, 1998, no ADITCs have been used under the regulatory agreement. Other important points in the settlement are that we will not be allowed to increase our Idaho general rates prior to January 1, 2000, except under special conditions as defined in the Settlement Agreement, and that we agree that our quality of service will not decline as a result of corporate reorganization. Demand-Side Management (Conservation) Expenses We are seeking changes to the regulatory treatment of previously deferred demand-side management (DSM) expenses in both Idaho and Oregon. In Idaho, we requested the IPUC to authorize recovery of post-1993 DSM expenses and acceleration of the recovery of DSM expenditures authorized in the last general rate case. We requested a five- year amortization instead of the 24-year period previously adopted. In its Order No. 27660 issued on July 31, 1998, the IPUC set a new amortization period of 12 years. The IPUC order reflects an increase in annual Idaho retail revenue requirements of $3.1 million for 12 years. As noted above, we are funding the annual revenue requirement with revenue sharing amounts until May 16, 1999. A group of our industrial customers has appealed the IPUC order to the Idaho Supreme Court. In December 1998 we filed with the IPUC, a request to recover our remaining deferred DSM expenditures of approximately $2.0 million. The IPUC has set this case for hearing in March 1999. In our filing we requested that the amount be applied against 1998 earnings sharing amounts. In Oregon, the OPUC authorized the amortization of the Oregon- allocated share of the DSM expenditures over five years. The DSM charge replaces an expiring rate surcharge related to extraordinary power supply costs associated with past drought conditions. We anticipate that the charge will recover approximately $540,000 per year. Ida-West Energy Company Ida-West Energy Company, a wholly owned subsidiary of IDACORP, was formed in 1989 to develop, finance, construct, acquire, own and operate electric power generation facilities. Ida-West is actively marketing new projects to utilities located in the West and is seeking to acquire operating facilities and projects under development throughout the United States and Canada. Existing Ida- West projects produced over 302,000 MWh's of energy in 1998. In addition, Ida-West has an interest in the Hermiston Power Project, a 536 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. To date, we have invested $20 million in Ida-West. IDACORP Financial Services, Inc. (IFS) IFS, a wholly owned subsidiary of IPC, participates in 12 affordable housing programs. These investments provide a return by reducing our federal income taxes and by assuring a return on investment through tax credits and tax depreciation benefits. To date, we have invested $6.5 million in IFS. LIQUIDITY AND CAPITAL RESOURCES Cash Flow Our net cash generated from operations totaled $508.6 million for the three-year period 1996-1998. After deducting common dividends of $209.7 million, net cash generation from operations provided approximately $298.9 million for our construction program and other capital requirements. Internal cash generation after dividends provided 95 percent of our total capital requirements in 1998, 89 percent in 1997, and 74 percent in 1996. In 1998, we increased our cash and cash equivalents by $12.2 million from life insurance death benefits and the surrender of life insurance policies. We forecast that internal cash generation after dividends will provide approximately 80 percent of total capital requirements in 1999 and over 94 percent during the four-year period 2000-2003. We expect to continue financing our construction program and other capital requirements with both internally generated funds and, to the extent necessary, externally financed capital. Principal amounts maturing during the forecast period are $6.0 million in 1999, $86.5 million in 2000, $36.9 million in 2001, $34.1 million in 2002 and $86.5 million in 2003. At January 1, 1999, IPC had regulatory authority to incur up to $200.0 million of short-term indebtedness. At December 31, 1998, its short-term borrowing totaled $38.5 million compared to $57.5 million at December 31, 1997 and $54.0 million at December 31, 1996. On December 19, 1996, IPC replaced its committed lines of credit arrangements with a $120.0 million multi-year revolving credit facility under which we pay a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond Rating. On December 21, 1998, IDACORP established a $100.0 million 364-day credit facility which will expire December 19, 1999, and a $50.0 million 3-year credit facility which will expire December 21, 2001. Under these facilities we will pay a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond Rating. Commercial paper may be issued up to $150.0 million and is supported by the bank credit facilities. (See Note 7 of "Notes to Consolidated Financial Statements"). Construction Program Our consolidated cash construction expenditures totaled $89.2 million in 1998, $95.6 million in 1997, and $93.6 million in 1996. Approximately 27 percent of these expenditures were for generation facilities, 14 percent for transmission facilities, 44 percent for distribution facilities, and 15 percent for general plant and equipment. We estimate that our cash construction program will require $115 million in 1999 and $527 million in the four-year period 2000-2003. These estimates are subject to revision in light of changing economic, regulatory, environmental, and conservation factors. Financing Program Our capital structure fluctuated slightly during the three-year period, with common equity ending at 44 percent, preferred stock (of IPC) seven percent, and long-term debt 49 percent at December 31, 1998. IDACORP, Inc. currently has a $300.0 million shelf registration statement that can be used for the issuance of unsecured debt securities and preferred or common stock. IDACORP also has committed short-term credit arrangements totaling $150.0 million. At December 31, 1998, none had been issued. IPC 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. In September 1998 IPC issued $60 million of Secured Medium Term Notes. The proceeds from this issuance were used to redeem at maturity $30 million of First Mortgage Bonds, and to reduce the balance of commercial paper issued in connection with ongoing business. In 1996, IPC issued $57 million of Secured Medium Term Notes. The net proceeds were used for repayment of commercial paper issued in connection with our ongoing construction program and to redeem preferred stock. These transactions have reduced the remaining balance on the shelf registration to $83 million as of December 31, 1998. In August 1996, IPC issued tax exempt Pollution Control Revenue Refunding Bonds with a principal amount of $116.3 million. The proceeds were used to retire the $116.3 million of Pollution Control Revenue Bonds due between 2003 and 2014. OTHER MATTERS Environmental Issues Salmon Recovery Plan We are continuing to work 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. We do not anticipate that the new designation will have any major effects on our operations. In September 1991, we modified operations at our three-dam Hells Canyon Hydroelectric Complex to protect the Fall Chinook downstream during spawning and juvenile emergence. From its start, our 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 our 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 our 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 called for 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 not complied 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 our power supply costs. IPC and the BPA have negotiated a five-year contract, expiring April 15, 2001, requiring BPA to replace lost energy and capacity resulting from recovery plans that impact our power supply cost. Nez Perce Lawsuit On March 21, 1997, the United States District Court for the District of Idaho entered a judgment related to a civil lawsuit filed against IPC in 1991 by the Nez Perce Tribe. The suit arose from the construction, maintenance, and operation of our three-dam Hells Canyon Complex and the project's alleged impact both on fish and the Tribe's treaty-reserved fishing rights. The judgment, which incorporated the terms of an agreement already reached by IPC and the Tribe, requires us to pay the Nez Perce Tribe $11.5 million over five years. All payments under the Agreement will be made in 1996 dollars, which allows for adjusted future inflation within a minimum range of three percent and a maximum of seven percent. As of December 31, 1998, $4.9 million remains payable to the Tribe over the next three years. 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 shares of the $11.5 million. In connection with settling the litigation, IPC 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 our application to relicense the project, we 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 we must file our relicense application. The Tribe will be entitled to earnings from investments on this account until we accept or reject a new federal license for the project. If we accept the new federal license, the Tribe will take ownership of the money in the account. If we reject the license, the money will be returned to us. This settlement is provisional because the Tribe retains the right to opt out of this relicensing settlement at any time prior to our acceptance of a new federal license. Threatened and Endangered Snails In 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, we have included this possibility in all of our 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 and their habitat. Although the hydro facilities on that reach of the Snake River do not significantly affect water levels during typical operations, some of them do provide the daily operational flexibility to meet increased electricity demand during high load hours. Recent studies suggest that this has no impact on the listed snails. While it is possible that the listing could affect how we operate our existing hydroelectric facilities on the middle reach of the Snake River, we believe that such changes will be minor and will not present any undue hardship. In 1995, as a part of our federal hydro relicensing process, we obtained a permit from the USFWS to study the five species of endangered Snake River snails. Our biologists have completed several studies 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. Results of the studies indicated that the snail colonies were part of a biological community well adapted to the influences of hydropower, water quality, and irrigation run-off. Company-sponsored studies continue to review how these and other factors affect the status of the various colonies and their habitats. Clean Air Act We have analyzed the Clean Air Act's effects on us and our customers. Our coal-fired plants in Oregon and Nevada already meet the federal emission rate standards for sulfur dioxide (SO2) and our coal-fired plant in Wyoming meets that state's even more stringent SO2 regulations. Therefore, we foresee no adverse effects on our operations with regard to SO2 emissions. 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 us and our operations. Electric Industry Restructuring Competition is increasing in the electric utility industry. Our goal is to anticipate and fully integrate into our operations any legislative, regulatory or competitive changes. We are pursuing a rapid, but orderly transition to at least a partially and possibly a totally deregulated environment in the years ahead. The following items describe some of the changes to date, as well as steps we are taking. Legislative Actions In 1997, the Idaho Legislature appointed a committee to study restructuring of the electric utility industry. Legislation resulting from this committee required the IPUC to begin an investigation into the unbundling of costs into its various delivery and energy components. We filed cost unbundling studies in July and December 1997. The IPUC compiled cost data presented by all the electric utilities and presented that information to the legislature. Although the committee will continue studying a variety of restructuring ideas, it is not expected to recommend restructuring legislation in the foreseeable future. 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. In November 1995, we 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 we use in our own operations to anyone seeking them. We requested and received permission to implement these tariffs beginning February 1, 1996. On July 8, 1996, we filed a new open-access transmission tariff to replace the 1995 tariffs. This provides full compliance with Final Order No. 888. This 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. Energy Trading We intend to be a competitive energy provider, including both electricity and natural gas. In mid-1997, IPC opened a gas trading office in Houston, Texas, to serve the southern and eastern United States and a Boise, Idaho office to serve the Northwest and Canadian markets. We also participate in the western wholesale electricity markets, the results of which are included in off- system revenue and purchased power expense. Inherent in the energy trading business are risks related to market movements and the creditworthiness of counterparties. When buying and selling energy, the high volatility of energy prices can have a significant impact on profitability if not managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into withstand dramatic market fluctuations. To mitigate these risks while implementing our business strategy, the IPC Board of Directors gave approval for executive management to form a Risk Management Committee, comprised of Company officers, to oversee a risk management program. The program is intended to minimize fluctuations in earnings while managing the volatility of energy prices. Embedded within the Risk Management policy and procedures is a credit policy requiring ongoing evaluation of the financial condition of counterparties, the securitization of credit support where needed, and ongoing monitoring of credit exposure. The objective of our risk management program is to mitigate commodity price risk, credit risk, and other risks related to the energy trading business. Market Rate Sensitive Instruments and Risk Management The following discussion summarizes the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates and commodity prices that IPC held at December 31, 1998. IPC buys and sells financial and physical natural gas and electricity commodity contracts as part of our ongoing business. These contracts are subject to electricity and natural gas commodity price risk. We have a trading and risk management policy defining the limits within which we contain our commodity price risk. We trade commodity futures, options and swaps as a method of managing the commodity price risk associated with electricity and natural gas trading. We have minimal foreign exchange exposure related to natural gas trading activities in Canadian dollars. This exposure is periodically offset through the use of foreign exchange swap instruments. Our sensitivity related to foreign exchange rate fluctuations as of December 31, 1998, is immaterial. Interest Rate Risk Sensitivity This table presents descriptions of our financial instruments at December 31, 1998, that are sensitive to changes in interest rates. We did not hold any interest rate derivative instruments at December 31, 1998. The majority of our debt is held in fixed rate securities with embedded call options. We hold $48.2 million in variable-rate tax-exempt debt for pollution control financings and 4.5 percent of our total debt is variable in the form of commercial paper. The variable rate debt is not interest rate sensitive by nature and the commercial paper borrowings do not give rise to significant interest rate risk because these borrowings generally have maturities of less than three months. The table below presents principal cash flows by maturity date and the related average interest rate. The table also presents the fair value for all fixed rate instruments as of December 31, 1998, based on market rates for similar instruments as of that date. Expected Maturity Date 1999 2000 2001 2002 2003 Thereafter Total Fair Value Fixed rate debt (in millions) $ 6.0 $87.8 $38.4 $35.7 $88.2 $519.3 $775.4 $829.2 Average interest rate 7.52% 8.55% 7.05% 7.00% 6.50% 7.76% 7.64% Commodity Price Risk Sensitivity This analysis presents the estimated December 31, 1998 value-at- risk related to our energy commodity contracts and related derivative instruments that are sensitive to changes in commodity prices. We use commodity derivative instruments such as futures, options and swaps to hedge against exposure to commodity price risk in the electricity and natural gas markets. The objective of our hedging program is to mitigate the risk associated with the purchase and sale of natural gas and electricity. Company policy also allows the use of these commodity derivative instruments for trading purposes in support of our operations. The aggregate potential loss in earnings from our energy trading activity is estimated to be $500,000 at a 95-percent confidence interval and for a holding period of one business day. The potential loss in earnings was estimated using a value-at-risk methodology with a monte carlo simulation. The monte carlo simulation averages outcomes from multiple scenarios based on our exposure at December 31, 1998. The multiple scenarios assume potential commodity prices based on historical prices, volatility and correlations to generate outcomes. Limitations of the value- at-risk analysis arise from uncertainties in assumptions. Historical prices, volatility and correlations are not necessarily a predictor of future prices, volatility and correlations. The use of a 95 percent confidence interval implies there is a 2.5 percent chance the value-at-risk is greater than that which is stated. A holding period of one day implies that all exposures could be liquidated in one business day. A lack of liquidity in the market could result in a holding period of more than one day. Relicensing of Hydroelectric Projects We are actively pursuing the relicensing of our hydroelectric projects, a process that will continue for the next 10 to 15 years. We submitted our first applications for license renewal to the FERC in December 1995. We have now filed applications seeking renewal of our licenses for our Bliss, Upper Salmon Falls, Lower Salmon Falls, C J Strike and Shoshone Falls Hydroelectric Projects. Although various federal requirements and issues must be resolved through the license renewal process, we anticipate that our efforts will be successful. At this point, however, we cannot predict what type of environmental or operational requirements we may face, nor can we estimate the eventual cost of license renewal. At December 31, 1998, $10.7 million of relicensing costs were included in Construction Work in Progress. Year 2000 Costs Many existing computer systems use only two digits to identify a year in the date field. These programs were designed and developed without considering the impact of the upcoming change in the century. Unless proper modifications are made, the program logic in many of these systems will start to produce erroneous results because, among other things, the systems will read the date "01/01/00" as being January 1 of the year 1900 or another incorrect date. In addition, the systems may fail to detect that the year 2000 is a leap year. Similar problems could arise prior to the year 2000 as dates in the next millennium are entered into systems that are not Year 2000 compliant. We recognize the Year 2000 problem as a serious threat to the Company and our customers. Our Year 2000 effort has been underway for over two years and is being addressed at the highest levels within the Company. The IPC Vice President of Corporate Services is responsible for coordinating the corporate effort. Each IPC vice president is responsible for addressing the problem within their respective business units and each has assigned a Year 2000 Project Leader to execute the project plan. Each subsidiary President is responsible for addressing the problem within their subsidiary in coordination with the corporate effort. In addition, we have appointed a full-time Year 2000 Project Manager to direct the project. Additional staff has been committed to complete the conversion and implementation needed to bring non-compliant items into compliance. This staff consists of a mix of end users, IPC Information Services staff and contract programmers. Currently, there are over 20 full-time employees devoted to the project with dozens of others involved to varying degrees. We have retained third parties who have recently completed technical and legal audits of our plan. With respect to the technical audit, we have completed our review of the audit report, have begun implementation of most of the recommendations and are discussing the remainder of the recommendations with the auditing company. Regarding the legal audit, we have received a draft audit and are presently reviewing the draft report internally. We have targeted July 1999 as the date by which we expect to be ready for the Year 2000. This means that all critical systems are expected to be capable of handling the century rollover and that we will be able to continue servicing our customers without interruption. It also means that all of the less critical systems are expected to have been identified and that contingency and/or repair plans are expected to be in place for dealing with the change of century. We are following a detailed project plan. The methodology is modeled after those used by some of the top companies in the world and has been adapted to meet our unique requirements. This process includes all the phases and steps commonly found in such plans, including the (i) identification and analysis of critical systems, key manufacturers, service providers, embedded systems, generation plants (part of which is owned by the Company but is operated by another electric utility), (ii) remediation and testing, (iii) education and awareness and (iv) contingency planning. With respect to that key component of the methodology related to the identification of critical systems, we have identified those critical systems which must be Year 2000 compliant in order to continue operations. Many are already compliant or are in the process of vendor upgrades to become compliant. The largest of these critical systems and their status regarding compliance are set forth below: System Description Status Business The business systems include the Our testing Systems financial and administrative has shown functions common to most companies. PeopleSoft and Business systems include accounts PassPort payable, general ledger, accounts both to be receivable, labor entry, inventory, compliant purchasing, cash management, vendor budgeting, asset management, packages. payroll, and financial reporting. Customer This system is used to, among other In-house Information things, bill customers, log calls system has System from customers and create service or been repaired. work requests and track them through Testing is completion. At this time, the underway. Company uses an in-house developed, mainframe-based Customer Information System to accomplish these tasks. Energy The most critical function the The packages Management Company offers is the delivery of comprising the System (EMS) electricity from the source to the EMS are now consumer. This must be done with fully minimal interruption in the midst of compliant and high demand, weather anomalies and rollout is equipment failures. To accomplish underway. this, we rely on a server-based Testing is energy management system provided by currently Landis & Gyr. This system monitors underway. and directs the delivery of electricity throughout our service area. Metering We rely on several processes for In-house code Systems metering electricity usage, has been including some hand-held devices repaired. with embedded chips. It is critical Vendor for metering systems to operate packages are without interruption so as not to being jeopardize our revenue stream. upgraded. Testing is underway. Embedded There is a category of systems on Non-Year 2000 Systems which the Company is highly reliant compliant called embedded systems. These are chips have typically computer chips that been replaced. provide for automated operations Test bench has within some device other than a been computer such as a relay or a established. security system. We are highly Testing is reliant on these systems throughout about 75% our generation and delivery systems complete. to monitor and allow manual or automatic adjustments to the desired devices. Other We also rely on a number of other In various Systems important systems to support stages of engineering, human resources, safety repair and and regulatory compliance, etc. testing. Regarding third parties, the plan methodology has required us to identify those third parties with which we have a material relationship. We have identified as material (1) our ownership interest in thermal generating facilities which are operated and maintained by third party electric utilities; (2) our fuel suppliers for those thermal generating facilities; and (3) our telecommunication providers. In addition, we have identified ninety-three (93) key manufacturers that provide materials and supplies to us. With respect to the thermal plants, fuel suppliers and telecommunication providers, the plan methodology includes a process wherein some members of the Year 2000 team meet periodically with the third parties to assess the status of their efforts. This is an ongoing process and will continue until such time as the third party has completed compliance testing and certified to us that they are compliant. Regarding the 93 key manufacturers, we have contacted all via mail and requested they complete a survey indicating the extent and status of their Year 2000 efforts. The survey is followed up with contact by telephone to further document their Year 2000 status. Finally, we are connected to an electric grid that connects utilities throughout the western portion of North America. This interconnection is essential to the reliability and operational integrity of each connected utility. This also means that failure of one electric utility in the interconnected grid could cause the failure of others. In the context of the Year 2000 problem, this interconnectivity compounds the challenge faced by the electric utility industry. Our Company could do a very thorough and effective job of becoming Year 2000 compliant and yet encounter difficulties supplying services and energy because another utility in the interconnected grid failed to achieve Year 2000 compliance. In this regard, we are working closely with other electric industry organizations concerned with reliability issues and technical collaboration. Our estimate of the cost of our Year 2000 plan remains at approximately $5.3 million which is being expensed as incurred. This includes costs incurred to date (approximately $1.8 million) and estimated costs through the year 2000. This level of expenditure is not expected to have a material effect on our operations or our financial position. Funds to cover Year 2000 costs in 1999 have been budgeted by business unit, subsidiary and within the IPC Information Services Department with approximately 10 percent of the IPC Information Services budget used for remediation. No IPC Information Services Department projects have been deferred due to our year 2000 efforts. The Year 2000 issue poses risks to our internal operations due to the potential inability to carry on our business activities and from external sources due to the potential impact on the ability of our customers to continue their business activities. The major applications that pose the greatest risks internally are those systems, embedded or otherwise, which impact the generation, transmission and distribution of energy and the metering and billing systems. The potential risks related to these systems are electric service interruptions to customers and associated reduction in loads and revenue, and interrupted data gathering and billing, and the resultant delay in receipt of revenues. All of this would negatively impact our relationship with our customers, which may enhance the likelihood of losing customers in a restructured industry. Externally, those customers who inadequately prepare for the Year 2000 issue may be unable to continue their business activities. This would affect us in a number of ways. Our loads and revenue would be reduced because of the lost load from discontinued business activities, and customers who lose jobs because of discontinued business activities may face difficulties in paying their power bills. The impact of this on us is dependent upon the number and the size of those businesses that are forced to discontinue business activities because of the Year 2000 issue. As part of our Year 2000 plan, we are in the process of developing a contingency plan and expect to complete this process on or before July 1999. Management Changes In January 1999 IDACORP's Board of Directors approved the retirement plans of Chairman of the Board of Directors and Chief Executive Officer Joseph W. Marshall. Mr. Marshall will retire effective June 1, 1999, and Jan B. Packwood, currently serving as President, will assume the responsibilities of Chief Executive Officer. Jon Miller, a Board member since 1988, will replace Marshall as Chairman of the Board in a non-executive capacity. New Accounting Pronouncements In June 1998, the FASB issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Transactions." This statement establishes accounting and reporting standards for derivative financial instruments and other similar financial instruments and for hedging activities. It is effective for fiscal years beginning after June 15, 1999. We are reviewing this statement to determine its effect on our financial position and results of operations. Emerging Issues Task Force 98-10 (EITF 98-10), "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" is issued and effective for financial statements for fiscal years beginning after December 15, 1998. We anticipate the impact of adoption on our financial position and results of operations will be immaterial. ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this item is included in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" under "Market Rate Sensitive Instruments and Risk Management" ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES PAGE Management's Responsibility for Financial Statements 38 Consolidated Financial Statements: IDACORP, Inc. Consolidated Statements of Income for the Years Ended December 31, 1998, 1997 and 1996 39 Consolidated Balance Sheets as of December 31, 1998, 1997 and 1996 40-41 Consolidated Statements of Capitalization as of December 31, 1998, 1997 and 1996 42 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996 43 Consolidated Statements of Retained Earnings and Consolidated Statements of Comprehensive Income for the Years Ended December 31, 1998,1997 and 1996 44 Notes to Consolidated Financial Statements 45-59 Independent Auditors' Report 60 Idaho Power Company Consolidated Statements of Income for the Years Ended December 31,1998, 1997 and 1996 61 Consolidated Balance Sheets as of December 31, 1998, 1997 and 1996 62-63 Consolidated Statements of Capitalization as of December 31, 1998, 1997 and 1996 64 Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996 65 Consolidated Statements of Retained Earnings and Consolidated Statements of Comprehensive Income for the Years Ended December 31, 1998, 1997 and 1996 66 Notes to Consolidated Financial Statements 67-69 Independent Auditors' Report 70 Supplemental Financial Information and Financial Statement Schedules: Supplemental Financial Information (Unaudited) 71 Financial Statement Schedules for the Years Ended December 31, 1998, 1997 and 1996: Schedule II-Consolidated Valuation and Qualifying Accounts- IDACORP, Inc. 77 Schedule II-Consolidated Valuation and Qualifying Accounts- Idaho Power Company. 77 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of IDACORP, Inc. and 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. 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 Companies maintain 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 conducts special and operational audits in support of these accounting controls throughout the year. Each Company's Board of Directors, through their Audit Committees comprised entirely of outside directors, meet periodically with management, internal auditors and 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 Committees. The financial statements have been audited by Deloitte & Touche LLP, the Companies' independent auditors, who were responsible for conducting their audit in accordance with generally accepted auditing standards. Joseph W. Marshall Chairman and Chief Executive Officer J. LaMont Keen Vice President, Chief Financial Officer and Treasurer IDACORP, Inc. Consolidated Statements of Income Year Ended December 31, 1998 1997 1996 (Thousands of Dollars except for per share amounts) REVENUES: General business $ 514,856 $ 480,458 $ 484,145 Off system sales 579,984 243,874 70,222 Other revenues 27,136 24,171 24,078 Total revenues 1,121,976 748,503 578,445 EXPENSES: Operation: Purchased power 540,200 219,200 69,038 Fuel expense 86,237 71,271 63,334 Power cost adjustment 21,866 (6,032) (6,859) Other 145,374 137,458 132,667 Maintenance 41,872 48,722 42,731 Depreciation 74,481 71,973 69,705 Taxes other than income taxes 20,725 21,162 20,658 Total expenses 930,755 563,754 391,274 INCOME FROM OPERATIONS 191,221 184,749 187,171 OTHER INCOME: Allowance for equity funds 300 34 46 used during construction Gas trading activities - Net (3,208) (1,181) - Other - Net 10,928 15,402 12,488 Total other income 8,020 14,255 12,534 INTEREST EXPENSE AND OTHER: Interest on long-term debt 52,270 53,215 52,165 Other interest 8,407 7,546 5,183 Allowance for borrowed funds used during (900) (503) (353) construction Preferred dividends of Idaho Power Company 5,658 5,176 7,463 Total interest expense and other 65,435 65,434 64,458 INCOME BEFORE INCOME TAXES 133,806 133,570 135,247 INCOME TAXES 44,630 46,472 52,092 NET INCOME $ 89,176 $ 87,098 $ 83,155 AVERAGE COMMON SHARES OUTSTANDING (000) 37,612 37,612 37,612 EARNINGS PER SHARE OF COMMON STOCK (basic and diluted) $ 2.37 $ 2.32 $ 2.21 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Assets December 31, 1998 1997 1996 (Thousands of Dollars) ELECTRIC PLANT: In service (at original cost) $2,659,441 $2,605,697 $2,537,565 Accumulated provision for depreciation (1,009,387) (942,400) (886,885) In service - Net 1,650,054 1,663,297 1,650,680 Construction work in progress 59,717 51,892 42,178 Held for future use 1,738 1,738 1,773 Electric plant - Net 1,711,509 1,716,927 1,694,631 INVESTMENTS AND OTHER PROPERTY 129,437 97,065 69,903 CURRENT ASSETS: Cash and cash equivalents 22,867 6,905 7,928 Receivables: Customer 81,245 63,076 34,962 Allowance for uncollectible accounts (1,397) (1,397) (1,394) Gas trading 21,426 42,128 - Notes 4,643 4,613 5,104 Employee notes 4,510 4,757 4,486 Other 6,059 8,854 8,489 Accrued unbilled revenues 34,610 33,312 27,709 Materials and supplies (at average cost) 30,157 29,156 24,639 Fuel stock (at average cost) 7,096 7,172 11,631 Prepayments 16,042 15,381 16,165 Regulatory assets associated with income taxes 2,965 3,164 4,397 Total current assets 230,223 217,121 144,116 DEFERRED DEBITS: American Falls and Milner water rights 31,830 32,055 32,260 Company-owned life insurance 35,149 51,915 57,291 Regulatory assets associated with income taxes 201,465 198,521 196,696 Regulatory assets - other 62,013 90,239 89,507 Other 49,994 47,973 44,334 Total deferred debits 380,451 420,703 420,088 TOTAL $2,451,620 $2,451,816 $2,328,738 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Capitalization and Liabilities December 31, 1998 1997 1996 (Thousands of Dollars) CAPITALIZATION: Common stock equity: Common stock without par value (shares authorized 120,000,000; shares outstanding - 37,612,351) $ 451,564 $ 452,519 $ 452,486 Retained earnings 278,607 259,299 242,088 Accumulated other comprehensive income 226 - - Total common stock equity 730,397 711,818 694,574 Preferred stock of Idaho Power Company 105,968 106,697 106,975 Long-term debt 815,937 746,142 769,810 Total capitalization 1,652,302 1,564,657 1,571,359 CURRENT LIABILITIES: Long-term debt due within one year 6,029 33,998 2,212 Notes payable 38,524 57,516 54,016 Accounts payable 73,499 69,064 36,370 Accounts payable gas trading 28,476 42,874 - Taxes accrued 24,785 24,295 17,304 Interest accrued 18,365 17,918 15,886 Deferred income taxes 2,965 3,164 4,397 Other 12,275 13,703 12,439 Total current liabilities 204,918 262,532 142,624 DEFERRED CREDITS: Regulatory liabilities associated with deferred investment tax credits 69,396 70,196 71,283 Deferred income taxes 422,196 423,736 411,890 Regulatory liabilities associated with income taxes 28,075 34,072 35,028 Regulatory liabilities - other 4,161 509 616 Other 70,572 96,114 95,938 Total deferred credits 594,400 624,627 614,755 COMMITMENTS AND CONTINGENT LIABILITIES TOTAL $2,451,620 $2,451,816 $2,328,738 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Capitalization December 31, 1998 % 1997 % 1996 % (Thousands of Dollars) COMMON STOCK EQUITY Common stock $ 451,564 $ 452,519 $ 452,486 Retained earnings 278,607 259,299 242,088 Accumulated other comprehensive 226 - - Total common stock equity 730,397 44 711,818 45 694,574 44 PREFERRED STOCK OF IDAHO POWER COMPANY 4% preferred stock 15,968 16,697 16,975 7.68% Series, serial preferred stock 15,000 15,000 15,000 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 105,968 7 106,697 7 106,975 7 LONG-TERM DEBT OF IDAHO POWER COMPANY First mortgage bonds: 5.33 % Series due 1998 - 30,000 30,000 8.65 % Series due 2000 80,000 80,000 80,000 6.93 % Series due 2001 30,000 30,000 30,000 6.85 % Series due 2002 27,000 27,000 27,000 6.40 % Series due 2003 80,000 80,000 80,000 8 % Series due 2004 50,000 50,000 50,000 5.83 % Series due 2005 60,000 - - Maturing 2021 through 2031 with rates ranging from 7.5% to 9.52% 230,000 230,000 230,000 Total first mortgage bonds 557,000 527,000 527,000 Amount due within one year - (30,000) - Net first mortgage bonds 557,000 497,000 527,000 Pollution control revenue bonds: 7 1/4 % Series due 2008 4,360 4,360 4,360 8.30 % Series 1984 due 2014 49,800 49,800 49,800 6.05 % Series 1996A due 2026 68,100 68,100 68,100 Variable Rate Series 1996B due 2026 24,200 24,200 24,200 Variable Rate Series 1996C due 2026 24,000 24,000 24,000 Total pollution control revenue bonds 170,460 170,460 170,460 REA notes 1,489 1,561 1,632 Amount due within one year (74) (72) (71) Net REA notes 1,415 1,489 1,561 American Falls bond guarantee 20,130 20,355 20,560 Milner Dam note guarantee 11,700 11,700 11,700 Debt related to investments in affordable housing with rates ranging from 6.97% to 8.59% due 1999 to 2009 62,103 46,385 33,401 Amount due within one year (5,955) (3,926) (2,141) Net affordable housing debt 56,148 42,459 31,260 Unamortized premium/discount - Net (1,539) (1,637) (1,731) Net Idaho Power Company debt 815,314 741,826 760,810 OTHER SUBSIDIARY DEBT 623 4,316 9,000 Total long-term debt 815,937 49 746,142 48 769,810 49 TOTAL CAPITALIZATION $1,652,302 100 $1,564,657 100$1,571,359 100 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Cash Flows Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) OPERATING ACTIVITIES: Net income $ 89,176 $ 87,098 $ 83,155 Adjustments to reconcile net income to net cash: Depreciation and amortization 87,143 80,485 78,228 Deferred taxes and investment tax credits (10,182) 5,978 7,967 Accrued PCA costs 21,658 (7,038) (6,768) Change in: Accounts receivable and prepayments 4,883 (69,589) 5,482 Accrued unbilled revenue (1,298) (5,603) (2,684) Materials and supplies and fuel stock (925) (57) 2,730 Accounts payable (9,963) 75,731 (4,277) Taxes accrued 489 6,991 1,895 Other current assets and liabilities (825) 3,296 673 Other - net (10,269) (5,562) 551 Net cash provided by operating activities 169,887 171,730 166,952 INVESTING ACTIVITIES: Additions to utility plant (89,184) (95,633) (93,645) Investments in affordable housing projects (19,139) (17,021) (18,281) Other investments - - (20,153) Other - net 3,206 (1,302) 825 Net cash used in investing activities (105,117) (113,956) (131,254) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 60,000 - 57,000 Pollution control revenue bonds - - 116,300 Long-term debt related to affordable housing projects 15,718 12,984 17,924 Other long-term debt - - 9,000 Retirement of: Subsidiary long-term debt (4,316) (4,700) - First mortgage bonds (30,000) - (20,249) Pollution control revenue - - (116,300) bonds Preferred stock of Idaho Power Company - - (26,530) Dividends on common stock (69,868) (69,887) (69,924) Increase (decrease) in short- term borrowings (18,992) 3,500 996 Other - net (1,350) (694) (4,455) Net cash used in financing activities (48,808) (58,797) (36,238) Net increase (decrease) in cash and cash equivalents 15,962 (1,023) (540) Cash and cash equivalents beginning of period 6,905 7,928 8,468 Cash and cash equivalents at end of period $ 22,867 $ 6,905 $ 7,928 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Income taxes $ 55,527 $ 41,786 $45,050 Interest (net of amount 53,806 $ 53,319 $53,273 capitalized) The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Retained Earnings Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) RETAINED EARNINGS, BEGINNING OF YEAR $259,299 $242,088 $229,827 NET INCOME 89,176 87,098 83,155 Total 348,475 329,186 312,982 COMMON STOCK DIVIDENDS (69,868) (69,887) (69,924) PREFERRED STOCK REDEMPTION - Idaho Power Company - - (970) RETAINED EARNINGS, END OF YEAR $278,607 $259,299 $242,088 The accompanying notes are an integral part of these statements. Consolidated Statements of Comprehensive Income Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) NET INCOME $ 89,176 $ 87,098 $ 83,155 OTHER COMPREHENSIVE INCOME: Unrealized gains on securities (net of tax of $2,185) 3,385 - - Minimum pension liability adjustment (net of tax of $2,054) (3,159) - - TOTAL COMPREHENSIVE INCOME $ 89,402 $ 87,098 $ 83,155 The accompanying notes are an integral part of these statements IDACORP, Inc. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Nature of Business IDACORP, Inc. (the Company) is a holding company formed in 1998 as the parent to Idaho Power Company (IPC), Ida-West Energy Company, and IDACORP Energy Solutions Inc. IPC's outstanding common stock was converted on a share-for-share basis into common stock of the Company. However, IPC's preferred shares and debt securities outstanding were unaffected and remain with IPC. IPC, a public utility, represents over 90% of the total assets of the Company and is its principal operating subsidiary. IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state commissions of Idaho, Oregon, Nevada and Wyoming, is engaged in the generation, transmission, distribution, sale and purchase of electric energy, and has approximately 374,000 retail customers and 1,669 employees. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned or controlled subsidiaries. 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 have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. System of Accounts The accounting records of IPC conform to the Uniform System of Accounts prescribed by the 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, IPC's weighted- average monthly AFDC rates for 1998, 1997 and 1996 were 6.0 percent, 5.8 percent and 6.1 percent, respectively. Revenues In order to match revenues with associated expenses, IPC accrues unbilled revenues for electric services delivered to customers but not yet billed at month-end. Under terms and conditions of a regulatory settlement with the Idaho Public Utilities Commission (IPUC), if IPC's actual earnings in a given year exceed an 11.75 percent return on year-end common equity, it will set aside 50 percent of the excess for the benefit of IPC's Idaho retail customers. In 1998, 1997 and 1996, approximately $5.4 million, $7.6 million and $4.9 million of revenues were set aside for the benefit of Idaho retail customers. Power Cost Adjustment IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to Idaho retail customers. These adjustments are based on forecasts of net power supply costs, and take effect annually on May 16. The difference between the actual costs incurred and the forecasted costs are deferred, with interest, and trued-up in the next annual rate adjustment. 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 2.87 percent in 1998, 2.93 percent in 1997 and 2.89 percent in 1996 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 the 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, IPC's 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, IPC received an accounting order from the IPUC that allowed for accelerated 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 1998, 1997 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 maturity dates at date of acquisition of three months or less. The Company has changed the presentation of operating activities in its consolidated statements of cash flows from the direct to the indirect method. The years 1997 and 1996 have been reclassified to conform to the new presentation. 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 and market producers, and the FERC is requiring utilities, including IPC, 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. These statutory and conforming regulations may result in increased wholesale and retail competition. Due to IPC's low cost structure, it is well positioned to compete in the evolving utility market place. However, the Company is unable to predict what financial impact or effect the adoption of any such legislation would have on IPC's operations. IPC 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 IPC. Pursuant to SFAS No. 71 IPC capitalizes, as deferred regulatory assets, incurred costs that are expected to be recovered in future utility rates. IPC also records as deferred regulatory liabilities the current recovery in utility rates of costs that are expected to be paid in the future. The following is a breakdown of IPC's regulatory assets and liabilities for the years 1998, 1997 and 1996: 1998 1997 1996 Assets Liabilities Assets Liabilities Assets Liabilities (Millions of Dollars) Income taxes $204.4 $ 28.1 $201.7 $ 34.1 $201.1 $ 35.0 Conservation 43.3 - 42.4 - 40.3 - Employee benefits 5.6 - 6.5 - 7.4 - PCA deferral and amortization (5.2) - 16.6 - 9.6 - Other 18.3 4.1 24.7 0.5 32.2 0.6 Deferred investment tax credits - 69.4 - 70.2 - 71.3 Total $266.4 $101.6 $291.9 $104.8 $290.6 $106.9 At December 31, 1998, IPC had $14.1 million of regulatory assets that were not earning a return on investment excluding the $204.4 million that relates to income taxes. In the event that recovery of costs 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 IPC's operations, then these items may represent stranded investments. 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. Derivative Financial Instruments IPC uses financial instruments such as commodity futures, options and swaps to hedge against exposure to commodity price risk in the electricity and natural gas markets. The objective of IPC's hedging program is to mitigate the risk associated with the purchase and sale of natural gas and electricity. The accounting for derivative financial instruments that are used to manage risk is in accordance with the concepts established in SFAS No. 80, "Accounting for Futures Contracts," American Institute of Certified Public Accountants Statement of Position 86-2, "Accounting for Options," and various Emerging Issues Task Force (EITF) pronouncements. Deferral (hedge) accounting is used if certain hedging criteria are met and is applied only if the derivative reduces the risk of the underlying hedged item and is designated at inception as a hedge with respect to the hedged item. Additionally, the derivative must result in payoffs that are expected to be inversely correlated to those of the hedged item. Gains and losses from derivatives that reduce the commodity price risk related to electricity are recognized as purchased power expenses when the hedged transaction occurs. Gains and losses from derivatives that reduce the commodity price risk related to natural gas are recognized as a component of gas trading activities when the hedged transaction occurs. Cash flows from derivatives are recognized in the statement of cash flows and are in the same category as that of the hedged item. IPC's policy also allows for the use of financial instruments noted above for trading purposes in support of Company operations. Gains or losses on financial instruments that do not qualify for hedge accounting are recognized in income on a current basis. The following table shows a summary of IPC's derivative positions as of December 31, 1998 and 1997. No derivative positions existed at December 31, 1996. 1998 1997 Gas Electricity Gas Electricity MMBTU's MWh's MMBTU's MWh's Futures: Purchase 21,210,000 286,304 3,560,000 21,344 Sale 18,590,000 370,944 3,510,000 - Options: Purchase - 18,400 - - Sale - 43,200 - - Swaps 27,568,610 - 15,104 - Comprehensive Income The Company adopted SFAS No. 130, "Reporting Comprehensive Income" effective January 1, 1998. The statement establishes standards for reporting and displaying comprehensive income and its components in the Company's financial statements. Components of the Company's comprehensive income include net income, the Company's proportionate share of unrealized holding gains on marketable securities held by an equity investee, and the changes in additional minimum liability under a deferred compensation plan for certain senior management employees and directors. New Accounting Pronouncements In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement is effective for all fiscal quarters of all fiscal years beginning after June 15, 1999, and establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The Company is evaluating the effect of this statement on its financial position and results of operations. EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" is issued and effective for financial statements for fiscal years beginning after December 15, 1998. The Company anticipates the impact of adoption on its financial position and results of operations will be immaterial. 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 1998 have been reclassified to conform to the current year's presentation. 2. INCOME TAXES: IPC has settled Federal and Idaho tax liabilities on all open years through the 1995 tax year except for amounts related to a partnership which have been, in management's opinion, adequately accrued. A reconciliation between the statutory federal income tax rate and the effective rate is as follows: 1998 1997 1996 Computed income taxes based on statutory federal income tax rate $ 46,832 $ 46,750 $ 47,336 Change in taxes resulting from: Investment tax credits (2,934) (2,887) (2,835) Repair allowance (2,800) (2,800) (2,800) Settlement of prior years tax returns (1,965) 23 (16) Current state income taxes 6,258 3,587 2,823 Depreciation 5,237 5,766 5,945 Affordable housing tax credits (6,880) (4,519) (1,777) Preferred dividends of IPC 1,980 1,811 2,613 Other (1,098) (1,259) 803 Total provision for federal and state income taxes $ 44,630 $ 46,472 $ 52,092 Effective tax rate 33.4 % 34.8 % 38.5 % The provision for income taxes consists of the following: 1998 1997 1996 Income taxes currently payable: Federal $ 45,606 $ 35,038 $ 40,379 State 9,206 5,456 3,746 Total 54,812 40,494 44,125 Income taxes deferred - Net of amortization: Federal (8,006) 6,717 6,877 State (1,376) 348 314 Total (9,382) 7,065 7,191 Investment tax credits: Deferred 2,134 1,800 3,611 Restored (2,934) (2,887) (2,835) Total (800) (1,087) 776 Total provision for income taxes $ 44,630 $ 46,472 $ 52,092 The tax effects of significant items comprising the Company's net deferred tax liability are as follows: 1998 1997 1996 Deferred tax assets: Regulatory liabilities $ 28,075 $ 34,072 $ 35,028 Advances for construction 10,401 18,665 17,736 Other 20,512 16,536 13,550 Total 58,988 69,273 66,314 Deferred tax liabilities: Electric plant 247,270 251,938 245,652 Regulatory assets 204,430 201,685 201,093 Investment tax credits 69,396 70,196 71,283 Conservation programs 16,866 14,377 13,720 Other 15,583 28,173 22,136 Total 553,545 566,369 553,884 Net deferred tax $494,557 $497,096 $487,570 liabilities 3. COMMON STOCK: Changes in shares of IDACORP common stock for 1998, 1997 and 1996 were as follows: Shares Amount Balance at December 31, 1995 37,612,351 $452,948 Other - Net (462) Balance at December 31, 1996 37,612,351 452,486 Other - Net 33 Balance at December 31, 1997 37,612,351 452,519 Other - Net (955) Balance at December 31, 1998 37,612,351 $451,564 As of December 31, 1998; 2,791,321 of authorized but unissued shares of IDACORP common stock were reserved for future issuance under the Company's Dividend Reinvestment and Stock Purchase Plan and IPC's Employee Savings Plan. In addition, 314,114 shares are reserved for the Restricted Stock Plan (see Note 9). The Company has a Shareholder 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 Share Purchase Right (Right) for each of the Company's outstanding Common Shares held on October 1, 1998 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 of such stock. The Company may redeem all but not less than all of the Rights at a price of $0.01 per Right or exchange the Rights for cash, securities (including Common Shares of the Company) or other assets at any time prior to the close of business on the 10th day after acquisition by an Acquiring Person of a 20 percent or greater position. Additionally, the IDACORP Board created the A Series Preferred Stock, without Par Value, and reserved 1,200,000 shares for issuance upon exercise of the Rights. Following the acquisition of a 20 percent or greater position, each Right will entitle its holder to purchase for $95 that number of shares of Common Stock or Preferred Stock having a market value of $190. 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 $95, shares of the acquiring company's common stock having a market value of $190. Any Rights that are or were held by an Acquiring Person become void if any of these events occurs. The Rights expire on September 30, 2008. The Rights themselves do not give any voting or other rights as shareholders to their holders. The terms of the Rights may be amended without the approval of any holders of the Rights until an Acquiring Person obtains a 20 percent or greater position, and then may be amended as long as the amendment is not adverse to the interests of the holders of the Rights. 4. PREFERRED STOCK OF IDAHO POWER COMPANY: The number of shares of IPC preferred stock outstanding at December 31, 1998, 1997 and 1996 were as follows: Shares Outstanding at December 31, Call Price 1998 1997 1996 Per Share Preferred stock: Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 159,680 166,972 169,753 $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: 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 560,180 567,472 570,253 (a) The preferred stock is not redeemable prior to July 1, 2003. (b) Dividend rate at December 31, 1998 was 4.02% and ranged between 4.29% and 3.97% during the year. During 1998, 1997 and 1996 IPC reacquired and retired 7,292; 2,781; and 2,060 shares of 4% preferred stock. As of December 31, 1998 the overall effective cost of all outstanding preferred stock was 5.57 percent. On November 7, 1996, IPC redeemed for $26.4 million, the $25.0 million principal amount of 8.375% Series, serial preferred stock without par value, ($100 stated value) from proceeds of the issuance of $27.0 million principal amount of secured medium term notes, Series B, 6.85%, Due 2002. 5. LONG-TERM DEBT: The Company currently has a $300.0 million shelf registration statement that can be used for the issuance of unsecured debt securities and preferred or common stock. At December 31, 1998, none had been issued. The amount of first mortgage bonds issuable by IPC is limited to a maximum of $900.0 million 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 IPC and are held by a Trustee for the benefit of the bondholders. IPC currently has a $200.0 million shelf registration statement with a balance of $83.0 million that remains to be issued. This can be used for first mortgage bonds (including medium term notes) or preferred stock. First mortgage bonds maturing during the five-year period ending 2003 are $0 in 1999, $80.0 million in 2000, $30.0 million in 2001, $27.0 million in 2002 and $80.0 million in 2003. On July 29, 1996, IPC issued $30.0 million 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 IPC's ongoing construction program. On October 2, 1996, $27.0 million principal amount of Secured Medium Term Notes, Series B, 6.85% Due 2002 were issued with net proceeds from this sale used to redeem IPC's $25.0 million of 8.375% Series, Serial Preferred Stock, Without Par Value. On September 9, 1998, $60.0 million principal amount of Secured Medium Term Notes, Series B 5.83% Series due 2005 were issued by IPC. Proceeds from this issuance were used to redeem at maturity, the $30.0 million First Mortgage Bonds 5.33% Series B due September 1998, with the balance used for repayment of commercial paper issued in connection with IPC's ongoing business. On August 29, 1996, tax exempt Pollution Control Revenue Refunding Bonds were issued by IPC in principal amount of $68.1 million Series 1996A, $24.2 million Series 1996B and $24.0 million Series 1996C. The proceeds were used to retire the $24.2 million Pollution Control Revenue Bonds due 2003, $24.0 million Pollution Control Revenue Bonds due 2007 and the $68.1 million Pollution Control Revenue Bonds due 2013-2014. At December 31, 1998, 1997 and 1996 the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 7.69 percent, 7.84 percent and 7.73 percent, respectively. At December 31, 1998, IDACORP Financial Services, Inc., a wholly owned subsidiary of IPC, has $62.1 million of debt with interest rates ranging from 6.97 percent to 8.59 percent. This debt is collateralized by investments in affordable housing projects with a book-value of $65.9 million at December 31, 1998. Principal amounts maturing during the five-year period ending 2003 are $6.0 million in 1999, $6.5 million in 2000, $6.9 million in 2001, $7.1 million in 2002 and $6.5 million in 2003. 6. FAIR VALUE OF FINANCIAL INSTRUMENTS: The estimated fair value of the Company's financial instruments has 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 estimated fair values for long-term debt and investments are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate. The total estimated fair value of the Company's debt was approximately $877.4 million in 1998, $801.8 million in 1997 and $806.8 million for 1996. Included in investments and other property were financial instruments totaling $14.2 million in 1998, $16.5 million in 1997 and $18.0 million in 1996. Estimated fair value of these instruments was $20.3 million in 1998, $19.9 million in 1997 and $18.7 million in 1996. 7. NOTES PAYABLE: On December 21, 1998, the Company established a $100.0 million 364- day credit facility which will expire December 19, 1999, and a $50.0 million 3-year credit facility which will expire December 21, 2001. Under these facilities the Company pays a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond Rating. Commercial paper may be issued up to the $150.0 million and are supported by the bank credit facilities. The Company has no short-term balance outstanding at December 31, 1998. At December 31, 1998, IPC had regulatory authority to incur up to $200.0 million of short-term indebtedness. On December 19, 1996, IPC replaced its committed lines of credit arrangements with a $120.0 million multi-year revolving credit facility, which will expire on December 19, 2001. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC'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 $200.0 million maximum and are supported by bank lines of credit of an equal amount. Balances and interest rates of short-term borrowings for IPC were as follows: Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) Balance at end of year $38,524 $57,516 $54,016 Effective annual interest rate 6.0 % 6.1 % 5.7% at end of year 8. COMMITMENTS AND CONTINGENT LIABILITIES: Commitments under contracts and purchase orders relating to IPC's program for construction and operation of facilities amounted to approximately $10.5 million at December 31, 1998. The commitments are generally revocable by IPC subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges. IPC is currently purchasing energy from 66 on-line cogeneration and small power production facilities with contracts ranging from 1 to 32 years. Under these contracts IPC is required to purchase all of the output from these facilities. During the fiscal year ended December 31, 1998, IPC purchased 907,096 MWh at a cost of $55.0 million. The Company is party to various legal claims, actions, and complaints, certain of which involve material amounts. Although 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: Pension Plans IPC sponsors a 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. IPC'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. IPC was not required to contribute to the plan during 1998, 1997 and 1996. The trustee invests the plan's assets primarily in listed stocks (both U.S. and foreign), fixed income securities and investment grade real estate. IPC has a nonqualified, deferred compensation plan for certain senior management employees and directors that provides for supplemental retirement and death benefit payments to the participant and his or her family. IPC financed this plan by purchasing life insurance policies for which it is the beneficiary and through investments in marketable securities held by a trustee. The cash value of the policies and investments exceed the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the funded status. The following table shows the components of net periodic pension cost for these plans (in thousands of dollars): Pension Plan Deferred Compensation Plan 1998 1997 1996 1998 1997 1996 Service cost $ 7,133 $ 6,152 $ 6,273 $ 572 $ 515 $ 596 Interest cost 15,458 14,445 13,647 1,747 1,731 1,679 Expected return on assets (22,724) (20,248) (18,145) - - - Recognized net actuarial (gain) loss (111) - - 255 222 248 Amortization of prior service cost 424 424 424 (332) (346) (339) Amortization of transition asset (263) (263) (263) 613 613 613 Net periodic pension cost $ (83) $ 510 $ 1,936 $ 2,855 $2,735 $ 2,797 The following table sets forth the funded status of these plans (in thousands of dollars): Pension Plan Deferred Compensation Plan 1998 1997 1996 1998 1997 1996 Change in projected benefit obligation: Beginning of year benefit obligation $224,073 $202,049 $193,133 $ 25,067 $24,122 $ 23,692 Service cost 7,133 6,152 6,273 572 516 596 Interest cost 15,458 14,445 13,647 1,747 1,731 1,679 Actuarial loss (gain) 14,139 12,763 (564) 1,297 806 189 Benefits paid (11,774) (11,336) (10,440) (2,049) (2,303) (1,958) Plan amendments 4,700 - - 395 195 (76) End of year benefit 253,729 224,073 202,049 27,029 25,067 24,122 obligation Change plan assets: Plan assets at fair value at beginning of year 256,893 230,478 204,760 - - - Actual return on plan assets 44,961 37,751 30,234 - - - Employer contributions - - 5,924 - - - Benefit payments (11,774) (11,336) (10,440) - - - Plan assets at fair value at end of year 290,080 256,893 230,478 - - - Funded status 36,351 32,820 28,429 (27,029) (25,067) (24,122) Unrecognized actuarial loss/(gain) (33,722) (25,734) (20,994) 6,612 5,569 4,985 Unrecognized prior service cost 9,370 5,093 5,517 (1,166) (1,893) (2,434) Unrecognized net transition liability (1,704) (1,967) (2,230) 3,988 4,601 5,214 (Accrued)/ Prepaid cost (net amount recognized) 10,295 20,212 10,722 (17,595) (16,790) (16,357) Additional minimum liability - - - (8,036) (7,867) (6,402) Minimum liability $ 10,295 $ 10,212 $ 10,722 $(25,631)$(24,657) $(22,759) Amount recognized in the statement of financial position consist of: Prepaid (accrued) pension cost $ 10,295 $ 10,212 $ 10,722 $(25,631)$(24,657) $(22,759) Intangible asset - - - 2,822 7,867 6,402 Accumulated other comprehensive income - - - 5,214 - - Net amount recognized $ 10,295 $ 10,212 $ 10,722 $(17,595)$(16,790) $(16,357) The following table sets forth the assumptions used at the end of each year for all IPC-sponsored pension and postretirement benefit plans: Pension Benefits Postretirement Benefits 1998 1997 1996 1998 1997 1996 Discount rate 6.75 % 7.10 % 7.35 % 6.75 % 7.35 % 7.60 % Expected long-term rate of return on assets 9.0 9.0 9.0 9.0 9.0 9.0 Annual salary increases 4.5 4.5 4.5 - - - Restricted Stock Plan IPC implemented a restricted stock plan in 1995 as an equity-based long-term incentive plan for certain key employees. Each grant has a three-year restricted period and final award amounts depend on the attainment of a cumulative earnings per share performance goal. At December 31, 1998, there were 314,114 shares of common stock reserved for the plan. Restricted stock awards are compensatory awards and IPC accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 1998, 1997 and 1996, total compensation accrued for the plan was $567,000, $539,000 and, $184,000 respectively. IPC applies APB Opinion 25 and related interpretations in accounting for this plan. Had compensation cost for IPC's grants of restricted stock been determined consistent with the optional fair value based method provisions of SFAS No. 123, "Account for Stock-Based Compensation," IPC's net income and earnings per share of common stock for 1998, 1997 and 1996 would not be significantly different from such amounts as reported. The following table summarizes restricted stock activity for the years 1998, 1997 and 1996: 1998 1997 1996 Shares outstanding - beginning of year, 38,365 18,140 9,120 Shares granted 21,361 20,225 9,740 Shares forfeited (4,063) - (720) Shares issued (12,600) - - Shares outstanding - end of year 43,063 38,365 18,140 Weighted average fair value of current year stock grants on grant date $ 37.00 $ 31.25 $ 30.25 Savings Plan IPC sponsors an Employee Savings Plan under which employees may contribute a percentage of their base salary. IPC matches the first two percent of salary contributed by the employee and 50 percent of the next four percent of salary contributed by the employee. All amounts are invested by a trustee in any or all of seven investment options. Matching contributions amounted to $3.0 million in 1998, $2.4 million in 1997 and, $2.3 million in 1996. Postretirement Benefits IPC 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. IPC has a retiree medical benefits funding program which consists of life insurance policies on active employees for which IPC is the beneficiary, and a qualified Voluntary Employees Beneficiary Association (VEBA) Trust. IPC was not required to contribute to the plan in 1998, 1997 and 1996. The VEBA trust represents plan assets that are invested in variable life insurance policies, Trust Owned Life Insurance (TOLI), on active employees. Inside buildup in the TOLI policies is tax deferred and tax free if the policy proceeds are paid to the Trust as death benefits. The investment return assumption reflects an expectation that investment income in the VEBA will be substantially tax free. The net periodic postretirement benefit cost was as follows (in thousands of dollars): 1998 1997 1996 Service cost $ 720 $ 713 $ 794 Interest cost 2,913 3,029 3,172 Expected return on plan assets (1,761) (1,511) (1,410) Amortization of unrecognized transition obligation 2,040 2,040 2,040 Amortization of prior service cost (280) (87) - Amortization of unrecognized net gains (220) (240) (57) Net periodic postretirement benefit cost $ 3,412 $ 3,944 $ 4,539 The following table sets forth the funded status of this postretirement health and life insurance benefit plan (in thousands of dollars): 1998 1997 1996 Change in accumulated benefit obligation: Benefit obligation at beginning of year $43,459 $44,439 $48,928 Service cost 720 713 794 Interest cost 2,913 3,029 3,172 Plan amendments (9,071) (1,214) - Actuarial loss (gain) 3,483 (1,940) (6,984) Benefits paid (2,889) (1,568) (1,471) Benefit obligation at end of year 38,615 43,459 44,439 Change in plan assets: Fair value of plan assets at beginning of year 19,493 17,341 15,920 Actual return on plan assets 4,853 2,152 1,421 Employer (excess) contributions 2,789 1,553 1,421 Benefits paid (2,789) (1,553) (1,421) Fair value of plan assets at end on year 24,346 19,493 17,341 Funded status (14,269) (23,966) (27,098) Unrecognized prior service cost (9,918) (1,127) - Unrecognized actuarial (gain)/loss (7,256) (7,867) (5,526) Unrecognized transition obligation 28,560 30,600 32,640 Accrued postretirement benefit obligations included with othe long-term liabilities $(2,883) $(2,360) $ 16 liabilities The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan is 6.75%. A one- percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of dollars): 1-Percentage- 1-Percentage- Point increase Point decrease Effect on total of service and interest cost components $ 279 $ (259) Effect on accumulated postretirement benefit obligation 2,286 (2,159) Postemployment Benefits The Company provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under our disability plans, and health care for surviving spouses and dependents. The Company accrues a liability for such benefits. In accordance with an IPUC order, the portion of the liability attributable to regulated activities in Idaho as of December 31, 1993, was deferred as a regulatory asset, and is being amortized over ten years. The following table summarizes postemployment benefits amounts included in the Company's consolidated balance sheet (in thousands of dollars): 1998 1997 1996 Included with regulatory assets - other $2,260 $2,632 $3,003 Included with other deferred credits (3,372) (3,093) (4,128) 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, accumulated provision for depreciation and annual depreciation provisions as a percent of average depreciable balance for the years 1998, 1997 and 1996 (in thousands of dollars): 1998 1997 1996 Balance Avg Rate Balancc Avg Rate Balance Avg Rate Production $1,344,526 2.60% $1,333,768 2.60% $1,323,090 2.58% Transmission 389,011 2.30 378,190 2.28 371,123 2.29 Distribution 736,527 3.15 715,091 3.38 688,232 3.35 General and Other 189,377 5.45 178,648 5.39 155,120 5.23 Total In Service 2,659,441 2.87 2,605,697 2.93 2,537,565 2.89 Less accumulated provision for depreciation 1,009,387 942,400 886,885 In Service - Net $1,650,054 $1,663,297 $1,650,680 IPC is involved in the ownership and operation of three jointly- owned generating facilities. The Consolidated Statements of Income include IPC's proportionate share of direct operation and maintenance expenses applicable to the projects. Each facility and extent of IPC participation as of December 31, 1998 are as follows: Company Ownership Accumulated Electric Plant Provision Name of Plant Location In Service for Depreciation % MW (Thousands of Dollars) Jim Bridger Rock Springs, $383,139 $190,139 33 708 Units 1-4 WY Boardman Boardman, OR 61,486 32,071 10 53 Valmy Units 1 Winnemucca, NV 299,763 130,118 50 261 and 2 IPC'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 IPC from the joint venture amounted to $46.2 million in 1998, $40.7 million in 1997 and, $35.0 million in 1996. IPC has contracts to purchase the energy from five PURPA Qualified Facilities that are 50 percent owned by Ida-West Energy Company, a wholly owned subsidiary of the Company. Power purchased from these facilities amounted to $8.7 million in 1998, $9.8 million in 1997 and $9.0 million in 1996. 11. INDUSTRY SEGMENT INFORMATION: In June 1997 the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This Statement requires financial and descriptive disclosure for fiscal years beginning after December 15, 1997, about certain operating segments of an enterprise as well as enterprise-wide disclosure of certain product and geographic information. The Company is predominantly a one operating segment company with the regulated electric operations of IPC being the most dominant segment. Other subsidiaries of the Company, subsidiaries of IPC and non-utility operating segments of IPC do not individually constitute more than 10% of enterprise revenues, income or assets, nor in aggregate do they comprise more than 25% of enterprise revenues, income or assets. IPC's primary business is the generation, transmission, distribution, purchase and sale of electricity. IPC also began natural gas trading activities in May 1997 and reports this activity in Other Income in the Consolidated Statements of Income. The following table summarizes the segment information for IPC Utility with a reconciliation to total enterprise information: IPC Total Utility Other Enterprise (Thousands of Dollars) 1998 Revenues $1,121,976 $ - $1,121,976 Income from operations 191,221 - 191,221 Other income 5,909 2,111 8,020 Interest expense 56,646 3,131 59,777 Income before income taxes 140,484 (6,678) 133,806 Income taxes 51,447 (6,817) 44,630 Net income 89,037 139 89,176 Total assets 2,310,322 141,298 2,451,620 Expenditures for long-lived assets 91,803 19,205 111,008 1997 Revenues $ 748,503 $ - $ 748,503 Income from operations 184,749 - 184,749 Other income 3,894 10,361 14,255 Interest expense 57,653 2,605 60,258 Income before income taxes 130,990 2,580 133,570 Income taxes 49,125 (2,653) 46,472 Net income 81,865 5,233 87,098 Total assets 2,338,524 113,292 2,451,816 Expenditures for long-lived assets 98,219 17,457 115,676 1996 Revenues $ 578,445 $ - $ 578,445 Income from operations 187,171 - 187,171 Other income 2,759 9,775 12,534 Interest expense 56,110 885 56,995 Income before income taxes 133,821 1,426 135,247 Income taxes 51,386 706 52,092 Net income 82,435 720 83,155 Total assets 2,245,880 82,858 2,328,738 Expenditures for long-lived assets 97,484 34,595 132,079 Substantially all of the Company's revenue comes from the sale of electricity and related services, predominately in the United States. The Company sells natural gas, solar electric products and systems, control systems integration services for substations and semiconductor manufacturing, and miscellaneous other services however, these revenues are not significant. INDEPENDENT AUDITORS' REPORT To The Board of Directors and Shareowners of IDACORP, Inc. Boise, Idaho We have audited the accompanying consolidated balance sheets and statements of capitalization of IDACORP, Inc. and its subsidiaries as of December 31, 1998, 1997 and 1996, and the related consolidated statements of income, cash flows, retained earnings and comprehensive income for the years then ended. Our audits also included the consolidated financial statement schedule listed in the Index 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 schedule 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 IDACORP, Inc. and subsidiaries at December 31, 1998, 1997 and 1996, 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 Boise, Idaho January 29, 1999 Idaho Power Company Consolidated Statements of Income Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) REVENUES: General business $ 514,856 $ 480,458 $ 484,145 Off system sales 579,984 243,874 70,222 Other revenues 27,136 24,171 24,078 Total revenues 1,121,976 748,503 578,445 EXPENSES: Operation: Purchased power 540,200 219,200 69,038 Fuel expense 86,237 71,271 63,334 Power cost adjustment 21,866 (6,032) (6,859) Other 145,374 137,458 132,667 Maintenance 41,872 48,722 42,731 Depreciation 74,481 71,973 69,705 Taxes other than income taxes 20,725 21,162 20,658 Total expenses 930,755 563,754 391,274 INCOME FROM OPERATIONS 191,221 184,749 187,171 OTHER INCOME: Allowance for equity funds used during construction 300 34 46 Gas trading activities - Net (3,208) (1,181) - Other - Net 12,364 15,402 12,488 Total other income 9,456 14,255 12,534 INTEREST CHARGES Interest on long-term debt 52,270 53,215 52,165 Other interest 8,323 7,546 5,183 Allowance for borrowed funds used during construction (900) (503) (353) Total interest charges 59,693 60,258 56,995 INCOME BEFORE INCOME TAXES 140,984 138,746 142,710 INCOME TAXES 45,065 46,472 52,092 NET INCOME 95,919 92,274 90,618 Dividends on preferred stock 5,658 5,176 7,463 EARNINGS ON COMMON STOCK $ 90,261 $ 87,098 $ 83,155 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Assets December 31, 1998 1997 1996 (Thousands of Dollars) ELECTRIC PLANT: In service (at original cost) $2,659,441 $2,605,697 $2,537,565 Accumulated provision for depreciation (1,009,387) (942,400) (886,885) In service - Net 1,650,054 1,663,297 1,650,680 Construction work in progress 58,904 51,892 42,178 Held for future use 1,738 1,738 1,773 Electric plant - Net 1,710,696 1,716,927 1,694,631 INVESTMENTS AND OTHER PROPERTY 105,600 97,065 69,903 CURRENT ASSETS: Cash and cash equivalents 20,029 6,905 7,928 Receivables: Customer 81,227 63,076 34,962 Allowance for uncollectible accounts (1,397) (1,397) (1,394) Gas trading 21,426 42,128 - Notes 467 4,613 5,104 Employee notes 4,510 4,757 4,486 Other (includes $3,164 from related parties in 1998) 8,502 8,854 8,489 Accrued unbilled revenues 34,610 33,312 27,709 Materials and supplies (at average cost) 30,143 29,156 24,639 Fuel stock (at average cost) 7,096 7,172 11,631 Prepayments 16,011 15,381 16,165 Regulatory assets associated with income taxes 2,965 3,164 4,397 Total current assets 225,589 217,121 144,116 DEFERRED DEBITS: American Falls and Milner water rights 31,830 32,055 32,260 Company-owned life insurance 35,149 51,915 57,291 Regulatory assets associated with income taxes 201,465 198,521 196,696 Regulatory assets - other 62,013 90,239 89,507 Other 49,448 47,973 44,334 Total deferred debits 379,905 420,703 420,088 TOTAL $2,421,790 $2,451,816 $2,328,738 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Capitalization and Liabilities December 31, 1998 1997 1996 (Thousands of Dollars) CAPITALIZATION: Common stock equity: Common stock, $2.50 par value (50,000,000 shares authorized; 37,612,351 shares outstanding) $ 94,031 $ 94,031 $ 94,031 Premium on capital stock 362,156 362,328 362,297 Capital stock expense (3,823) (3,840) (3,842) Retained earnings 252,137 259,299 242,088 Accumulated other comprehensive income 226 - - Total common stock equity 704,727 711,818 694,574 Preferred stock 105,968 106,697 106,975 Long-term debt 815,937 746,142 769,810 Total capitalization 1,626,632 1,564,657 1,571,359 CURRENT LIABILITIES: Long-term debt due within one year 6,029 33,998 2,212 Notes payable 38,508 57,516 54,016 Accounts payable 72,660 69,064 36,370 Accounts payable gas trading 28,476 42,874 - Taxes accrued 25,164 24,295 17,304 Interest accrued 18,364 17,918 15,886 Deferred income taxes 2,965 3,164 4,397 Other 12,117 13,703 12,439 Total current liabilities 204,283 262,532 142,624 DEFERRED CREDITS: Regulatory liabilities associated with deferred investment tax credits 69,396 70,196 71,283 Deferred income taxes 420,268 423,736 411,890 Regulatory liabilities associated with income taxes 28,075 34,072 35,028 Regulatory liabilities - other 4,161 509 616 Other 68,975 96,114 95,938 Total deferred credits 590,875 624,627 614,755 COMMITMENTS AND CONTINGENT LIABILITIES TOTAL $2,421,790 $2,451,816 $2,328,738 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Capitalization December 31, 1998 % 1997 % 1996 % (Thousands of Dollars) COMMON STOCK EQUITY Common stock $ 94,031 $ 94,031 $ 94,031 Premium on capital stock 362,156 362,328 362,297 Capital stock expense (3,823) (3,840) (3,842) Retained earnings 252,137 259,299 242,088 Accumulated other comprehensive income 226 - - Total common stock equity 704,727 43 711,818 45 694,574 44 PREFERRED STOCK 4% preferred stock 15,968 16,697 16,975 7.68% Series, serial preferred stock 15,000 15,000 15,000 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 105,968 7 106,697 7 106,975 7 LONG-TERM DEBT First mortgage bonds: 5.33 % Series due 1998 - 30,000 30,000 8.65 % Series due 2000 80,000 80,000 80,000 6.93 % Series due 2001 30,000 30,000 30,000 6.85 % Series due 2002 27,000 27,000 27,000 6.40 % Series due 2003 80,000 80,000 80,000 8 % Series due 2004 50,000 50,000 50,000 5.83 % Series due 2005 60,000 - - Maturing 2021 through 2031 with rates ranging from 7.5% to 9.52% 230,000 230,000 230,000 Total first mortgage bonds 557,000 527,000 527,000 Amount due within one year - (30,000) - Net first mortgage bonds 557,000 497,000 527,000 Pollution control revenue bonds: 7 1/4% Series due 2008 4,360 4,360 4,360 8.30 % Series 1984 due 2014 49,800 49,800 49,800 6.05 % Series 1996A due 2026 68,100 68,100 68,100 Variable Rate Series 1996B due 2026 24,200 24,200 24,200 Variable Rate Series 1996C due 2026 24,000 24,000 24,000 Total pollution control revenue bonds 170,460 170,460 170,460 REA notes 1,489 1,561 1,632 Amount due within one year (74) (72) (71) Net REA notes 1,415 1,489 1,561 American Falls bond guarantee 20,130 20,355 20,560 Milner Dam note guarantee 11,700 11,700 11,700 Debt related to investments in affordable housing with rates ranging from 6.97% to 8.59% due 1999 to 2009 62,103 46,385 33,401 Amount due within one year (5,955) (3,926) (2,141) Net affordable housing debt 56,148 42,459 31,260 Other subsidiary debt 623 4,316 9,000 Unamortized premium/discount - (1,539) (1,637) (1,731) Net Total long-term debt 815,937 50 746,142 48 769,810 49 TOTAL CAPITALIZATION $1,626,632 100 $1,564,657 100$1,571,359 100 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Cash Flows Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) OPERATING ACTIVITIES: Net income $ 95,919 $ 92,274 $ 90,618 Adjustments to reconcile net income to net cash: Depreciation and amortization 87,044 80,485 78,228 Deferred taxes and investment tax credits (10,127) 5,978 7,967 Accrued PCA costs 21,658 (7,038) (6,768) Change in: Accounts receivable and prepayments 1,985 (69,589) 5,482 Accrued unbilled revenue (1,298) (5,603) (2,684) Materials and supplies and fuel stock (911) (57) 2,730 Accounts payable (10,658) 75,731 (4,277) Taxes accrued 1,312 6,991 1,895 Other current assets and liabilities (857) 3,296 673 Other - net (10,340) (5,562) 551 Net cash provided by operating activities 173,727 176,906 174,415 INVESTING ACTIVITIES: Additions to utility plant (89,644) (95,633) (93,645) Investments in affordable housing projects (19,139) (17,021) (18,281) Other investments - - (20,153) Other - net 867 (1,302) 825 Net cash used in investing activities (107,916) (113,956) (131,254) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 60,000 - 57,000 Pollution control revenue - - 116,300 bonds Long-term debt related to affordable housing projects 15,718 12,984 17,924 Other long-term debt - - 9,000 Retirement of: Subsidiary long-term debt (3,316) (4,700) - First mortgage bonds (30,000) - (20,249) Pollution control revenue - - (116,300) bonds Preferred stock - - (26,530) Dividends on common stock (69,889) (69,887) (69,924) Dividends on preferred stock (5,658) (5,176) (7,463) Increase (decrease) in short- (18,992) 3,500 996 term borrowings Other - net (550) (694) (4,455) Net cash used in financing activities (52,687) (63,973) (43,701) Net increase (decrease) in cash 13,124 (1,023) (540) and cash equivalents Cash and cash equivalents 6,905 7,928 8,468 beginning of period Cash and cash equivalents at end of period $ 20,029 $ 6,905 $ 7,928 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Income taxes $ 55,527 $ 41,786 $ 45,050 Interest (net of amount capitalized) $ 53,806 $ 53,319 $ 53,273 Net assets of affiliates transferred to parent $ 27,534 - - The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Retained Earnings Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) RETAINED EARNINGS, BEGINNING OF YEAR $259,299 $242,088 $229,827 NET INCOME 95,919 92,274 90,618 Total 355,218 334,362 320,445 DIVIDENDS Common stock ($1.86 per share) (69,889) (69,887) (69,924) Preferred stock (5,658) (5,176) (7,463) TRANSFER TO IDACORP, INC. (27,534) - - PREFERRED STOCK REDEMPTION - - (970) RETAINED EARNINGS, END OF YEAR $252,137 $259,299 $242,088 The accompanying notes are an integral part of these statements. Consolidated Statements of Comprehensive Income Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) NET INCOME $ 95,919 $ 92,274 $ 90,618 OTHER COMPREHENSIVE INCOME: Unrealized gains on securities (net of tax of $2,185) 3,385 - - Minimum pension liability adjustment (net of tax of $2,054) (3,159) - - TOTAL COMPREHENSIVE INCOME $ 96,145 $ 92,274 $ 90,618 The accompanying notes are an integral part of these statements. Idaho Power Company Notes to the Consolidated Financial Statements On October 1, 1998, IDACORP, Inc. (IDACORP) became the parent of Idaho Power Company and its subsidiaries (IPC). At that time, IPC's ownership interests in two subsidiaries were transferred to IDACORP at book value. IPC's financial statements include the following amounts attributable to the transferred subsidiaries for the periods prior to October 1, 1998: As of/Year Ended December 31, 1998 1997 1996 (Thousands of Dollars) Total assets $ - $ 31,369 $ 33,258 Net assets - 23,311 21,255 Net income 3,024 2,057 1,249 Except as modified below, the Notes to the Consolidated Financial Statements of IDACORP beginning on page 45 of this 1998 Annual Report on Form 10-K are incorporated herein by reference insofar as they relate to IPC. Note 1 - Summary of Significant Accounting Policies Note 3 - Common Stock Note 4 - Preferred Stock of Idaho Power Company Note 5 - Long-Term Debt Note 7 - Notes Payable Note 8 - Commitments and Contingent Liabilities Note 9 - Employee Benefit Plans Note 10 - Electric Plant in Service and Jointly Owned Projects Note 2 - Income Taxes IPC has settled Federal and Idaho tax liabilities on all open years through the 1995 tax year except for amounts related to a partnership which have been, in management's opinion, adequately accrued. A reconciliation between the statutory federal income tax rate and the effective rate is as follows: 1998 1997 1996 Computed income taxes based on statutory federal income tax rate $ 49,344 $ 48,561 $ 49,949 Change in taxes resulting from: Investment tax credits (2,934) (2,887) (2,835) Repair allowance (2,800) (2,800) (2,800) Settlement of prior years tax (1,965) 23 (16) returns Current state income taxes 6,309 3,587 2,823 Depreciation 5,237 5,766 5,945 Affordable housing tax (6,880) (4,519) (1,777) credits Other (1,246) (1,259) 803 Total provision for federal $ 45,065 $ 46,472 $ 52,092 and state income taxes Effective tax rate 32.0 % 33.5 % 36.5 % The provision for income taxes consists of the following: 1998 1997 1996 Income taxes currently payable: Federal $ 45,909 $ 35,038 $ 40,379 State 9,283 5,456 3,746 Total 55,192 40,494 44,125 Income taxes deferred - Net of amortization: Federal (8,006) 6,717 6,877 State (1,321) 348 314 Total (9,327) 7,065 7,191 Investment tax credits: Deferred 2,134 1,800 3,611 Restored (2,934) (2,887) (2,835) Total (800) (1,087) 776 Total provision for income taxes $ 45,065 $ 46,472 $ 52,092 The tax effects of significant items comprising the Company's net deferred tax liability are as follows: 1998 1997 1996 Deferred tax assets: Regulatory liabilities $ 28,075 $ 34,072 $ 35,028 Advances for construction 10,401 18,665 17,736 Other 20,457 16,536 13,550 Total 58,933 69,273 66,314 Deferred tax liabilities: Electric plant 247,270 251,938 245,652 Regulatory assets 204,430 201,685 201,093 Investment tax credits 69,396 70,196 71,283 Conservation programs 16,866 14,377 13,720 Other 13,600 28,173 22,136 Total 551,562 566,369 553,884 Net deferred tax liabilities $492,629 $497,096 $487,570 Note 6 - Fair Value of Financial Instruments The estimated fair value of IPC's financial instruments has been determined by 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 estimated fair values for long-term debt and investments are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate. The total estimated fair value of IPC's debt was approximately $877.4 million in 1998, $801.8 million in 1997 and $806.8 million for 1996. Included in investments and other property were financial instruments totaling $16.5 million in 1997 and $18.0 million in 1996. Estimated fair value of these instruments was $19.9 million in 1997 and $18.7 million in 1996. These investments were included in the net assets transferred to IDACORP during 1998. Note 11 - Industry Segment Information In June 1997 the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This Statement requires financial and descriptive disclosure for fiscal years beginning after December 15, 1997, about certain operating segments of an enterprise as well as enterprise-wide disclosure of certain product and geographic information. IPC is predominantly a one operating segment company with its regulated electric operations being the most dominant segment. Other subsidiaries and non-utility operating segments do not individually constitute more than 10% of enterprise revenues, income or assets, nor in aggregate do they comprise more than 25% of enterprise revenues, income or assets. IPC's primary business is the generation, transmission, distribution, purchase and sale of electricity. IPC also began natural gas trading activities in May 1997 and reports this activity in Other Income in the Consolidated Statements of Income. The following table summarizes the segment information for the regulated electric operations with a reconciliation to total enterprise information: Regulated Electric Total Operations Other Enterprise (Thousands of Dollars) 1998 Revenues $1,121,976 $ - $1,121,976 Income from operations 191,221 - 191,221 Other income 5,909 3,547 9,456 Interest expense 56,646 3,047 59,693 Income before income 140,484 500 140,984 taxes Income taxes 51,447 (6,382) 45,065 Net income 89,037 6,882 95,919 Total assets 2,312,919 108,871 2,421,790 Expenditures for long- 91,803 19,197 111,000 lived assets 1997 Revenues $ 748,503 $ - $ 748,503 Income from operations 184,749 - 184,749 Other income 3,894 10,361 14,255 Interest expense 57,653 2,605 60,258 Income before income 130,990 2,580 133,570 taxes Income taxes 49,125 (2,653) 46,472 Net income 81,865 5,233 87,098 Total assets 2,338,524 113,292 2,451,816 Expenditures for long- 98,219 17,457 115,676 lived assets 1996 Revenues $ 578,445 $ - $ 578,445 Income from operations 187,171 - 187,171 Other income 2,759 9,775 12,534 Interest expense 56,110 885 56,995 Income before income 133,821 1,426 135,247 taxes Income taxes 51,386 706 52,092 Net income 82,435 720 83,155 Total assets 2,245,880 82,858 2,328,738 Expenditures for long- 97,484 34,595 132,079 lived assets Substantially all revenues come from the sale of electricity and related services, predominately in the United States. IPC sells natural gas, solar electric products and systems, control systems integration services for substations and semiconductor manufacturing, and miscellaneous other services however, these revenues are not significant. INDEPENDENT AUDITORS' REPORT To The Board of Directors and Shareowners of Idaho Power Company Boise, Idaho We have audited the accompanying consolidated balance sheets and statements of capitalization of Idaho Power Company and its subsidiaries as of December 31, 1998, 1997 and 1996, and the related consolidated statements of income, cash flows, retained earnings, and comprehensive income for the years then ended. Our audits also included the consolidated financial statement schedule listed in the Index 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 schedule 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, 1998, 1997 and 1996, 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 Boise, Idaho January 29, 1999 SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA: The following unaudited information is presented for each quarter of 1998, 1997 and 1996 (in thousands of dollars, except for per share amounts). In the opinion of the Companies, 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. IDACORP, INC. Quarter Ended March 31 June 30 September 30 December 31 1998 Revenues $238,170 $221,622 $392,378 $269,805 Income from operations 56,555 42,783 47,459 44,424 Income taxes 13,125 9,213 12,392 9,900 Net income 28,050 20,351 22,305 18,468 Earnings per share of 0.75 0.54 0.59 0.49 common stock 1997 Revenues 155,447 166,975 217,174 208,908 Income from operations 59,073 41,778 43,877 40,025 Income taxes 16,361 9,126 10,715 10,270 Net income 28,986 19,377 19,719 19,018 Earnings per share of 0.77 0.52 0.52 0.51 common stock 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 28,259 21,106 17,197 16,593 Earnings per share of 0.75 0.56 0.45 0.44 common stock Idaho Power Company Quarter Ended March 31 June 30 September 30 December 31 1998 Revenues $238,170 $221,622 $392,378 $269,805 Income from operations 56,555 42,783 47,459 44,424 Income taxes 13,125 9,213 12,392 10,335 Net income 29,455 21,768 23,715 20,979 Dividends on preferred 1,405 1,417 1,410 1,426 stock Earnings on common stock 28,050 20,351 22,305 19,553 1997 Revenues 155,447 166,975 217,174 208,908 Income from operations 59,073 41,778 43,877 40,025 Income taxes 16,361 9,126 10,715 10,270 Net income 30,380 20,042 21,141 20,715 Dividends on preferred 1,394 665 1,422 1,696 stock Earnings on common stock 28,966 19,377 19,719 19,019 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 1,952 1,927 1,954 1,632 stock Earnings on common stock 28,259 21,106 17,197 16,593 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III Part III has been omitted because the registrants will file a definitive proxy statement pursuant to Regulation 14A, which involves the election of Directors, with the Commission within 120 days after the close of the fiscal year portions of which are hereby incorporated by reference (except for information with respect to executive officers which is set forth in Part I hereof). PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Please refer to Item 8, "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules. (b) Reports on SEC Form 8-K. The following reports on Form 8-K were filed for the three months ended December 31, 1998: Items Reported Date of Report Filed by Item 5, Other Events September 15, 1998 IDACORP,Inc. Item 7, Exhibits Item 5, Other Events October 1, 1998 IDACORP, Inc. Item 7, Financial Statements and IPC and Exhibits (c) Exhibits. *Previously Filed and Incorporated Herein by Reference Exhibit File Number As Exhibit *2 333-48031 2 Agreement and Plan of Exchange between IDACORP, Inc.,and IPC dated as of February 2, 1998. *3(a) 33-00440 4(a)(xiii) Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 30, 1989. *3(a)(i) 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) of IPC, as filed with the Secretary of State of Idaho on November 5, 1991. *3(a)(ii) 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) of IPC, as filed with the Secretary of State of Idaho on June 30, 1993. *3(b) 33-41166 4(b) Waiver resolution to Restated Articles of Incorporation of IPC adopted by Shareholders on May 1, 1991. *3(c) 33-00440 4(a)(xiv) By-laws of IPC amended on June 30, 1989, and presently in effect. *3(d) 33-56071 3(d) Articles of Share Exchange of IDACORP, Inc. as filed with the Secretary of State of Idaho on September 29, 1998. *3(e) 333-64737 3.1 Articles of Incorporation of IDACORP, Inc. *3(f) 333-64737 3.2 Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998. *3(g) 333-00139 3(b) Articles of Amendment to Restated Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value as filed with the Secretary of State of Idaho on September 17, 1998. *3(h) 333-48031 3(c) Amended Bylaws of IDACORP, Inc. as of September 10, 1998. *4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as of October 1, 1937, between IPC and Bankers Trust Company and R. G. Page, as Trustees. *4(a)(ii) IPC Supplemental Indentures to Mortgage and Deed of Trust: Number Dated 1-MD B-2-a First July 1,1939 2-5395 7-a-3 Second November 15, 1943 2-7237 7-a-4 Third February 1, 1947 2-7502 7-a-5 Fourth May 1, 1948 2-8398 7-a-6 Fifth November 1, 1949 2-8973 7-a-7 Sixth October 1, 1951 2-12941 2-C-8 Seventh January 1, 1957 2-13688 4-J Eighth July 15,1957 2-13689 4-K Ninth November 15, 1957 2-14245 4-L Tenth April 1, 1958 2-14366 2-L Eleventh October 15, 1958 2-14935 4-N Twelfth May 15, 1959 2-18976 4-O Thirteenth November 15, 1960 2-18977 4-Q Fourteenth November 1, 1961 2-22988 4-B-16 Fifteenth September 15, 1964 2-24578 4-B-17 Sixteenth April 1,1966 2-25479 4-B-18 Seventeenth October 1, 1966 2-45260 2(c) Eighteenth September 1, 1972 2-49854 2(c) Nineteenth January 15, 1974 2-51722 2(c)(i) Twentieth August 1, 1974 2-51722 2(c)(ii) Twenty-first October 15, 1974 2-57374 2(c) Twenty-second November 15, 1976 2-62035 2(c) Twenty-third August 15, 1978 33-34222 4(d)(iii) Twenty-fourth September 1, 1979 33-34222 4(d)(iv) Twenty-fifth November 1, 1981 33-34222 4(d)(v) Twenty-sixth May 1, 1982 33-34222 4(d)(vi) Twenty-seventh May 1, 1986 33-00440 4(c)(iv) Twenty-eighth June 30,1989 33-34222 4(d)(vii) Twenty-ninth January 1, 1990 33-65720 4(d)(iii) Thirtieth January 1, 1991 33-65720 4(d)(iv) Thirty-first August 15, 1991 33-65720 4(d)(v) Thirty-second March 15, 1992 33-65720 4(d)(vi) Thirty-third April 16, 1993 1-3198 4 Thirty-fourth December 1, 1993 Form 8-K Dated 12/17/93 *4(b) Instruments relating to IPC American Falls bond guarantee. (see Exhibit 10(c)). *4(c) 33-65720 4(f) Agreement of IPC 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 IPC and First Chicago Trust Company of New York, as Rights Agent (The Bank of New York, successor Rights Agent). *4(e)(i) 1-3198 4(e)(i) Amendment, dated as of January 30, Form 10-K 1998, related to agreement filed as for 1997 Exhibit 4(e). *4(f) Form 8-K 4 Rights Agreement, dated as of dated September 10, 1998, between IDACORP, September 15, Inc. and the Bank of New York as 1998 Rights Agent. *10(a) 2-49584 5(b) Agreements, dated September 22, 1969, between IPC and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project. *10(a)(i) 2-51762 5(c) Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10(a). *10(b) 2-49584 5(c) Agreement, dated as of October 11, 1973, between IPC and Pacific Power & Light Company. *10(c) 33-65720 10(c) Guaranty Agreement, dated March 1, 1990, between IPC and West One Bank, as Trustee, relating to $21,425,000 American Falls Replacement Dam Bonds of the American Falls Reservoir District, Idaho. *10(d) 2-62034 5(r) Guaranty Agreement, dated as of August 30, 1974, between IPC and Pacific Power & Light Company. *10(e) 2-56513 5(i) Letter Agreement, dated January 23, 1976, between IPC and Portland General Electric Company. *10(e)(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 IPC. *10(e)(ii) 2-62034 5(t) Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(e). *10(e)(iii) 2-62034 5(u) Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(e). *10(e)(iv) 2-62034 5(v) Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10(e). *10(e)(v) 2-62034 5(w) Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(e). *10(e)(vi) 2-68574 5(x) Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(e). *10(f) 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(g) 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 IPC. *10(h)(i)1 1-3198 10(n)(i) The Revised Security Plan for Senior Form 10-K Management Employees - a non- for 1994 qualified, deferred compensation plan effective August 1, 1996. *10(h)(ii)1 1-3198 10(n)(ii) The Executive Annual Incentive Plan Form 10-K for senior management employees of for 1994 IPC effective January 1, 1995. *10(h)(iii)1 1-3198 10(n)(iii) The 1994 Restricted Stock Plan for Form 10-K officers and key executives of for 1994 IDACORP, Inc. and IPC effective July 1, 1994. 10(h)(iv)1 The Revised Security Plan for Board of Directors - a non-qualified, deferred compensation plan effective August 1, 1996, revised March 2, 1999. *10(i) 33-65720 10(h) Framework Agreement, dated October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights. *10(i)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). *10(i)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). *10(j) 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 IPC and the Twin Falls Canal Company and the Northside Canal Company Limited. *10(j)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February 10, 1992, between IPC and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. *10(k) 1-3198 10(y) Executive Employment Agreement dated Form 10-K November 20, 1996 between IPC and for 1997 Richard R. Riazzi. 12 Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(a) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(b) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP,Inc.) 12(c) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.) 12(d) Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IPC) 12(e) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC) 12(f) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC) 12(g) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC) 21 Subsidiaries of IDACORP,Inc. and IPC. 23 Independent Auditors' Consent. 27(a) Financial Data Schedule for IDACORP, Inc. 27(b) Financial Data Schedule for IPC. IDACORP, Inc. SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1998, 1997 and 1996 Column A Column B Column C Column D Column E Additions Charged Balance At Charged (Credited) Balance At Beginning to to Other Deductions (1)End Classification of Period Income Accounts Of Period (Thousands of Dollars) 1998: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,397 $ - $ 3,299(2) $3,299 $1,397 Other Reserves: Rate refunds $8,740 $4,188 $ - $7,572 $5,356 Injuries and damages reserve $1,500 $ - $ - $ - $1,500 Miscellaneous operating reserves $8,388 $ 512 $ - $1,993 $6,907 1997: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,394 $ - $3,384(2) $3,381 $1,397 Other Reserves: Rate refunds $4,873 $8,740 $ - $4,873 $8,740 Injuries and damages reserve $1,500 $ - $ - $ - $1,500 Miscellaneous operating reserves $1,774 $ 592 $7,245 $1,223 $8,388 1996: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $1,397 $ - $3,003(2) $3,006 $1,394 Other Reserves: Rate refunds $ - $4,873 $ - $ - $4,873 Injuries and damages reserve $1,500 $ - $ - $ - $1,500 Miscellaneous operating reserves $1,143 $ 681 $ - $ 50 $1,774 Notes: (1) Represents deductions from the reserves for purposes for which the reserves were created. (2) Represents collections of accounts previously written off. IDAHO POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 1998, 1997 and 1996 Amounts for Idaho Power Company are same as the above Schedule II for IDACORP, Inc. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. IDACORP, Inc. (Registrant) March 11, 1999 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 11, 1999 Joseph W. Marshall Chief Executive Officer and Director By: /s/Jan B. Packwood President and Chief " Operating Jan B. Packwood 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/Rotchford L. Barker By: /s/Evelyn Loveless " Rotchford L. Barker Evelyn Loveless Director Director By: /s/Robert D. Bolinder By: /s/Jon H. Miller " Robert D. Bolinder Jon H. Miller Director Director By: /s/Roger L. Breezley By: /s/Peter S. O'Neill " Roger L. Breezley Peter S. O'Neill Director Director By: /s/John B. Carley By: /s/Phil Soulen " John B. Carley Phil Soulen Director Director By: /s/Peter T. Johnson By: /s/Robert A. Tinstman " Peter T. Johnson Robert A. Tinstman Director Director By: /s/Jack K. Lemley " Jack K. Lemley Director SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. IDAHO POWER COMPANY. (Registrant) March 11, 1999 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 11, 1999 Joseph W. Marshall Chief Executive Officer and Director By: /s/Jan B. Packwood President and Chief " Operating Jan B. Packwood 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/Rotchford L. Barker By: /s/Evelyn Loveless " Rotchford L. Barker Evelyn Loveless Director Director By: /s/Robert D. Bolinder By: /s/Jon H. Miller " Robert D. Bolinder Jon H. Miller Director Director By: /s/Roger L. Breezley By: /s/Peter S. O'Neill " Roger L. Breezley Peter S. O'Neill Director Director By: /s/John B. Carley By: /s/Phil Soulen " John B. Carley Phil Soulen Director Director By: /s/Peter T. Johnson By: /s/Robert A. Tinstman " Peter T. Johnson Robert A. Tinstman Director Director By: /s/Jack K. Lemley " Jack K. Lemley Director EXHIBIT INDEX Exhibit Page Number Number 10(h)(iv) The Revised Security Plan for 81 Board of Directors - a non- qualified, deferred compensation plan effective August 1, 1996, revised March 2, 1999. 12 Statements Re: Computation of 103 Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(a) Statements Re: Computation of 104 Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(b) Statements Re: Computation of 105 Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.) 12(c) Statements Re: Computation of 106 Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.) 12(d) Statements Re: Computation of 107 Ratio of Earnings to Fixed Charges. (IPC) 12(e) Statements Re: Computation of 108 Supplemental Ratio of Earnings to Fixed Charges. (IPC) 12(f) Statements Re: Computation of 109 Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC) 12(g) Statements Re: Computation of 110 Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC) 21 Subsidiaries of IDACORP, Inc. 111 and IPC 23 Independent Auditors' 112 Consent. 27(a) Financial Data Schedule for 113 IDACORP, Inc. 27(b) Financial Data Schedule for 114 IPC EX-10 2 Exhibit 10(h)(iv) IDAHO POWER COMPANY SECURITY PLAN FOR BOARD OF DIRECTORS Amended and Restated Effective August 1, 1996 Revised March 8, 1999 TABLE OF CONTENTS ARTICLE I PURPOSE; EFFECTIVE DATE 1 1.1 Purpose 1 ARTICLE II DEFINITIONS 1 2.1 Actuarial Equivalent 1 2.2 Administrative Committee 2 2.3 Beneficiary 2 2.4 Board 2 2.5 Change in Control 2 2.6 Change in Control Period 4 2.7 Company 4 2.8 Compensation Committee 4 2.9 Contract of Participation 4 2.10 Employer 4 2.11 Participant 4 2.12 Plan Anniversary Date 4 2.13 Plan Year 4 2.14 Supplemental Retirement Benefit 4 2.15 Year of Service 4 ARTICLE III PARTICIPATION AND VESTING 5 3.1 Participation 5 3.2 Fee Reduction 5 3.3 Vesting 5 ARTICLE IV SURVIVOR BENEFITS 5 4.1 Death Benefit 5 4.2 Suicide 8 ARTICLE V RETIREMENT BENEFITS 8 5.1 Benefit 8 5.2 Form of Payment 9 5.3 Commencement of Benefit Payment 9 5.4 Grandfathered Form of Benefit 10 ARTICLE VI BENEFICIARY DESIGNATION 10 6.1 Beneficiary Designation 10 6.2 Amendments, Marital Status, No Participant Designation 10 6.3 Effect of Payment 11 ARTICLE VII TERMINATION, SUSPENSION OR AMENDMENT OF PLAN 11 7.1 Termination, Suspension or Amendment of Plan 11 7.2 Change in Control 11 ARTICLE VIII ADMINISTRATION 12 8.1 Administrative Committee Duties 12 8.2 Indemnity of Administrative Committee 12 ARTICLE IX CLAIMS PROCEDURE 13 9.1 Claim 13 9.2 Denial of Claim 13 9.3 Review of Claim 13 9.4 Final Decision 14 ARTICLE X MISCELLANEOUS 14 10.1 Unfunded Plan 14 10.2 Unsecured General Creditor 14 10.3 Trust Fund 15 10.4 Nonassignability 15 10.5 Governing Law 15 10.6 Validity 15 10.7 Notice 16 10.8 Successors 16 10.9 Payment to Guardian 16 10.10 Accelerated Distribution. 16 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 DEFINITION 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 VESTINGARTICLE III 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 employed by 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 an request and 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. Adopted this ____ day of ___________________________, 1996. IDAHO POWER COMPANY ____________________________________ Chairman APPENDIX A CONTRACT OF PARTICIPATION IN THE IDAHO POWER COMPANY SECURITY PLAN FOR BOARD OF DIRECTORS NAME OF PARTICIPANT: DATE OF BIRTH: SECURITY PLAN ENTRY DATE: BENEFICIARY: This Agreement is made and entered into as of the date written hereinbelow by and between Idaho Power Company and . This Agreement is subject to all of the terms of the Idaho Power Company Security Plan for Board of Directors, as amended and restated November 30, 1994 (The "Plan"). By signing this agreement,Participant acknowledges receipt of a copy of the Plan document. PARTICIPANT IDAHO POWER COMPANY BY BY PARTICIPANT CHAIRMAN DATE DATE EX-12 3
Ex-12 IDACORP, Inc. Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity method investments. 0 0 0 0 458 Minority interest in losses of majority owned subs................................ 0 0 0 0 (125) Fixed charges, as below..................... 66,324 70,215 70,418 69,634 69,923 Total earnings, as defined.............. $168,425 $195,499 $204,252 $199,261 $199,365 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677 Preferred stock dividends of subsidiaries- gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445 Rental interest factor...................... 794 925 991 982 801 Total fixed charges, as defined......... $66,324 $70,215 $70,418 $69,634 $69,923 Ratio of earnings to fixed charges.............. 2.54x 2.78x 2.90x 2.86x 2.85x
EX-12 4
Ex-12a IDACORP, Inc. Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity method investments............................... 0 0 0 0 458 Minority interest in losses of majority owned subs....................... 0 0 0 0 (125) Supplemental fixed charges, as below........ 68,946 72,826 73,018 72,208 72,496 Total earnings, as defined.............. $171,047 $198,110 $206,852 $201,835 $201,938 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677 Preferred stock dividends of subsidiaries- gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445 Rental interest factor...................... 794 925 991 982 801 Total fixed charges..................... 66,324 70,215 70,418 69,634 69,923 Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573 Total supplemental fixed charges........ $68,946 $72,826 $73,018 $72,208 $72,496 Supplemental ratio of earnings to fixed charges. 2.48x 2.72x 2.83x 2.80x 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-12 5
Ex-12b IDACORP, Inc. Consolidated Financial Information Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity method investments............................... 0 0 0 0 458 Minority interest in losses of majority owned subs................................ 0 0 0 0 (125) Fixed charges, as below..................... 66,324 70,215 70,418 69,634 69,923 Total earnings, as defined.............. $168,425 $195,499 $204,252 $199,261 $199,365 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677 Preferred stock dividends of subsidiaries- gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445 Rental interest factor...................... 794 925 991 982 801 Total fixed charges..................... 66,324 70,215 70,418 69,634 69,923 Preferred dividends requirements............ 0 0 0 0 0 Total combined fixed charges and preferred dividends................... $66,324 $70,215 $70,418 $69,634 $69,923 Ratio of earnings to combined fixed charges and preferred dividends....................... 2.54x 2.78x 2.90x 2.86x 2.85x Exhibit 12-B
EX-12 6
Ex-12c IDACORP, Inc. Consolidated Financial Information Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $101,775 $127,342 $135,247 $133,570 $133,806 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity method investments............................... 0 0 0 0 458 Minority interest in losses of majority owned subs................................ 0 0 0 0 (125) Supplemental fixed charges and Pref Div, as below.................................. 68,946 72,826 73,018 72,208 72,496 Total earnings, as defined.............. $171,047 $198,110 $206,852 $201,835 $201,938 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677 Preferred stock dividends of subsidiaries- gross up-Idcrp rate....................... 11,097 12,834 12,079 7,891 8,445 Rental interest factor...................... 794 925 991 982 801 Total fixed charges..................... 66,324 70,215 70,418 69,634 69,923 Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573 Supplemental fixed charges.................. 68,946 72,826 73,018 72,208 72,496 Preferred dividends requirements............ 0 0 0 0 0 Total combined supplemental fixed charges and preferred dividends............... $68,946 $72,826 $73,018 $72,208 $72,496 Supplemental ratio of earnings to combined fixed charges and preferred dividends.............. 2.48x 2.72x 2.83x 2.80x 2.79x * Explanation of increment: interest on the guaranty of American Falls District bonds and Milner Dam Inc. notes which are already included in operating expense. Exhibit 12-C
EX-12 7
Ex-12d Idaho Power Company Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity method investments............................... 0 0 0 0 476 Minority interest in losses of majority owned subs................................ 0 0 0 0 (125) Fixed charges, as below..................... 55,227 57,381 58,339 61,743 61,478 Total earnings, as defined.............. $164,726 $190,656 $199,636 $196,546 $198,116 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $ 60,677 Rental interest factor...................... 794 925 991 982 801 Total fixed charges, as defined....... $55,227 $57,381 $58,339 $61,743 $61,478 Ratio of earnings to fixed charges.............. 2.98x 3.32x 3.42x 3.18x 3.22x Exhibit 12-D
EX-12 8
Ex-12e Idaho Power Company Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity method investments............................... 0 0 0 0 476 Minority interest in losses of majority owned subs................................ 0 0 0 0 (125) Supplemental fixed charges, as below........ 57,849 59,992 60,939 64,317 64,051 Total earnings, as defined.............. $167,348 $193,267 $202,236 $199,120 $200,689 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677 Rental interest factor...................... 794 925 991 982 801 Total fixed charges..................... 55,227 57,381 58,339 61,743 61,478 Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573 Total supplemental fixed charges........ $57,849 $59,992 $60,939 $64,317 $64,051 Supplemental ratio of earnings to fixed charges. 2.89x 3.22x 3.32x 3.10x 3.13x * 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. Exhibit 12-E
EX-12 9
Ex-12f Idaho Power Company Consolidated Financial Information Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity mehtod investments............................... 0 0 0 0 476 Minority interest in losses of majority owned subs................................ 0 0 0 0 (125) Fixed charges, as below..................... 55,227 57,381 58,339 61,743 61,478 Total earnings, as defined.............. $164,726 $190,656 $199,636 $196,546 $198,116 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677 Rental interest factor...................... 794 925 991 982 801 Total fixed charges..................... 55,227 57,381 58,339 61,743 61,478 Preferred stock dividends-gross up-Ipc rate...................................... 10,682 12,392 12,146 7,803 8,275 Total combined fixed charges and preferred dividends.................. 65,909 $69,773 $70,485 $69,546 $69,753 Ratio of earnings to combined fixed charges and preferred dividends.......................... 2.50x 2.73x 2.83x 2.83x 2.84x Exhibit 12-F
EX-12 10
Ex-12g Idaho Power Company Consolidated Financial Information Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements Twelve Months Ended December 31, (Thousands of Dollars) 1994 1995 1996 1997 1998 Earnings, as defined: Income before income taxes.................. $109,173 $135,333 $142,710 $138,746 $140,984 Adjust for distributed income of equity investees................................. 326 (2,058) (1,413) (3,943) (4,697) Equity in loss of equity method investments............................... 0 0 0 0 476 Minority interest in losses of majority owned subs................................ 0 0 0 0 (125) Supplemental fixed charges and Pref Div, as below.................................. 57,849 59,992 60,939 64,317 64,051 Total earnings, as defined.............. $167,348 $193,267 $202,236 $199,120 $200,689 Fixed charges, as defined: Interest charges............................ $54,433 $56,456 $57,348 $60,761 $60,677 Rental interest factor...................... 794 925 991 982 801 Total fixed charges..................... 55,227 57,381 58,339 61,743 61,478 Supplemental increment to fixed charges*.... 2,622 2,611 2,600 2,574 2,573 Supplemental fixed charges.................. 57,849 59,992 60,939 64,317 64,051 Preferred stock dividends-gross up-Ipc rate...................................... 10,682 12,392 12,146 7,803 8,275 Total combined supplemental fixed charges and preferred dividends...... $68,531 $72,384 $73,085 $72,120 $72,326 Supplemental ratio of earnings to combined fixed charges and preferred dividends.............. 2.44x 2.67x 2.77x 2.76x 2.77x * Explanation of increment: Exhibit 12-G interest on the guaranty of American Falls District bonds and Milner Dam Inc. notes which are already included in operating expense.
EX-21 11 EXHIBIT 21 SUBSIDIARIES OF REGISTRANTS IDACORP, Inc: 1. Idaho Power Company (incorporated in Idaho) 2. Ida-West Energy Company (incorporated in Idaho) 3. IDACORP Energy Solutions Co. (incorporated in Nevada) 4. IDACORP Energy Services Co. (incorporated in Nevada) 5. IDACORP Energy Solutions L.P. (a Delaware limited partnership) Idaho Power Company 1. Idaho Energy Resources Company (incorporated in Wyoming) 2. IDACORP Financial Services, Inc. (incorporated in Idaho) 3. Stellar Dynamics Inc. (incorporated in Idaho) 4. Idaho Power Resources Corporation (incorporated in Idaho) 5. Applied Power Corporation (incorporated in Washington) 6. Idaho Power Diversified Enterprises Co. (incorporated in Idaho) 7. Pathnet/Idaho Power Equipment, LLC (a Delaware Limited Liability Company) EX-23 12 EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Idaho Power Company's Registration Statement No. 33-51215 on Form S-3 and IDACORP, Inc.'s Registration Statement Nos. 33-56071 and 333-65157 on Form S-8 and Registration Statement Nos. 333-00139 and 333-64737 on Form S-3 of our reports dated January 29, 1999 on IDACORP, Inc. and Idaho Power Company, appearing in this Annual Report on Form 10-K of IDACORP, Inc. and Idaho Power Company for the year ended December 31, 1998. DELOITTE & TOUCHE LLP Boise, Idaho March 19, 1999 EX-27 13 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT This schedule contains summary financial information extracted from IDACORP, Inc.(Ex-27A) and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1998 DEC-31-1998 PER-BOOK 1,711,509 129,437 230,223 380,451 0 2,451,620 451,564 0 278,833 730,397 0 105,968 802,199 0 13,738 38,524 6,029 0 0 0 754,765 2,451,620 1,121,976 44,630 930,755 975,385 146,591 8,020 154,611 65,435 89,176 0 89,176 69,868 52,270 169,887 2.37 2.37
EX-27 14
UT This schedule contains summary financial information extracted from Idaho Power (EX-27B) Company and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1998 DEC-31-1998 PER-BOOK 1,710,696 105,600 225,589 379,905 0 2,421,790 94,031 358,333 252,363 704,727 0 105,968 802,199 0 13,738 38,508 6,029 0 0 0 750,621 2,421,790 1,121,976 45,065 930,755 975,820 146,156 9,456 155,612 59,693 95,919 5,658 90,261 69,889 52,279 173,725 0 0
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