-----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, QFZsktMCrdJY47ZDtQ0zjPgihiP0MiWqhs6Qh9O9n/jIKk3n/kppNQVS2G971JX5 X8ebD4TqqPVX8KzgHx1RYg== 0001057877-00-000013.txt : 20000321 0001057877-00-000013.hdr.sgml : 20000321 ACCESSION NUMBER: 0001057877-00-000013 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000320 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: 573549 BUSINESS ADDRESS: STREET 1: 1221 W IDAHO ST STREET 2: PO BOX 70 CITY: BOISE STATE: ID ZIP: 83702 BUSINESS PHONE: 2083882200 FILER: COMPANY DATA: COMPANY CONFORMED NAME: IDACORP INC CENTRAL INDEX KEY: 0001057877 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 820505802 STATE OF INCORPORATION: ID FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-14465 FILM NUMBER: 573550 BUSINESS ADDRESS: STREET 1: 1221 WEST IDAHO STREET CITY: BOISE STATE: ID ZIP: 83702-5627 BUSINESS PHONE: 2083882200 MAIL ADDRESS: STREET 1: 1221 WEST IDAHO STREET CITY: BOISE STATE: ID ZIP: 83702-5627 10-K405 1 TABLE OF CONTENTS PART I PAGE ITEM 1. BUSINESS 2 GENERAL 2 ELECTRIC INDUSTRY RESTRUCTURING 3 REGULATION 3 RATES 4 POWER SUPPLY 5 FUEL 6 WATER RIGHTS 7 ENVIRONMENTAL REGULATION 7 RESEARCH AND DEVELOPMENT 9 DIVERSIFIED BUSINESS OPERATIONS 9 CONSTRUCTION PROGRAM 11 FINANCING PROGRAM 11 ITEM 2. PROPERTIES 13 ITEM 3. LEGAL PROCEEDINGS 15 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 16 EXECUTIVE OFFICERS OF THE REGISTRANTS 17 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. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK 32 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 33 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 69 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS* 69 ITEM 11. EXECUTIVE COMPENSATION* 69 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT* 69 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 69 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K 69 SIGNATURES 75 *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, 1999 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 their charters, Commission address of principal executive IRS Employer Iden- File Number offices and Registrants' tification Number telephone 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 Preferred Stock Purchase Rights 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, 2000) IDACORP, Inc.: $1,160,332,841 Idaho Power Company: None Number of shares of common stock outstanding at February 29,2000: 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 - 13 Portions of the joint definitive proxy statement of the Registrant. to be filed pursuant to Regulation 14A for the 2000 Annual Meeting of Shareholders to be held on May 11, 2000. This Combined Form 10-K represents separate filings by IDACORP, Inc. and Idaho Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Idaho Power Company makes no representations as to the information relating to IDACORP, Inc.'s other operations. 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. (IDACORP or the Company) is a holding company incorporated in 1998 under the laws of the state of Idaho. The Company's principal subsidiary is Idaho Power Company (IPC), an electric public utility that represents over 90 percent of IDACORP's total assets and substantially all of its operating revenues. IDACORP's other subsidiaries include Ida-West Energy Company, an independent power project management and development company, IDACORP Energy Solutions, LP, a marketer of energy commodities, and IDACORP Technologies, Inc., a majority owner of Northwest Power Systems, a developer of integrated fuel cell systems. IPC was 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 794,000. IPC holds franchises in approximately 72 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, 1999, IPC supplied electric energy to 384,421 general business customers and employed 1,720 people in its operations. IPC operates 17 hydroelectric 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. IPC's 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 incorporates a major portion of the operating expenses with the largest variation potential (net power supply costs), IPC's operating results have become 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. 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 the Bonneville Power Administration (BPA) and other utilities, IPC has access to all the major electric systems in the West. For the year ended December 31, 1999, total revenues from residential customers accounted for 41 percent 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 or more accounted for 23 percent, irrigation customers accounted for 12 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. ELECTRIC INDUSTRY RESTRUCTURING The legislatures and/or the regulatory commissions in several states, and at a national level, have considered or are considering various forms of retail competition. In 1997, the Idaho Legislature appointed a committee to study restructuring of the electric utility industry. Although the committee will continue studying a variety of restructuring ideas, it has not recommended any restructuring legislation and is not expected to in the foreseeable future. In 1999 the Oregon legislature passed legislation restructuring the electric utility industry in that state, but exempted IPC's service territory. In December 1999 the FERC issued Order No. 2000, dealing with Regional Transmission Organizations (RTOs). It proposes to ensure non-discriminatory, open-access to electricity transmission facilities. Each utility is required to file by October 15, 2000 a statement regarding its intention to join a RTO. IPC is engaged in formation discussions with other Northwest utilities. These utilities include both investor-owned and other entities. IPC's resource acquisition policy reflects the changing nature of the electric utility industry. 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. REGULATION IPC is under the regulatory jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities Commission (IPUC), the Oregon Public Utility Commission (OPUC) and the Public Utility 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 Public Utilities Regulatory Policy Act of 1978 (PURPA), the state regulatory agencies have each issued orders and rules regulating IPC's purchase of power from Cogeneration and Small Power Production (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"). RATES Idaho Jurisdiction - IPC adjusts its Idaho retail rates based on a PCA mechanism adopted in 1993. The PCA enables IPC to collect or refund a portion of the difference between net power supply costs actually incurred and power supply costs allowed in base rates. These adjustments, which take effect annually in mid-May, are based on two components: the difference between a forecast of the upcoming year's net power supply costs and the amount in base rates, and a true-up of the prior year's forecasted costs to actual costs. The May 1999 rate adjustment reduced rates by 9.2 percent. The decrease was the result of both forecasted above-average hydroelectric generating conditions for the upcoming year and a true-up from the 1998-99 rate period. Overall, the May 1999 rate adjustment is expected to decrease annual general business revenue by $40 million during the 1999-2000 rate period. So far in the 1999-2000 rate period, actual power costs and generating conditions have been near forecast. IPC has recorded a regulatory asset and a reduction of expenses of $1.7 million as of December 31, 1999, representing the difference between actual and forecasted costs so far in this rate period. The variance that exists at the end of the 1999-2000 rate period will be trued- up in the next annual PCA adjustment. The May 1998 rate adjustment increased expected annual revenue by $34 million over the amount that would have been recorded at the 1997-98 rates. The 1998-99 forecast had assumed a return to more normal hydroelectric generating conditions from the above-average conditions experienced in the prior year. This resulted in forecasted power supply costs being near the amounts used in base rates. In August 1995 the IPUC approved a Settlement that authorized IPC to defer and amortize costs related to reorganization in return for a general rate freeze through the end of 1999. Under the Settlement, which expired at the end of 1999, when actual annual earnings exceeded an 11.75 percent return on year- end common equity for the Idaho jurisdiction, the Company shared 50 percent of the additional earnings with its Idaho retail customers. IPC set aside approximately $8.9 million, $6.4 million and $7.6 million for 1999, 1998 and 1997 respectively for the benefit of its Idaho customers. Of the $14.0 million set aside during 1997 and 1998, $6.2 million was applied against Idaho demand-side management / conservation expenditures and $2.6 million was applied to 1997-1998 Northwest Energy Efficiency Alliance (NEEA) expenditures. In addition, $2.0 million was reserved to fund 1999 NEEA and demand-side management (DSM) expenditures (once they have been approved for recovery by the IPUC), and $0.7 million was refunded to certain customers. The balance of $2.5 million has been set in a reserve for the benefit of Idaho customers. The disposition of this benefit has yet to be determined. In December 1999 IPC filed a request that $5.5 million of the 1999 sharing amount be reserved to fund 2000-2004 NEEA participation. Other important points in the Settlement were that IPC was not allowed to increase its Idaho general rates prior to January 1, 2000, except under special conditions as defined in the Settlement, and IPC agreed that its quality of service would 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. This order was appealed to the Idaho Supreme Court by a group of IPC customers. Oral arguments were heard on December 8, 1999 and the matter is awaiting a Supreme Court decision. 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 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"). 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 resources. IPC's system is dual-peaking, with the larger peak demand generally occurring in the summer. The system peak demand for 1999 was 2,839 MW, set on July 13, 1999. Peak demands in 1998 and 1997 were 2,747 MW and 2,545 MW respectively. IPC periodically updates its load and resource projections and now expects total system energy requirements to grow 2.3 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 (water) 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 2000-2003 period, IPC plans to provide all the energy required to serve its firm load requirements by using its hydroelectric and coal-fired generating units and CSPP purchases, 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 1997, 1998 and 1999, IPC's hydro generating system experienced above average water years. 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 Avista Corporation, PacifiCorp, The Montana Power Company and Sierra Pacific Power Company. Such interconnections, coupled with transmission line capacity made available under agreements with certain of the above utilities, permit the interchange, purchase and sale of power among all major 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 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 65 CSPP projects on-line as of December 31, 1999 is $56.2 million. During 1999, IPC purchased 931.8 million kWh of power from these private developers at a blended price of 6.3 cents per kWh. The IPUC has 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 and has limited the length of new contracts to a maximum of five years. Wholesale Power Sales - IPC has firm wholesale power sales contracts with several entities. These contracts are for various amounts of energy, up to 100 average megawatts, and are of various lengths expiring between 2000 and 2009. 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 December 1999 the FERC issued Order No. 2000, dealing with Regional Transmission Organizations (RTOs). It proposes to ensure non-discriminatory, open-access to electricity transmission facilities. Each utility is required to file by October 15, 2000 a statement regarding its intention to join a RTO. IPC is engaged in formation discussions with other Northwest utilities. These utilities include both investor-owned and other entities. 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. The FERC has issued an unconditional acceptance of the terms and conditions of IPC's tariff. 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 both provide transmission services and reach a broad power sales market. IPC is a member of both the Western Regional Transmission Association and the Northwest Regional Transmission Association. These associations help facilitate transmission access and planning throughout the power system. FUEL IPC, through its subsidiary Idaho Energy Resources Co., owns a one-third interest in the Bridger Coal Company, which owns the Jim Bridger 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. The Jim Bridger 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 Black Butte and Leucite Hills mines located near 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. Sierra Pacific Power Company (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), has a long- term coal contract with Southern Utah Fuel Company, a subsidiary of Canyon Fuel Co., LLC. This contract, which expires on June 30, 2003, calls 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. In 1986 IPC 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 for at least the next 10 years. 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. ENVIRONMENTAL REGULATION Environmental regulation at the federal, state, regional and local levels is having a continuing impact on IPC's operations due to the cost of installation and operation of equipment required for compliance with such regulations 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 2000 and during the period 2001-2004 will total approximately $10.8 million and $47.3 million, respectively. Studies related to mitigation of environmental concerns due to relicensing of hydro facilities will be a major portion of these expenditures. IPC anticipates incurring approximately $24 million annually of operating expenses for environmental facilities during the period 2000-2004, 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 material adverse effects upon its operations with regard to SO2 emissions. In July 1997 the Environmental Protection Agency (EPA) announced new National Ambient Air Quality Standards (NAAQS) for ozone and Particulate Matter (PM) and in July 1999 the EPA announced regional haze regulations for protection of visibility in national parks and wilderness areas. Other parties have appealed the NAAQS standards on the constitutionality of the primary protective standards that were set. Impacts of the ozone and PM regulations and regional haze regulations on IPC's thermal operations are unknown at this time. North Valmy, Boardman and Jim Bridger Unit 4 elected to meet Phase I nitrogen oxide (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 NO x limits until 2008. Had the units not voluntarily "early elected," they would have been required to meet the Phase II limits in 2000. Jim Bridger Units 1, 2, and 3 were accepted as substitution units in 1995 and are subject to NO x limits of Phase I instead of the more restrictive limits of Phase II. Jim Bridger has installed low NO x equipment to reduce NO x 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 period from May 15 to October 15 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, 1999, the investment in these facilities was $12.3 million and the annual cost of operation pursuant to FERC License 1971 was approximately $2.6 million annually. 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 Operations - Environmental Issues".) Hazardous/Toxic Wastes and Substances - Under the Toxic Substances Control Act (TSCA), the 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 system. This program will save costs associated with the long-term monitoring and testing of equipment and grounds for PCB contamination as well as being good for the environment.. Total IPC costs for the identification and disposal of PCBs from IPC's system were $0.6 million, $0.5 million and $1.0 million for 1999, 1998 and 1997 respectively. IPC believes that all generation facilities are presently non-PCB. RESEARCH AND DEVELOPMENT In March 1999 IDACORP Technologies, Inc., a subsidiary of IDACORP, purchased a controlling interest in Northwest Power Systems (NPS). NPS owns several patents on 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. Fully operational prototypes have been constructed and successfully tested. During 1999, IPC spent approximately $0.4 million on research and development of which $0.3 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 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 Department of Energy, Lockheed and PES to test the electrolyzer and validate the operating characteristics of the unit. As an active member of the NEEA, IPC has been shifting the focus of its conservation, or 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 1999, $2.1 million was expended on energy-efficiency programs. DIVERSIFIED BUSINESS OPERATIONS The Company has been pursuing a strategy of expanding non- regulated activities and separating the regulated utility operations of IPC from non-regulated activities. The following discussion highlights significant events related to this strategy. In mid-1997, IPC began trading natural gas, opening trading offices in Houston, Texas and Boise, Idaho. Beginning in 1999, these unregulated trading operations were transferred from under IPC to IDACORP Energy Solutions L.P., an unregulated subsidiary of IDACORP. IPC has also greatly increased its participation in electricity commodity markets. IDACORP plans to move this electricity marketing activity out of IPC and to a non-regulated branch of the Company in 2000. IDACORP Technologies' NPS focuses on the production and distribution of fully-integrated fuel cell systems that combine its patented reformer with other fuel cell components. NPS has received orders from the BPA and other parties for more than 115 prototype fuel cell systems, with delivery scheduled to begin in March 2000. At December 31, 1999, total investment in IDACORP Technologies was $2.5 million. Ida-West Energy Company develops, acquires, owns and manages electric power projects. In March 2000, Ida-West sold for cash its interest in the Hermiston Power Project, a 536 MW, gas-fired project to be located near Hermiston, Oregon. Ida-West was responsible for managing all permitting and development activities relating to the project since its inception in 1993. The Company anticipates recording a pre-tax gain of approximately $14.0 million on this transaction in 2000. Ida-West has investments in 12 operating hydroelectric plants with a total generating capacity of approximately 72 MW. IPC has purchased all of the power from the five Idaho hydroelectric entities that are fifty percent owned by Ida-West, totaling approximately $8.8 million in 1999. Through September 30, 1998, Ida-West was a subsidiary of IPC. On October 1, 1998 Ida-West was transferred to become a direct subsidiary of IDACORP. At December 31, 1999, total investment in Ida-West was $29.3 million. In 1998 and 1999, another IDACORP subsidiary, IDACORP Energy Solutions Co. (IESCo), introduced a variety of energy and non- energy related products, such as home surge protectors, carbon monoxide detectors, internet services, digital satellite television systems, and payment protection 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, IESCo is developing new products and services to offer to retail customers. Collectively, the members of the alliance serve approximately one million customers. IDACORP Financial Services, Inc. (IFS) has a portfolio of 17 investments, primarily in affordable housing programs, which provide a return primarily by reducing federal income taxes through tax credits and tax depreciation benefits. On December 31, 1999, total investment in IFS was $18.7 million. On January 1, 2000, ownership of IFS was transferred from IPC to become a direct subsidiary of IDACORP. 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. At December 31, 1999, total investment in APC was $3.4 million. On January 1, 2000, IPC's ownership interest in APC was also transferred to IDACORP. Idaho Energy Resources Company (IERCo), a subsidiary of IPC, is 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"). At December 31, 1999, total investment in IERCO was $12.9 million. Pathnet/Idaho Equipment, LLC (Pathnet), a subsidiary of IPC, was formed in 1998 to develop and distribute microwave communication services and products. At December 31, 1999, total investment in Pathnet was $1.7 million. CONSTRUCTION PROGRAM IPC's construction program for the 2000-2004 period (excluding allowances for funds used during construction) is presently estimated to require cash funds of approximately $580.9 million as follows: 2000 2001-2004 (Millions of Dollars) Generating facilities Hydro $ 14.3 $ 61.5 Thermal 7.2 27.3 Total generating facilities 21.5 88.8 Transmission lines and substations 23.6 75.5 Distribution lines and substations 46.8 216.0 General 28.3 72.2 Total IPC cash construction 120.2 452.5 Non-utility cash construction 0.8 7.4 Total IPC cash construction expenditures $ 121.0 $ 459.9 IPC has no nuclear involvement and its future construction plans do not include development of any nuclear generation. IPC is looking at various options that may be available to meet the future energy requirements of its customers including efficiency improvements on IPC's generation, transmission and distribution systems and purchased power and exchange agreements with other utilities or other power suppliers. IPC will pursue the projects that best meet its future energy needs. FINANCING PROGRAM The Company's five-year estimate of capital requirements and sources of capital are outlined in the following table: IDACORP, Inc. Idaho Power Company 2000 2001-2004 2000 2001-2004 (Millions of Dollars) Capital Requirements: Net cash construction expenditure $120.2 $452.5 $120.2 $452.5 Other cash expenditures 21.4 50.1 0.8 7.4 Total $141.6 $502.6 $121.0 $459.9 Sources of Capital: Internal generation $119.1 $550.6 $ 99.2 $421.1 Short-term bank loans - Net 17.8 (17.8) 22.0 50.4 Affordable housing debt repayment (8.9) (39.3) - - Other debt issued 11.5 20.9 - (0.9) Other 1.5 (10.7) (0.2) (10.7) Cash investments (increase) 0.6 (1.1) - - Total $141.6 $502.6 $121.0 $459.9 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, 1999, net earnings were 5.94 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, 1999, the actual preferred dividend earnings coverage was 3.33 times. If the dividends on the shares of Auction Preferred Stock were to reach the maximum allowed, the preferred dividend earnings coverage would be 3.05 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 4,656 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 Project Non- Coincident Operating Nameplate License Capacity Capacity Expiration kW kW 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 (a) 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) 703,333 709,617 Valmy (coal-fired) 260,650 260,650 Boardman (coal-fired) 53,000 56,050 (a)Renewed on a year-to-year basis; application for relicense is pending. At December 31, 1999, the composite average ages of the principal parts of IPC's system, based on dollar investment, were: production plant, 20 years; transmission system and substations, 19 years; and distribution lines and substations, 15 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 it is in the public interest for IPC to continue to hold the federal licenses. IPC is actively pursuing new licenses for 10 of its 17 hydroelectric projects from the FERC. This process could take anywhere from eight to 15 years, depending on environmental issues and political processes. The most significant relicensing will be the Hells Canyon Complex, which provides over half of IPC's generation capacity. Presently, IPC is developing study plans within the framework of a collaborative team made up of individuals representing state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests. IPC expects to file the new license application in August 2003. Shoshone Falls, Upper Salmon Falls, Lower Salmon Falls and Bliss hydroelectric projects are awaiting the Environmental Impact Statement (EIS) from the federal government, which will precede license issuance. IPC is completing additional information requests (AIRs) in 2000, which will provide the government with the necessary data to complete the environmental impact statement by mid-to-late 2000. IPC filed its application for new license for the CJ Strike project in November 1998. Similarly, AIRs were issued on this project as well and are scheduled to be completed in October 2000, which should result in an EIS by mid-2001. The Upper and Lower Malad projects, scheduled for an August 2002 new license application, are nearing completion of field studies and reporting should be complete in 2000. 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 twelve 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 Idaho Public Utilities Commission (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 Commission's order and has never posted the $1.9 million amount required by the FESA. After the IPUC's order became final and non-appealable, 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 Idaho Power 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. The case was fully briefed in 1999 and argued on January 5, 2000. The parties are now awaiting a decision from the court. This matter has been previously reported in Form 10-K dated March 11, 1999 and other reports filed with the Commission. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None EXECUTIVE OFFICERS OF THE REGISTRANT The names, ages and positions of all of the executive officers of IDACORP, Inc. are listed below along with their business experience during the past five years. 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* Jan B. Packwood, 56 Appointed May 30, 1999. Mr. Packwood President and Chief was President and Chief Operating Executive Officer Officer from February 2, 1998 to May 30, 1999. J. LaMont Keen, 47 Appointed May 5, 1999. Mr. Keen was Senior Vice President - Senior Vice President-Administration, Administration and Chief Chief Financial Officer and Treasurer Financial Officer from March 15, 1999 to May 5, 1999, and Vice President, Chief Financial Officer and Treasurer from February 2, 1998 to March 15, 1999. Richard Riazzi, 45 Appointed March 15, 1999. Mr. Riazzi Senior Vice President - was Vice President - Marketing and Marketing and Sales Sales from January 14, 1999 to March 15, 1999. Darrel T. Anderson, 41 Appointed May 5, 1999. Vice President - Finance and Treasurer Robert W. Stahman, 55 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. EXECUTIVE OFFICERS OF THE REGISTRANT The names, ages and positions of all of the executive officers of Idaho Power Company are listed below along with their business experience during the past five years. 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. Idaho Power Company Name, Age and Position Business Experience During Past Five (5) Years Jan B. Packwood, 56 Appointed May 30, 1999. Mr. Packwood President and Chief was President and Chief Operating Executive Officer Officer from September 1, 1997 to May 30, 1999, Executive Vice President from July 11, 1996 to September 1, 1997, and Vice President-Power Supply prior to July 11, 1996. J. LaMont Keen, 47 Appointed May 5, 1999. Mr. Keen was Senior Vice President - Senior Vice President-Administration, Administration and Chief Chief Financial Officer and Treasurer Financial Officer from March 15, 1999 to May 5, 1999, Vice President, Chief Financial Officer and Treasurer from March 14, 1996 to March 15, 1999 and Vice President and Chief Financial Officer prior to March 14, 1996. James C. Miller, 45 Appointed November 18, 1999. Mr. Senior Vice President - Miller was Vice President - Delivery Generation from July 10, 1997 to November 18, 1999 and was General Manager - Generation prior to July 10, 1997. Richard Riazzi, 45 Appointed March 15, 1999. Mr. Riazzi Senior Vice President - was Vice President - Marketing and Marketing and Sales Sales from January 9, 1997 to March 15, 1999. Mr. Riazzi was Vice President, Corporate Marketing (1995- 1996) for Equitable Resources, Inc. Darrel T. Anderson, 41 Appointed May 5, 1999. Mr. Anderson Vice President - Finance was corporate controller from January and Treasurer 25, 1999 to May 5, 1999, Executive Vice President of Finance and Operations at Applied Power Corp. from June 5, 1998 to January 25, 1999, and corporate controller from February 26, 1996 to June 5, 1998. Mr. Anderson was Senior Manager of Audit Services for Deloitte & Touche LLP prior to February 26, 1996. John P. Prescott, 43 Appointed November 18, 1999. Mr. Vice President - Prescott was Vice President of Generation Business Development for IDACORP Technologies, Inc. from August 1999 to November 18, 1999, and President and Treasurer of Stellar Dynamics from October 5, 1995 to August 1999. Bryan A.B. Kearney, 37 Appointed November 18, 1999. Mr. Vice President and Chief Kearney was Vice President and Chief Information Officer Technology Officer at Bear Creek Corp (1998-1999), Chief Information Officer for Shasta County, California (1996-1998), and Director of Information Systems and Services for the City of Fort Worth, Texas (1994- 1995). Cliff N. Olson, 50 Appointed July 11, 1991. Vice President -Corporate Services Robert W. Stahman, 55 Appointed July 13, 1989. Vice President, General Counsel and Secretary Marlene K. Williams, 47 Appointed May 5, 1999. Ms. Williams Vice President - Human was Director of Human Resources at Resources Arizona Public Service prior to May 5, 1999. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATE STOCKHOLDER MATTERS IDACORP, Inc.'s common stock (without par value) is traded on the New York and Pacific Stock Exchanges. At December 31, 1999, there were 23,758 holders of record and the year-end stock price was $26 13/16 per share. The outstanding shares of Idaho Power Company common stock ($2.50 par value) are held by IDACORP, Inc. and are not traded. IDACORP, Inc. became the holding company of Idaho Power Company on October 1, 1998. The following table shows the reported high and low sales price and dividends paid for the years 1999 and 1998 as reported by the Wall Street Journal as composite tape transactions. Amounts reported for periods prior to October 1, 1998, were for Idaho Power Company only. 1999 Quarters Common Stock, without par 1st 2nd 3rd 4th value: High $ 36 1/2 $ 33 5/8 $ 32 $ 31 1/4 Low 29 1/4 29 1/2 29 3/16 26 Dividends paid per share (cents) 46.5 46.5 46.5 46.5 ______________________________ 1998 Quarters Common Stock, without par 1st 2nd 3rd 4th value: 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 ITEM 6. SELECTED FINANCIAL DATA SUMMARY OF OPERATIONS (Thousands of Dollars except for per share amounts) IDACORP, Inc. For the Years Ended 1999 1998 1997 1996 1995 December 31, Operating revenues $ 658,336 756,410 605,183 578,445 545,621 Income from operations 172,458 180,584 180,731 187,171 175,991 Net income 91,349 89,176 87,098 83,155 78,930 Earnings per average share outstanding (basic and diluted) 2.43 2.37 2.32 2.21 2.10 Dividends declared per share 1.86 1.86 1.86 1.86 1.86 At December 31, Total long-term debt* 821,558 815,937 746,142 769,810 672,618 Total assets 2,636,993 2,451,620 2,451,816 2,328,738 2,241,753 *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) IDAHO POWER COMPANY For the Years Ended 1999 1998 1997 1996 1995 December 31, Operating revenues $ 658,336 $ 756,410 $ 605,183 $ 578,445 $ 545,621 Income from operations 172,458 180,584 180,731 187,171 175,991 Net income 97,528 95,919 92,274 90,618 86,921 At December 31, Total long-term debt* 821,558 815,937 746,142 769,810 672,618 Total assets 2,559,374 2,421,790 2,451,816 2,328,738 2,241,753 Utility Customer Data: General business 384,421 373,730 363,085 352,487 340,708 customers Average kWh per customer 36,379 36,368 37,080 37,627 35,740 Average rate per kWh (cents) 3.75 3.85 3.63 3.71 3.85 *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) and Idaho Power Company and its subsidiaries (IPC). IDACORP is a holding company formed in 1998 as the parent of IPC and several other entities. IPC, an electric utility, is IDACORP's principal operating subsidiary, and accounts for over 90 percent of its 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, 1999, 1998 and 1997. 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, any 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 $2.43 in 1999, $2.37 in 1998, and $2.32 in 1997. The 1999 earnings equate to a 12.1 percent return on year-end common equity, as compared to 12.2 percent in 1998 and 1997. At December 31, 1999, the book value per share of common stock was $20.02, compared to $19.42 at December 31, 1998 and $18.93 at December 31, 1997. Overview The primary factors contributing to the increase in earnings per share over the last three years are a strong economy in our utility service territory and favorable energy marketing results. Idaho's economy continued its strong performance over the last three years. Idaho's non-agricultural employment growth for the twelve months ended November 1999 was 2.4 percent; annual growth rates in 1998 and 1997 were 2.4 percent and 3.2 percent, respectively. Within the Boise Metropolitan Statistical Area, the heart of our utility service territory, non-agricultural employment increased 3.2 percent for the twelve months ended November 1999, 4.1 percent in 1998 and 4.2 percent in 1997. General business customer growth has been consistent, with 2.9 percent increases in 1999 and 1998 and a 3.0 percent increase in 1997. This growth is attributable to strong overall economic conditions in our utility service territory. Our service territory experienced above average water years from 1997-1999. Hydro generation was 17 percent above normal in 1999, 22 percent above normal in 1998, and 30 percent above normal in 1997. Our energy marketing income increased $14 million in 1999 due to favorable conditions in the energy markets and $5 million in 1998 due to growth in this business segment. Income from operations decreased $8 million in 1999 primarily due to a $5 million decrease in other revenues resulting from increased funds set aside for refund to IPC ratepayers as part of a regulatory settlement with the IPUC. This increase results from an increase in the amount set aside for 1999 compared to 1998, plus true-ups of prior years' sharing estimates. We discuss the regulatory settlement below in "Regulatory Issues - Regulatory Settlement." Another factor impacting operating income was a decrease in the net power supply costs (surplus sales less purchased power, fuel, and PCA expense) of $6 million due to effective management of the system given a combination of favorable market, weather and hydro conditions throughout the year. Other factors impacting income from operations were a $7 million increase in other operation and maintenance expenses, and a $3 million increase in depreciation expense. Income from operations decreased slightly in 1998. The primary factors affecting income from operations were a $3 million increase in depreciation expense, offsetting a $3 million increase in other revenue resulting primarily from decreased amounts set aside for the regulatory settlement with the IPUC. While general business increased, that increase was offset by a similar increase in net power supply costs. 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 conditions. IPC's rates are adjusted annually based primarily on a Power Cost Adjustment (PCA) mechanism that is described more fully below in "Regulatory Issues - Power Cost Adjustment." Generally, extreme temperatures increase sales to customers, who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the growing season affect sales to customers who use electricity to operate irrigation pumps. Increased precipitation reduces electricity usage by these customers. In 1999, general business revenue was only marginally higher than 1998. The 2.9 percent increase in general business customers increased revenue $7 million and drier weather conditions and other factors affecting usage increased revenue $12 million. These increases were nearly offset by reductions in rates stemming from the PCA, which decreased revenue $17 million. The $34 million increase in general business revenue in 1998 was due primarily to increased rates, which increased revenue $31 million, and the 2.9 percent increase in general business customers, which increased revenue $16 million. These increases were offset by a $12 million decrease resulting from more precipitation and more moderate weather conditions. Power Supply Power supply components of income from operations include off- system sales and purchased power, fuel and PCA expenses. Off-system sales, which consist primarily of long-term sales contracts and opportunity sales of surplus system energy, decreased $95 million in 1999 after increasing $114 million in 1998. Purchased power expense decreased $79 million in 1999 after increasing $105 million in 1998. Contributing to these results are a number of operational factors, including changing hydro availability, system load and fluctuating wholesale market conditions. Net off-system sales less purchases were 2.8 million MWh in 1999, compared to 3.2 million MWh in 1998 and 3.1 million MWh in 1997. Fuel expenses were essentially unchanged in 1999 but increased by $15 million in 1998. Total generation at our coal-fired plants was approximately 7.3 million MWh in 1999, 6.9 million MWh in 1998 and 5.4 million MWh in 1997. The PCA expense component is related to the Company's PCA regulatory mechanism. The PCA mechanism increases expenses when power supply costs are below forecast, and decreases expenses when power supply costs are above forecast. In 1999, actual costs were near forecast, causing the PCA component of expense to be minimal. In 1998 the PCA expense increased $28 million because our 1998 power supply costs were well below the forecast, when 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 were significantly better than normal. We discuss the PCA in more detail in "Regulatory Issues - - Power Cost Adjustment." The impact of these changes in net power supply costs is a decrease in net expense in 1999 of $6 million and an increase in net expense in 1998 of $35 million. Other Expenses Other operations expenses increased $6 million in 1999 and $8 million in 1998. The increase in 1999 was due primarily to increased operating expenses at our coal-fired generation plants, and payroll and consulting expenses. The increase in 1998 was due primarily to increases in payroll and benefits and transmission charges for electricity sales. Maintenance expenses decreased $7 million in 1998, resulting from decreased cost of maintenance work performed at our steam generation and distribution facilities. Depreciation expenses increased $3 million in both 1998 and 1999, due primarily to plant additions. Other Income Energy marketing income increased $14 million in 1999 and $5 million in 1998 due primarily to improved results and increased volumes of energy trading activities. We discuss our energy marketing activities more fully below in "Energy Marketing." Other-net decreased $3 million in 1999 and $5 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. LIQUIDITY AND CAPITAL RESOURCES Cash Flow Our net cash generated from operations totaled $572 million for the three-year period 1997-1999. After deducting common dividends of $210 million, net cash generation from operations provided approximately $362 million for our construction program and other capital requirements. Internal cash generation after dividends provided 114 percent of our total capital requirements in 1999, 95 percent in 1998, and 89 percent in 1997. The $88 million increase in cash and cash equivalents in 1999 is due primarily to IPC's issuance of $80 million of medium-term notes late in 1999. The proceeds were used in January 2000 to retire $80 million of first mortgage bonds that had matured. In 1998, our increase in cash and cash equivalents was due primarily to $12 million received from life insurance death benefits and the surrender of life insurance policies. We forecast that internal cash generation after dividends will provide approximately 84 percent of total capital requirements in 2000 and over 110 percent during the four-year period 2001-2004. 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 next five years are $89 million in 2000, $40 million in 2001, $37 million in 2002, $90 million in 2003 and $60 million in 2004. At January 1, 2000, IPC had regulatory authority to incur up to $200 million of short-term indebtedness. At December 31, 1999, IPC's short-term borrowing totaled $20 million compared to $39 million at December 31, 1998 and $58 million at December 31, 1997. We have credit facilities established at both IPC and IDACORP. IPC has a $120 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. 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 million maximum, and is supported by bank lines of credit of an equal amount. IDACORP has separately established a $50 million three-year credit facility that expires in December 2001, and a $100 million 364-day credit facility that expires in December 2000. Under these facilities we 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 the $150 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 $111 million in 1999, $89 million in 1998, and $96 million in 1997. Approximately 28 percent of these expenditures were for generation facilities, 17 percent for transmission facilities, 39 percent for distribution facilities, and 16 percent for general plant and equipment. We estimate that our cash construction program will require $121 million in 2000 and $460 million in the four-year period 2001-2004. 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 45 percent, preferred stock (of IPC) 6 percent, and long-term debt 49 percent at December 31, 1999. IDACORP, Inc. currently has a $300 million shelf registration statement that can be used for the issuance of unsecured debt securities and preferred or common stock. At December 31, 1999 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. The remaining balance on the shelf registration is $3 million as of December 31, 1999. In November 1999 IPC issued $80 million of Secured Medium Term Notes. The proceeds from this issuance were used in January 2000 to redeem at maturity $80 million of First Mortgage Bonds. 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. OTHER MATTERS 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 in mid-May, are based on two components, the difference between our forecast of the upcoming year's net power supply costs and a base amount, and the true-up of the prior year's forecasted costs to actual costs. Our May 1999 rate adjustment reduced Idaho general business customer rates by 9.2 percent. The decrease was the result of forecasted above-average hydroelectric generating conditions for the upcoming year, and a true-up benefit from the 1998-99 rate period. Overall, the May 1999 rate adjustment is expected to decrease our annual general business revenue by $40 million during the 1999-2000 rate period. The May 1998 rate adjustment increased expected annual revenue by $34 million over the amount that would have been received at the 1997-98 rates. The 1998-99 forecast had assumed a return to more normal hydroelectric generating conditions from the above-average conditions experienced in the prior year. This resulted in forecasted power supply costs being near the amounts used to establish base rates in past regulatory proceedings. So far in the 1999-2000 rate period, actual power costs and generating conditions have been near forecast. We have recorded a regulatory asset of $1.7 million as of December 31, 1999. The variance that exists at the end of the 1999-2000 rate period will be trued-up in the next annual PCA adjustment. Regulatory Settlement IPC had a settlement agreement with the IPUC that expired at the end of 1999. Under the terms of the settlement, when earnings in our Idaho jurisdiction exceeded an 11.75 percent return on year- end common equity, we set aside 50 percent of the excess for the benefit of our Idaho retail customers. In 1999, we set aside approximately $8.9 million for this purpose, compared to $6.4 million in 1998 and $7.6 million in 1997. Demand-Side Management (Conservation) Expenses We have obtained changes to the regulatory treatment of previously deferred demand-side management (DSM) expenses. The IPUC set a new amortization period of 12 years instead of the 24- year period previously established. The order reflects an increase in annual Idaho retail revenue requirements of $3.1 million for 12 years. This order was appealed to the Idaho Supreme Court by a group of IPC customers; oral arguments were heard on December 8, 1999 and the matter is awaiting a Supreme Court decision. Energy Marketing Over the last three years we have been implementing a strategy to become a competitive energy provider throughout the western markets. In order to compete as an energy provider of choice we needed to build a foundation of an effective and efficient trading operation that competently participates in the electricity, natural gas and other related markets. In 1997 we opened natural gas trading operations in Houston, Texas and in Boise, Idaho. We also began to expand our electricity marketing, which, along with natural gas, is included in other income. We have seen increasing positive results from our strategy. Our natural gas marketing capability continues to expand as the electricity and natural gas markets move toward convergence, and our electricity marketing efforts have resulted in volume and income increases each year since inception of the strategy. We have built this capability over the last three years to allow us to develop controls to mitigate the operational, market and credit risks inherent in the marketing business. 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 manage these risks while implementing our business strategy, the Company has a Risk Management Committee, comprised of Company officers, to oversee the risk management program as defined in the risk management policy. The program is intended to minimize fluctuations in earnings while managing the volatility of energy prices by mitigating commodity price risk, credit risk, and other risks related to the energy trading business Ida-West Energy Company In March 2000, Ida-West Energy Company, a wholly owned subsidiary of IDACORP, sold for cash its interest in the Hermiston Power Project, a 536 MW, gas-fired cogeneration project to be located near Hermiston, Oregon. Ida-West was responsible for managing all permitting and development activities relating to the project since its inception in 1993. We anticipate recording a pre-tax gain of approximately $14 million on this transaction. Northwest Power Systems In March 1999 IDACORP Technologies, Inc., a wholly owned subsidiary of IDACORP, purchased a majority interest in Northwest Power Systems (NPS). 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. Fully operational prototypes have been constructed and successfully tested. NPS' focus will be the development, production and distribution of fully integrated fuel-cell systems. 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. Although the committee will continue studying a variety of restructuring ideas, it has not recommended any restructuring legislation and is not expected to in the foreseeable future. In 1999, the Oregon legislature passed legislation restructuring the electric utility industry, but exempted IPC's service territory. FERC Decisions In December 1999 the FERC issued Order No. 2000, dealing with Regional Transmission Organizations (RTO). It proposes to ensure non-discriminatory, open-access to electricity transmission facilities. Each utility is required to file by October 15, 2000 a statement regarding its intention to join a RTO. IPC is engaged in formation discussions with other Northwest utilities. These utilities include both investor-owned and other entities. IPC believes the FERC Order will allow sufficient flexibility to adequately protect the interests of both shareholders and customers. In April 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 implemented 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. 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 we held at December 31, 1999. We buy and sell 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, forwards, options and swaps as a method of managing the commodity price risk and optimizing the profitability of our 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, 1999 is immaterial. Interest Rate Risk Sensitivity This table presents descriptions of our financial instruments at December 31, 1999, that are sensitive to changes in interest rates. We did not hold any interest rate derivative instruments at December 31, 1999. The majority of our debt is held in fixed rate securities with embedded call options. We hold $48 million in variable-rate tax-exempt debt for pollution control financings and 2.1 percent of our total debt is variable in the form of commercial paper. By nature, the value of our variable rate debt is not sensitive to changes in interest rates, and the value of our commercial paper borrowings does 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, 1999, based on market rates for similar instruments as of that date. Expected Maturity Date 2000 2001 2002 2003 2004 Thereafter Total Fair Value Fixed rate debt (in millions) $ 89 $ 40 $ 37 $ 90 $ 60 $548 $864 $850 Average interest rate 8.5% 7.0% 7.0% 6.5% 7.9% 7.7% 7.6% Commodity Price Risk Sensitivity This analysis presents the estimated December 31, 1999, 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, forwards, options and swaps to manage our exposure to commodity price risk in the electricity and natural gas markets. The objective of our risk management 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 daily loss in earnings from our energy trading activity is estimated to be $115,000 at a 95 percent confidence interval and for a holding period of one business day. The potential loss in earnings was estimated using an analytic value-at-risk methodology. This methodology computes value-at- risk based upon market prices for futures and option-implied volatilities as of December 31, 1999. The value-at-risk is understood to be a forecast and is not guaranteed to occur. The chosen confidence level and holding period are industry standards. The confidence level and holding period imply that there is a five percent chance that the daily loss will exceed $115,000. 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, CJ 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, 1999, $20 million of relicensing costs were included in Construction Work in Progress. Environmental Issues Salmon Recovery Plan We are continuing to monitor regional efforts to develop 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. This designation has not had 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 1995, the National Marine Fisheries Service (NMFS) released a draft Biological Opinion and five-year operating plan to protect listed Snake River Salmon. The NMFS accepted public comment on the Plan through December 1995. The final five-year Plan did not call for any change in the Company's operations for salmon at the Hells Canyon Complex. The Biological Opinion did call for a five-year study of various recovery options for the listed fish including the possible removal of four federally owned hydro facilities on the lower Snake River. As the five- year operating plan comes to a close, NMFS is expected to announce the results of the studies and propose a new operating plan in the near future. It is unknown whether any change in operations at the Hells Canyon Complex will be requested as a result of the studies. 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. 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 our operations. Year 2000 Costs We have not experienced any significant operational issues resulting from the Year 2000 problem. Our total costs through the end of 1999 were $3.7 million charged to operations and maintenance expenses and $0.5 million of capital expenditures. We do not anticipate any material expenditures or issues to arise in the future. 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 was originally effective for fiscal years beginning after June 15, 1999. In June 1999 the FASB issued SFAS No. 137 "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Standard No. 133," which defers the effective date of SFAS No. 133 one year. We are reviewing this statement to determine its effect on our financial position and results of operations. 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 34 Consolidated Financial Statements: IDACORP, Inc. Consolidated Statements of Income for the Years Ended December 31, 1999, 1998 and 1997 35 Consolidated Balance Sheets as of December 31, 1999, 1998 and 1997 36-37 Consolidated Statements of Capitalization as of December 31, 1999, 1998 and 1997 38 Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997 39 Consolidated Statements of Retained Earnings and Consolidated Statements of Comprehensive Income for the Years Ended December 31, 1999, 1998 and 1997 40 Notes to Consolidated Financial Statements 41-54 Independent Auditors' Report 55 Idaho Power Company Consolidated Statements of Income for the Years Ended December 31, 1999, 1998 and 1997 57 Consolidated Balance Sheets as of December 31, 1999, 1998 and 1997 58-59 Consolidated Statements of Capitalization as of December 31, 1999, 1998 and 1997 60 Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997 61 Consolidated Statements of Retained Earnings and Consolidated Statements of Comprehensive Income for the Years Ended December 31, 1999,1998 and 1997 62 Notes to Consolidated Financial Statements 63-66 Independent Auditors' Report 67 Supplemental Financial Information and Financial Statement Schedules Supplemental Financial Information (Unaudited) 68 Financial Statement Schedules for the Years Ended December 31, 1999, 1998 and 1997: Schedule II-Consolidated Valuation and Qualifying Accounts- IDACORP, Inc. 74 Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho Power Company. 74 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, meets 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. Jan B. Packwood J. LaMont Keen Darrel T. Anderson President and Senior Vice President, Vice President, Chief Executive Officer Administration and Finance and Treasurer Chief Financial Officer IDACORP, Inc. Consolidated Statements of Income Year Ended December 31, 1999 1998 1997 (Thousands of Dollars except for per share amounts) REVENUES: General business $516,148 $514,856 $480,458 Off system sales 119,785 214,418 100,554 Other revenues 22,403 27,136 24,171 Total revenues 658,336 756,410 605,183 EXPENSES: Operations: Purchased power 106,344 185,271 79,898 Fuel expense 86,617 86,237 71,271 Power cost adjustment (502) 21,866 (6,032) Other 151,800 145,374 137,458 Maintenance 42,067 41,872 48,722 Depreciation 77,833 74,481 71,973 Taxes other than income taxes 21,719 20,725 21,162 Total expenses 485,878 575,826 424,452 INCOME FROM OPERATIONS 172,458 180,584 180,731 OTHER INCOME: Allowance for equity funds used during construction 1,667 300 34 Energy marketing activities - Net 21,739 7,429 2,837 Other - Net 8,312 10,928 15,402 Total other income 31,718 18,657 18,273 INTEREST EXPENSE AND OTHER: Interest on long-term debt 54,294 52,270 53,215 Other interest 8,681 8,407 7,546 Allowance for borrowed funds used during construction (1,392) (900) (503) Preferred dividends of Idaho Power Company 5,572 5,658 5,176 Total interest expense and other 67,155 65,435 65,434 INCOME BEFORE INCOME TAXES 137,021 133,806 133,570 INCOME TAXES 45,672 44,630 46,472 NET INCOME $ 91,349 $ 89,176 $ 87,098 AVERAGE COMMON SHARES OUTSTANDING (000) 37,612 37,612 37,612 EARNINGS PER SHARE OF COMMON STOCK (basic and diluted) $ 2.43 $ 2.37 $ 2.32 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Assets December 31, 1999 1998 1997 (Thousands of Dollars) ELECTRIC PLANT: In service (at original cost) $2,726,026 $2,659,441 $2,605,697 Accumulated provision for depreciation (1,073,722) (1,009,387) (942,400) In service - Net 1,652,304 1,650,054 1,663,297 Construction work in progress 91,637 59,717 51,892 Held for future use 1,742 1,738 1,738 Electric plant - Net 1,745,683 1,711,509 1,716,927 INVESTMENTS AND OTHER PROPERTY 146,019 129,437 97,065 CURRENT ASSETS: Cash and cash equivalents 111,338 22,867 6,905 Receivables: Customer 98,923 102,671 105,204 Allowance for uncollectible accounts (1,397) (1,397) (1,397) Notes 4,353 4,643 4,613 Employee notes 4,105 4,510 4,757 Other 7,764 6,059 8,854 Energy marketing assets 37,398 - - Accrued unbilled revenues 31,994 34,610 33,312 Materials and supplies (at average cost) 29,611 30,157 29,156 Fuel stock (at average cost) 9,329 7,096 7,172 Prepayments 16,097 16,042 15,381 Regulatory assets associated with income taxes 893 2,965 3,164 Total current assets 350,408 230,223 217,121 DEFERRED DEBITS: American Falls and Milner water rights 31,585 31,830 32,055 Company-owned life insurance 40,480 35,149 51,915 Regulatory assets associated with income taxes 214,782 201,465 198,521 Regulatory assets - other 52,759 62,013 90,239 Other 55,277 49,994 47,973 Total deferred debits 394,883 380,451 420,703 TOTAL $2,636,993 $2,451,620 $2,451,816 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets Capitalization and Liabilities December 31, 1999 1998 1997 (Thousands of Dollars) CAPITALIZATION: Common stock equity: Common stock without par value (shares authorized 120,000,000; shares outstanding - 37,612,351) $ 451,343 451,564 452,519 Retained earnings 300,093 278,607 259,299 Accumulated other comprehensive income 1,534 226 - Total common stock 752,970 730,397 711,818 equity Preferred stock of Idaho Power Company 105,811 105,968 106,697 Long-term debt 821,558 815,937 746,142 Total capitalization 1,680,339 1,652,302 1,564,657 CURRENT LIABILITIES: Long-term debt due within one year 89,101 6,029 33,998 Notes payable 19,757 38,524 57,516 Accounts payable 145,737 101,975 111,938 Energy marketing liabilities 33,814 - - Taxes accrued 21,313 24,785 24,295 Interest accrued 19,126 18,365 17,918 Deferred income taxes 893 2,965 3,164 Other 16,696 12,275 13,703 Total current liabilities 346,437 204,918 262,532 DEFERRED CREDITS: Regulatory liabilities associated with deferred investment tax credits 67,433 69,396 70,196 Deferred income taxes 430,468 422,196 423,736 Regulatory liabilities associated with income taxes 33,817 28,075 34,072 Regulatory liabilities - other 3,363 4,161 509 Other 75,136 70,572 96,114 Total deferred credits 610,217 594,400 624,627 COMMITMENTS AND CONTINGENT LIABILITIES TOTAL $2,636,993 $2,451,620 $2,451,816 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Capitalization December 31, 1999 % 1998 % 1997 % (Thousands of Dollars) COMMON STOCK EQUITY: Common stock $ 451,343 $ 451,564 $ 452,519 Retained earnings 300,093 278,607 259,299 Accumulated other comprehensive income 1,534 226 - Total common stock equity 752,970 45 730,397 44 711,818 45 PREFERRED STOCK OF IDAHO POWER COMPANY: 4% preferred stock 15,811 15,968 16,697 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 105,811 6 105,968 7 106,697 7 LONG-TERM DEBT : First mortgage bonds: 5.33% Series due 1998 - - 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 60,000 - 7.20% Series due 2009 80,000 - - Maturing 2021 through 2031 with rates ranging from 7.5% to 9.52% 230,000 230,000 230,000 Total first mortgage bonds 637,000 557,000 527,000 Amount due within one year (80,000) - (30,000) Net first mortgage bonds 557,000 557,000 497,000 Pollution control revenue bonds: 7.25 % 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 1,415 1,489 1,561 Amount due within one year (76) (74) (72) Net REA notes 1,339 1,415 1,489 American Falls bond guarantee 19,885 20,130 20,355 Milner Dam note guarantee 11,700 11,700 11,700 Debt related to investments in affordable housing with rates ranging from 6.03% to 8.77% due 2000 to 2010 71,183 62,103 46,385 Amount due within one year (9,025) (5,955) (3,926) Net affordable housing debt 62,158 56,148 42,459 Unamortized premium/discount - Net (1,441) (1,539) (1,637) Net Idaho Power Company debt 821,101 815,314 741,826 Other subsidiary debt 457 623 4,316 Total long-term debt 821,558 49 815,937 49 746,142 48 TOTAL CAPITALIZATION $1,680,339 100 $1,652,302 100 $1,564,657 100 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Cash Flows Year Ended December 31, 1999 1998 1997 (Thousands of Dollars) OPERATING ACTIVITIES: Net income $ 91,349 $ 89,176 $ 87,098 Adjustments to reconcile net income to net cash provided by operating activities: Unrealized gains from energy marketing activities (3,584) - - Depreciation and amortization 95,436 87,143 80,485 Deferred taxes and investment tax credits (1,820) (10,182) 5,978 Accrued PCA costs (891) 21,658 (7,038) Change in: Accounts receivable and prepayments 2,683 4,883 (69,589) Accrued unbilled revenue 2,616 (1,298) (5,603) Materials and supplies and fuel stock (1,687) (925) (57) Accounts payable 43,762 (9,963) 75,731 Taxes accrued (3,472) 489 6,991 Other current assets and liabilities 5,182 (825) 3,296 Other - net 1,014 (10,269) (5,562) Net cash provided by operating activities 230,588 169,887 171,730 INVESTING ACTIVITIES: Additions to utility plant (110,974) (89,184) (95,633) Investments in affordable housing projects (19,554) (19,139) (17,021) Investments in company - owned life insurance (5,862) - - Other - net (5,060) 3,206 (1,302) Net cash used in investing activities (141,450) (105,117) (113,956) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 80,000 60,000 - Long-term debt related to affordable housing projects 18,730 20,556 12,984 Retirement of: Subsidiary long-term debt (165) (4,316) (4,700) Long-term debt related to affordable housing projects (9,650) (4,838) - First mortgage bonds - (30,000) - Dividends on common stock (69,863) (69,868) (69,887) Increase (decrease) in short- term borrowings (18,767) (18,992) 3,500 Other - net (952) (1,350) (694) Net cash used in financing activities (667) (48,808) (58,797) Net increase (decrease) in cash and cash equivalents 88,471 15,962 (1,023) Cash and cash equivalents at beginning of period 22,867 6,905 7,928 Cash and cash equivalents at end of period $111,338 $ 22,867 6,905 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Income taxes $ 51,750 $ 55,527 41,786 Interest (net of amount capitalized) $ 56,295 $ 53,806 53,319 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Retained Earnings Year Ended December 31, 1999 1998 1997 (Thousands of Dollars) RETAINED EARNINGS, BEGINNING OF YEAR $278,607 $259,299 $242,088 NET INCOME 91,349 89,176 87,098 Total 369,956 348,475 329,186 COMMON STOCK DIVIDENDS (69,863) (69,868) (69,887) RETAINED EARNINGS, END OF YEAR $300,093 $278,607 $259,299 The accompanying notes are an integral part of these statements. Consolidated Statements of Comprehensive Income Year Ended December 31, 1999 1998 1997 (Thousands of Dollars) NET INCOME $ 91,349 $ 89,176 $ 87,098 OTHER COMPREHENSIVE INCOME: Unrealized gains on securities (net of tax of $677 and $2,185) 1,017 3,385 - Minimum pension liability adjustment (net of tax of $189 and ($2,054)) 291 (3,159) - TOTAL COMPREHENSIVE INCOME $ 92,657 $ 89,402 $ 87,098 The accompanying notes are an integral part of these statements IDACORP, Inc. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Nature of Business IDACORP, Inc. (IDACORP or the Company) is a holding company whose principal operating subsidiary is Idaho Power Company (IPC). On October 1, 1998, IPC's outstanding common stock was converted on a share-for-share basis into common stock of IDACORP. However, IPC's preferred stock and debt securities outstanding were unaffected and remain with IPC. IPC, a public utility, represents over 90% of the consolidated total assets of the Company and is its principal operating subsidiary. IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho, Oregon, Nevada and Wyoming, and is engaged in the generation, transmission, distribution, sale and purchase of electric energy. 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 1999, 1998 and 1997 were 7.8 percent, 6.0 percent, and 5.8 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. IPC had a regulatory settlement with the Idaho Public Utilities Commission (IPUC) that expired in 1999. Under terms of the settlement, when earnings in the Idaho jurisdiction exceeded an 11.75 percent return on year-end common equity, 50 percent of the excess was set aside for the benefit of IPC's Idaho retail customers. In 1999, 1998 and 1997, approximately $8.9 million, $6.4 million, and $7.6 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 at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable electric plant in service approximated 2.94 percent in 1999, 2.87 percent in 1998, and 2.93 percent in 1997. 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 computed using book lives 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. 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. 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. In 1997, the Idaho Legislature appointed a committee to study restructuring of the electric utility industry. Although the committee will continue studying a variety of restructuring ideas, it has not recommended any restructuring legislation and is not expected to in the foreseeable future. In 1999, the Oregon legislature passed legislation restructuring the electric utility industry, but exempted IPC's service territory. 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 1999, 1998 and 1997: 1999 1998 1997 Assets Liabilities Assets Liabilities Assets Liabilities (Millions of Dollars) Income taxes $215.7 $ 33.8 $204.4 $ 28.1 $201.7 $ 34.1 Conservation 37.5 - 43.3 - 42.4 - Employee benefits 4.7 - 5.6 - 6.5 - PCA deferral and amortization (3.4) - (5.2) - 16.6 - Other 13.9 3.4 18.3 4.1 24.7 0.5 Deferred investment tax credits - 67.4 - 69.4 - 70.2 Total $268.4 $104.6 $266.4 $101.6 $291.9 $104.8 At December 31, 1999, IPC had $7.1 million of regulatory assets that were not earning a return on investment, excluding the $215.7 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 The Company uses financial instruments such as commodity futures, forwards, options and swaps to manage exposure to commodity price risk in the electricity and natural gas markets. The objective of the Company's risk management program is to mitigate the risk associated with the purchase and sale of natural gas and electricity as well as to optimize its energy marketing portfolio. 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 Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading Activities". EITF 98-10 was adopted effective January 1, 1999 resulting in an adjustment to net income that was not material. Related to the adoption of EITF 98-10, the Company has begun reporting electricity trading activity net on the Consolidated Statements of Income. Prior years have been reclassified to conform with the current year's presentation. Energy trading contracts as defined by EITF 98-10 are reported at fair value on the balance sheet with the resulting gains and losses reported on the income statement. Cash flows from energy trading contracts are recognized in the statement of cash flows as an operating activity. The following table shows a summary of the notional amounts of the Company's forward exposure as of December 31, 1999. The maximum term related to any of our forward positions is two years. 1999 Gas Electricity MMBTU's MWh's Payable 38,421 4,739 Receivable 49,040 6,079 Swaps 25,052 - The following table displays the fair values of the Company's energy marketing assets and liabilities at December 31, 1999, and the average values for the year ended December 31, 1999 (in thousands of dollars): 1999 End of Year Balance 1999 Average Balance Assets Liabilities Assets liabilities (Thousands of Dollars) Gas $ 8,302 $ 8,220 $14,173 $11,710 Electriciy 29,096 25,594 40,450 43,320 Total $37,398 $33,814 $54,623 $55,030 The gain in fair value of energy trading contract positions (including electricity and natural gas forwards, futures, options and swaps) included in income before income taxes for the year ended December 31, 1999 was $21.7 million. Notional amounts listed above reflect the volume of energy related to transactions with counterparties, but do not measure exposure to market or credit risks. The maximum term detailed above also is not indicative of likely future cash flows as positions may be offset in the markets at any time to meet risk management guidelines. Comprehensive Income 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 FASB issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." This statement establishes accounting and reporting standards for derivative financial instruments and other similar instruments and for hedging activities. It was originally effective for fiscal years beginning after June 15, 1999. In June 1999 the FASB issued SFAS No. 137 "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Standard No. 133", which defers the effective date of SFAS No. 133 one year. The Company is reviewing SFAS No. 133 to determine its effects on the Company's financial position and results of operations. 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 1999 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: 1999 1998 1997 (Thousands of Dollars) Computed income taxes based on statutory federal income tax rate $ 47,957 $ 46,832 $ 46,750 Change in taxes resulting from: Investment tax credits (3,032) (2,934) (2,887) Repair allowance (2,800) (2,800) (2,800) Settlement of prior years tax returns (380) (1,965) 23 Current state income taxes 6,024 6,258 3,587 Depreciation 7,292 5,237 5,766 Affordable housing tax credits (9,529) (6,880) (4,519) Preferred dividends of IPC 1,950 1,980 1,811 Other (1,810) (1,098) (1,259) Total provision for federal and state income taxes $ 45,672 44,630 46,472 Effective tax rate 33.3% 33.4% 34.8% The provision for income taxes consists of the following: 1999 1998 1997 (Thousands of Dollars) Income taxes currently payable: Federal $ 38,165 $ 45,606 $ 35,038 State 9,327 9,206 5,456 Total 47,492 54,812 40,494 Income taxes deferred - Net of amortization: Federal 2,174 (8,006) 6,717 State (2,031) (1,376) 348 Total 143 (9,382) 7,065 Investment tax credits: Deferred 1,069 2,134 1,800 Restored (3,032) (2,934) (2,887) Total (1,963) (800) (1,087) Total provision for income taxes $ 45,672 $ 44,630 $ 46,472 The tax effects of significant items comprising the Company's net deferred tax liability are as follows: 1999 1998 1997 (Thousands of Dollars) Deferred tax assets: Regulatory liabilities $ 33,817 $ 28,075 $ 34,072 Advances for construction 9,646 10,401 18,665 Other 19,019 20,512 16,536 Total 62,482 58,988 69,273 Deferred tax liabilities: Electric plant 249,597 247,270 251,938 Regulatory assets 215,675 204,430 201,685 Conservation programs 17,396 16,866 14,377 Other 11,175 15,583 28,173 Total 493,843 484,149 496,173 Net deferred tax liabilities $431,361 $425,161 $426,900 3. COMMON STOCK: Changes in shares of IDACORP common stock for 1999, 1998 and 1997 were as follows: Shares Amount (Thousands of Dollars) 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 Other - Net - (221) Balance at December 31, 1999 37,612,351 $ 451,343 As of December 31, 1999; 3,791,321 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, 1999, 1998 and 1997 were as follows: Shares Outstanding at December 31, Call Price 1999 1998 1997 Per Share Preferred stock: Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 158,112 159,680 166,972 $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 558,612 560,180 567,472 (a) The preferred stock is not redeemable prior to July 1, 2003. (b) Dividend rate at December 31, 1999 was 4.41% and ranged between 3.60% and 4.41% during the year. During 1999, 1998 and 1997 IPC reacquired and retired 1,568; 7,292; and 2,781 shares of 4% preferred stock. As of December 31, 1999, the overall effective cost of all outstanding preferred stock was 5.74 percent. 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, 1999, 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. First mortgage bonds maturing during the five-year period ending 2004 are $80.0 million in 2000, $30.0 million in 2001, $27.0 million in 2002, $80.0 million in 2003 and $50.0 in 2004. 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 November 23, 1999, $80.0 million principal amount of Secured Medium Term Notes, Series B, 7.20% Series due 2009 were issued by IPC. Proceeds from this issuance were used to redeem at maturity, the $80.0 million First Mortgage Bonds 8.65% Series due January 2000. At December 31, 1999, 1998 and 1997 the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 7.62 percent, 7.69 percent, and 7.84 percent, respectively. At December 31, 1999, IDACORP Financial Services, Inc., a wholly owned subsidiary of IPC, has $71.2 million of debt with interest rates ranging from 6.03 percent to 8.77 percent. This debt is collateralized by investments in affordable housing projects with a bookvalue of $80.5 million at December 31, 1999. Principal amounts maturing during the five-year period ending 2004 are $9.0 million in 2000, $9.7 million in 2001, $10.0 million in 2002, $9.6 million in 2003 and $9.6 million in 2004. 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 $898.1 million in 1999, $877.4 million in 1998 and $801.8 million in 1997. Included in investments and other property were financial instruments totaling $24.0 million in 1999, $14.2 million in 1998 and $16.5 million in 1997. Estimated fair value of these instruments was $30.6 million in 1999, $20.3 million in 1998 and $19.9 million in 1997. 7. NOTES PAYABLE: At December 31, 1999, IPC had regulatory authority to incur up to $200 million of short-term indebtedness. IPC has a $120 million multi-year revolving credit facility expiring in December 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 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, 1999 1998 1997 (Thousands of Dollars) Balance at end of year $19,757 $38,524 $57,516 Effective annual interest rate at end of year 6.1% 6.0% 6.1% IDACORP has separately established a $50 million three-year credit facility that expires in December 2001, and a $100 million 364-day credit facility that expires in December 2000. 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 million and is supported by the bank credit facilities. None of this debt is outstanding at December 31, 1999. 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 $8.6 million at December 31, 1999. 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 65 on-line cogeneration and small power production facilities with contracts ranging from 1 to 31 years. Under these contracts IPC is required to purchase all of the output from these facilities. During the fiscal year ended December 31, 1999, IPC purchased 931,797 (MWh) at a cost of $56.2 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 IDACORP has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee's final average earnings. The Company's policy is to fund with an independent corporate trustee at least the minimum required under the Employee Retirement Income Security Act of 1974 but not more than the maximum amount deductible for income tax purposes. The Company was not required to contribute to the plan in 1999, 1998 and 1997. The trustee invests the plan's assets primarily in listed stocks (both U.S. and foreign), fixed income securities and investment grade real estate. IDACORP has a nonqualified, deferred compensation plan for certain senior management employees and directors. The Company financed this plan by purchasing life insurance policies and investments in marketable securities all of which are 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 benefit cost for these plans (in thousands of dollars): Pension Plan Deferred Compensation Plan 1999 1998 1997 1999 1998 1997 Service cost $ 8,389 $ 7,133 $ 6,152 $ 744 $ 572 $ 515 Interest cost 16,402 15,458 14,445 1,797 1,747 1,731 Expected return on assets (25,240) (22,724) (20,248) - - - Recognized net actuarial (gain) loss (344) (111) - 279 255 222 Amortization of prior service cost 708 424 424 (325) (332) (346) Amortization of transition asset (263) (263) (263) 613 613 613 Net periodic pension cost $ (348) $ (83) $ 510 $ 3,108 $ 2,855 $ 2,735 The following table summarizes the changes in benefit obligation and plan assets of these plans (in thousands of dollars): Pension Plan Deferred Compensation Plan 1999 1998 1997 1999 1998 1997 Change in projected benefit obligation: Benefit obligation at January 1 $253,729 $224,073 $202,049 $ 27,029 $ 25,067 $ 24,122 Service cost 8,389 7,133 6,152 744 572 516 Interest cost 16,402 15,458 14,445 1,797 1,747 1,731 Actuarial loss (gain) (33,014) 14,139 12,763 (489) 1,297 806 Benefits paid (16,464) (11,774) (11,336) (2,201) (2,049) (2,303) Plan amendments - 4,700 - 45 395 195 Benefit obligation at December 31 229,042 253,729 224,073 26,925 27,029 25,067 Change in plan assets: Fair value at January 1 290,080 256,893 230,478 - - - Actual return on plan assets 66,905 44,961 37,751 - - - Employer contributions - - - - - - Benefit payments (16,464) (11,774) (11,336) - - - Fair value at December 31 340,521 290,080 256,893 - - - Funded status 111,479 36,351 32,820 (26,925) (27,029) (25,067) Unrecognized actuarial loss/(gain) (108,057) (33,722) (25,734) 5,844 6,612 5,569 Unrecognized prior service cost 8,662 9,370 5,093 (796) (1,166) (1,893) Unrecognized net transition liability (1,441) (1,704) (1,967) 3,375 3,988 4,601 Net amount recognized $ 10,643 $ 10,295 $ 10,212 $(18,502)$(17,595)$(16,790) Amounts recognized in the statement of financial position consists of: Prepaid (accrued) pension cost $ 10,643 $ 10,295 $ 10,212 $(25,815)$(25,631)$(24,657) Intangible asset - - - 2,579 2,822 7,867 Accumulated other comprehensive income - - - 4,734 5,214 - Net amount recognized $ 10,643 $ 10,295 $ 10,212 $(18,502)$(17,595)$(16,790) 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 1999 1998 1997 1999 1998 1997 Discount rate 7.5 % 6.75 % 7.10 % 7.5 % 6.75 % 7.35 % 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 IDACORP has a restricted stock 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, 1999, there were 297,888 remaining shares of common stock available for issuance under the plan. Restricted stock awards are compensatory awards and the Company accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 1999, 1998 and 1997, total compensation accrued for the plan was $519,000, $567,000 and $539,000 respectively. The Company applies APB Opinion 25 and related interpretations in accounting for this plan. Had compensation cost for the grants of restricted stock been determined consistent with the optional fair value based method provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's net income and earnings per share of common stock for 1999, 1998 and 1997 would not be significantly different from such amounts as reported. The following table summarizes restricted stock activity for the years 1999, 1998 and 1997: 1999 1998 1997 Shares outstanding - beginning of year, 43,063 38,365 18,140 Shares granted 23,497 21,361 20,225 Shares forfeited (9,585) (4,063) - Shares issued (13,360) (12,600) - Shares outstanding - end of year 43,615 43,063 38,365 Weighted average fair value of current year stock grants on grant date $ 32.88 $ 37.00 $ 31.25 Savings Plan IDACORP has an Employee Savings Plan which complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. The Company matches specified percentages of employee contributions to the plan. Matching contributions amounted to $3.1 million in 1999, $3.0 million in 1998 and $2.4 million in 1997. Postretirement Benefits The Company maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement, their spouses and qualifying dependents. The net periodic postretirement benefit cost was as follows (in thousands of dollars): 1999 1998 1997 Service cost $ 896 $ 720 $ 713 Interest cost 2,867 2,913 3,029 Expected return on plan assets (2,230) (1,761) (1,511) Amortization of unrecognized 2,040 2,040 2,040 transition obligation Amortization of prior service cost (691) (280) (87) Amortization of unrecognized net gains - (220) (240) Net periodic post-retirement benefit cost $ 2,882 3,412 3,944 The following table summarizes the changes in benefit obligation and plan assets plan (in thousands of dollars): 1999 1998 1997 Change in accumulated benefit obligation: Benefit obligation at January 1 $38,615 $43,459 $44,439 Service cost 896 720 713 Interest cost 2,867 2,913 3,029 Plan amendments - (9,071) (1,214) Actuarial loss (gain) 1,859 3,483 (1,940) Benefits paid (3,098) (2,889) (1,568) Benefit obligation at December 31 41,139 38,615 43,459 Change in plan assets: Fair value of plan assets at January 1 24,346 19,493 17,341 Actual return on plan assets 2,389 4,853 2,152 Employer (excess) contributions 2,845 2,789 1,553 Benefits paid (2,775) (2,789) (1,553) Fair value of plan assets at December 31 26,805 24,346 19,493 Funded status (14,334) (14,269) (23,966) Unrecognized prior service cost (9,227) (9,918) (1,127) Unrecognized actuarial gain (5,556) (7,256) (7,867) Unrecognized transition obligation 26,520 28,560 30,600 Accrued benefit obligations included with other deferred credits $(2,597) $(2,883) $(2,360) 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- 1- Percentage- Percentage- Point Point increase decrease Effect on total of service and interest cost components $ 293 $ (239) Effect on accumulated post- retirement benefit obligation $2,421 $(2,058) 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 benefit amounts included in the Company's consolidated balance sheet (in thousands of dollars): 1999 1998 1997 Included with regulatory assets - other $ 1,889 $ 2,260 $ 2,632 Included with other deferred credits $(3,282) $(3,372) $(3,093) 10. ELECTRIC PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS: The following table sets out the major classifications of the IPC's electric plant in service, accumulated provision for depreciation and annual depreciation provisions as a percent of average depreciable balance for the years 1999, 1998 and 1997 (in thousands of dollars): 1999 1998 1997 Balance Avg Rate Balance Avg Rate Balance Avg Rate Production $1,348,531 2.60% $1,344,526 2.60% $1,333,768 2.60% Transmission 403,010 2.30 389,011 2.30 378,190 2.28 Distribution 786,488 3.37 736,527 3.15 715,091 3.38 General and Other 187,997 5.46 189,377 5.45 178,648 5.39 Total In Service 2,726,026 2.94% 2,659,441 2.87% 2,605,697 2.93% Less accumulated provision for depreciation 1,073,722 1,009,387 942,400 In Service - Net $1,652,304 $1,650,054 $1,663,297 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, 1999 are as follows: Company Ownership Accumulated Electric Provision Name of Plant Location Plant In for Service Depreciation % MW (Thousands of Dollars) Jim Bridger Rock Springs, $ 389,277 $ 198,393 33 708 Units 1-4 WY Boardman Boardman, OR 61,728 33,970 10 53 Valmy Units 1 Winnemucca, NV 300,449 139,101 50 261 and 2 IPC's wholly owned subsidiary, Idaho Energy Resources Company, 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 $41.9 million in 1999, $46.2 million in 1998 and $40.7 million in 1997. 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 $8.8 in 1999, $8.7 million in 1998 and $9.8 million in 1997. 11. INDUSTRY SEGMENT INFORMATION: The Company operates an electric utility involving the generation, transmission, distribution, purchase and sale of electricity. The Company's primary non-utility segments involve electricity and natural gas trading, independent power projects, energy-related products and services, renewable energy products, fuel-cell technology, and home security, internet and satellite television services. The following table summarizes the segment information for the Company's utility operations and the total of all other segments, and reconciles this information to total enterprise amounts: IPC Consolida ted Utility Other Total (Thousands of Dollars) 1999 Revenues $ 658,336 $ - $ 658,336 Income from operations 172,458 - 172,458 Other income 5,120 26,598 31,718 Interest expense 56,679 4,904 61,583 Income before income taxes 115,327 21,694 137,021 Income taxes 46,395 (723) 45,672 Net income 68,932 22,417 91,349 Total assets 2,355,907 281,086 2,636,993 Expenditures for long- lived assets 112,772 27,192 139,964 1998 Revenues $ 756,410 $ - $ 756,410 Income from operations 180,584 180,584 Other income 5,909 12,748 18,657 Interest expense 56,646 3,131 59,777 Income before income taxes 129,847 3,959 133,806 Income taxes 47,552 (2,922) 44,630 Net income 82,295 6,881 89,176 Total assets 2,251,077 200,543 2,451,620 Expenditures for long- lived assets 91,803 19,205 111,008 1997 Revenues $ 605,183 $ - $ 605,183 Income from operations 180,731 - 180,731 Other income 3,894 14,379 18,273 Interest expense 57,653 2,605 60,258 Income before income taxes 126,972 6,598 133,570 Income taxes 47,618 (1,146) 46,472 Net income 79,354 7,744 87,098 Total assets 2,272,752 179,064 2,451,816 Expenditures for long- lived assets 98,219 17,457 115,676 INDEPENDENT AUDITORS' REPORT To The Board of Directors and Shareowners 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, 1999, 1998 and 1997, and the related consolidated statements of income, cash flows, retained earnings and comprehensive income for the years then ended. Our audits also include 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, 1999, 1998 and 1997, 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 31, 2000 (This page intentionally left blank) Idaho Power Company Consolidated Statements of Income Year Ended December 31, 1999 1998 1997 (Thousands of Dollars) REVENUES: General business $516,148 $514,856 $480,458 Off system sales 119,785 214,418 100,554 Other revenues 22,403 27,136 24,171 Total revenues 658,336 756,410 605,183 EXPENSES: Operation: Purchased power 106,344 185,271 79,898 Fuel expense 86,617 86,237 71,271 Power cost adjustment (502) 21,866 (6,032) Other 151,800 145,374 137,458 Maintenance 42,067 41,872 48,722 Depreciation 77,833 74,481 71,973 Taxes other than income taxes 21,719 20,725 21,162 Total expenses 485,878 575,826 424,452 INCOME FROM OPERATIONS 172,458 180,584 180,731 OTHER INCOME: Allowance for equity funds used during construction 1,667 300 34 Energy marketing activities - Net 23,206 7,429 2,837 Other - Net 6,369 12,364 15,402 Total other income 31,242 20,093 18,273 INTEREST CHARGES: Interest on long-term debt 54,150 52,270 53,215 Other interest 7,864 8,323 7,546 Allowance for borrowed funds used during construction (1,392) (900) (503) Total interest charges 60,622 59,693 60,258 INCOME BEFORE INCOME TAXES 143,078 140,984 138,746 INCOME TAXES 45,550 45,065 46,472 NET INCOME 97,528 95,919 92,274 Dividends on preferred stock 5,572 5,658 5,176 EARNINGS ON COMMON STOCK $ 91,956 $ 90,261 $ 87,098 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Assets December 31, 1999 1998 1997 (Thousands of Dollars) ELECTRIC PLANT: In service (at original cost) $2,726,026 $2,659,441 $2,605,697 Accumulated provision for depreciation (1,073,722) (1,009,387) (942,400) In service - Net 1,652,304 1,650,054 1,663,297 Construction work in progress 88,348 58,904 51,892 Held for future use 1,742 1,738 1,738 Electric plant - Net 1,742,394 1,710,696 1,716,927 INVESTMENTS AND OTHER PROPERTY 117,759 105,600 97,065 CURRENT ASSETS: Cash and cash equivalents 95,038 20,029 6,905 Receivables: Customer 83,412 102,653 105,204 Allowance for uncollectible accounts (1,397) (1,397) (1,397) Notes 345 467 4,613 Employee notes 4,105 4,510 4,757 Related parties 195 3,164 - Other 7,095 5,338 8,854 Energy marketing assets 29,096 - - Accrued unbilled revenues 31,994 34,610 33,312 Materials and supplies (at average cost) 28,960 30,143 29,156 Fuel stock (at average cost) 9,329 7,096 7,172 Prepayments 16,054 16,011 15,381 Regulatory assets associated with income taxes 893 2,965 3,164 Total current assets 305,119 225,589 217,121 DEFERRED DEBITS: American Falls and Milner water rights 31,585 1,830 32,055 Company-owned life insurance 40,480 35,149 51,915 Regulatory assets associated with income taxes 214,782 201,465 198,521 Regulatory assets - other 52,759 62,013 90,239 Other 54,496 49,448 47,973 Total deferred debits 394,102 379,905 420,703 TOTAL $2,559,374 $2,421,790 $2,451,816 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Capitalization and Liabilities December 31, 1999 1998 1997 (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 362,203 362,156 362,328 Capital stock expense (3,819) (3,823) (3,840) Retained earnings 274,181 252,137 259,299 Accumulated other comprehensive income 1,534 226 - Total common stock equity 728,130 704,727 711,818 Preferred stock 105,811 105,968 106,697 Long-term debt 821,558 815,937 746,142 Total capitalization 1,655,499 1,626,632 1,564,657 CURRENT LIABILITIES: Long-term debt due within one year 89,101 6,029 33,998 Notes payable 19,757 38,508 57,516 Accounts payable 95,125 101,108 111,938 Notes and accounts payable to related parties 10,076 28 - Energy marketing liabilities 25,594 - - Taxes accrued 21,773 25,164 24,295 Interest accrued 19,122 18,364 17,918 Deferred income taxes 893 2,965 3,164 Other 16,069 12,117 13,703 Total current liabilities 297,510 204,283 262,532 DEFERRED CREDITS: Regulatory liabilities associated with deferred investment tax credits 67,433 69,396 70,196 Deferred income taxes 428,923 420,268 423,736 Regulatory liabilities associated with income taxe 33,817 28,075 34,072 Regulatory liabilities - other 3,363 4,161 509 Other 72,829 68,975 96,114 Total deferred credits 606,365 590,875 624,627 COMMITMENTS AND CONTINGENT LIABILITIES TOTAL $2,559,374 $2,421,790 $2,451,816 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Capitalization December 31, 1999 % 1998 % 1997 % (Thousands of Dollars) COMMON STOCK EQUITY Common stock $ 94,031 $ 94,031 $ 94,031 Premium on capital stock 362,203 362,156 362,328 Capital stock expense (3,819) (3,823) (3,840) Retained earnings 274,181 252,137 259,299 Accumulated other comprehensive income 1,534 226 - Total common stock equity 728,130 44 704,727 43 711,818 45 PREFERRED STOCK 4% preferred stock 15,811 15,968 16,697 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 105,811 6 105,968 7 106,697 7 LONG-TERM DEBT First mortgage bonds: 5.33 %Series due 1998 - - 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 60,000 - 7.20 % Series due 2009 80,000 - - Maturing 2021 through 2031 with rates ranging from 7.5% to 9.52% 230,000 230,000 230,000 Total first mortgage bonds 637,000 557,000 527,000 Amount due within one year (80,000) - (30,000) Net first mortgage bonds 557,000 557,000 497,000 Pollution control revenue bonds: 7.25%Series due 2008 4,360 4,360 4,360 8.30%Series 1984 due 49,800 49,800 49,800 2014 6.05%Series 1996A due 68,100 68,100 68,100 2026 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 1,415 1,489 1,561 Amount due within one year (76) (74) (72) Net REA notes 1,339 1,415 1,489 American Falls bond guarantee 19,885 20,130 20,355 Milner Dam note guarantee 11,700 11,700 11,700 Debt related to investments in affordable housing with rates ranging from 6.03% to 8.77% due 2000 to 2010 71,183 62,103 46,385 Amount due within one year (9,025) (5,955) (3,926) Net affordable housing debt 62,158 56,148 42,459 Other subsidiary debt 457 623 4,316 Unamortized premium/discount - Net (1,441) (1,539) (1,637) Total long-term debt 821,558 50 815,937 50 746,142 48 TOTAL CAPITALIZATION $1,655,499 100 $1,626,632 100 $1,564,657 100 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Cash Flows Year Ended December 31, 1999 1998 1997 (Thousands of Dollars) OPERATING ACTIVITIES: Net income $ 97,528 $ 95,919 $ 92,274 Adjustments to reconcile net income to net cash: Unrealized gains from energy marketing activities (3,502) - - Depreciation & amortization 95,154 87,044 80,485 Deferred taxes and investment tax credits (1,747) (10,127) 5,978 Accrued PCA costs (891) 21,658 (7,038) Change in: Accounts receivable and prepayments (489) 1,985 (69,589) Accrued unbilled revenue 2,616 (1,298) (5,603) Materials and supplies and fuel stock (1,050) (911) (57) Accounts payable 28,397 (10,658) 75,731 Taxes accrued (3,391) 1,312 6,991 Other current assets and liabilities 4,710 (857) 3,296 Other - net (3,490) (10,340) (5,562) Net cash provided by operating activities 213,845 173,727 176,906 INVESTING ACTIVITIES: Additions to utility plant (108,498) (89,644) (95,633) Investments in affordable housing projects (19,554) (19,139) (17,021) Investments in company - owned life insurance (5,862) - - Other - net (3,066) 867 (1,302) Net cash used in investing activities (136,980) (107,916) (113,956) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 80,000 60,000 - Long-term debt related to affordable housing projects 18,730 20,556 12,984 Retirement of: Subsidiary long-term debt (165) (3,316) (4,700) Long-term debt related to affordable housing projects (9,650) (4,838) - First mortgage bonds - (30,000) - Dividends on common stock (69,912) (69,889) (69,887) Dividends on preferred stock (5,572) (5,658) (5,176) Increase (decrease) in short- term borrowings (14,607) (18,992) 3,500 Other - net (680) (550) (694) Net cash used in financing activities (1,856) (52,687) (63,973) Net increase (decrease) in cash and cash equivalents 75,009 13,124 (1,023) Cash and cash equivalents at beginning of period 20,029 6,905 7,928 Cash and cash equivalents at end of period $ 95,038 $ 20,029 $ 6,905 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Income taxes $ 50,532 $ 55,527 $ 41,786 Interest (net of amount capitalized) $ 55,186 $ 53,806 $ 53,319 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, 1999 1998 1997 (Thousands of Dollars) RETAINED EARNINGS, BEGINNING OF YEAR $252,137 $259,299 $242,088 NET INCOME 97,528 95,919 92,274 Total 349,665 355,218 334,362 DIVIDENDS Common stock ($1.86 per share) (69,912) (69,889) (69,887) Preferred stock (5,572) (5,658) (5,176) TRANSFER TO IDACORP, INC. - (27,534) - RETAINED EARNINGS, END OF YEAR $274,181 $252,137 $259,299 The accompanying notes are an integral part of these statements. Consolidated Statements of Comprehensive Income Year Ended December 31, 1999 1998 1997 (Thousands of Dollars) NET INCOME $ 97,528 $ 95,919 $ 92,274 OTHER COMPREHENSIVE INCOME: Unrealized gains on securities (net of tax of $677 and $2,185) 1,017 3,385 - Minimum pension liability adjustment (net of tax of $189 and( $2,054)) 291 (3,159) - TOTAL COMPREHENSIVE INCOME $ 98,836 $ 96,145 $ 92,274 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 subsidiaries (IPC). At that time ownership interests in two of IPC's 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 (Thousands of Dollars) Total assets $ - $31,369 Net assets - 23,311 Net income 3,024 2,057 On January 1, 2000 IPC's ownership interests in two additional subsidiaries were transferred to IDACORP at book value. IPC's financial statements include the following amounts attributable to these transferred subsidiaries for the periods prior to January 1, 2000: As of/Year Ended December 31, 1999 1998 1997 (Thousands of Dollars) Total assets $107,996 $90,029 $69,294 Net assets 22,090 19,706 15,984 Net income 2,385 2,216 3,362 Except as modified below, the Notes to the Consolidated Financial Statements of IDACORP included in this 1999 Annual Report on Form 10-K are incorporated herein by reference insofar as they relate to Idaho Power Company. 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 - Benefit Plans Note 10 - Electric Plant in Service and Jointly-Owned Projects Note 1 - Derivative Financial Instruments The following table shows a summary of the notional amounts of IPC's forward exposure as of December 31, 1999. The maximum term related to any forward position is two years. Electricity MWh's Payable 4,739 Receivable 6,079 The following table displays the fair value of IPC's energy marketing assets and liabilities (all electricity) at December 31, 1999, and the average values for the year ended December 31, 1999 (in thousands of dollars): 1999 End of Year Balance 1999 Average Balance Assets Liabilities Assets Liabilities $ 29,096 $ 25,594 $ 40,450 $ 43,320 The gain in fair value of energy trading contract positions (including electricity forwards, futures, options and swaps) included in income before income taxes for the year ended December 31, 1999 was $23.2 million. 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: 1999 1998 1997 (Thousands of Dollars) Computed income taxes based on statutory federal income tax rate $ 50,077 $ 49,344 $ 48,561 Change in taxes resulting from: Investment tax credits (3,032) (2,934) (2,887) Repair allowance (2,800) (2,800) (2,800) Settlement of prior years tax returns (478) (1,965) 23 Current state income taxes 5,833 6,309 3,587 Depreciation 7,292 5,237 5,766 Affordable housing tax credits (9,529) (6,880) (4,519) Other (1,813) (1,246) (1,259) Total provision for federal and state income taxes $ 45,550 $ 45,065 $ 46,472 Effective tax rate 31.8% 32.0% 33.5% The provision for income taxes consists of the following: 1999 1998 1997 (Thousand of Dollars) Income taxes currently payable: Federal $ 38,169 $ 45,909 $ 35,038 State 9,128 9,283 5,456 Total 47,297 55,192 40,494 Income taxes deferred - Net of amortization: Federal 2,246 (8,006) 6,717 State (2,030) (1,321) 348 Total 216 (9,327) 7,065 Investment tax credits: Deferred 1,069 2,134 1,800 Restored (3,032) (2,934) (2,887) Total (1,963) (800) (1,087) Total provision for income taxes $ 45,550 $ 45,065 $ 46,472 The tax effects of significant items comprising the Company's net deferred tax liability are as follows: 1999 1998 1997 (Thousands of Dollars) Deferred tax assets: Regulatory liabilities $ 33,817 $ 28,075 $ 34,072 Advances for construction 9,646 10,401 18,665 Other 18,890 20,457 16,536 Total 62,353 58,933 69,273 Deferred tax liabilities: Electric plant 249,597 247,270 251,938 Regulatory assets 215,675 204,430 201,685 Conservation programs 17,396 16,866 14,377 Other 9,501 13,600 28,173 Total 492,169 482,166 496,173 Net deferred tax liabilities $429,816 $423,233 $426,900 Note 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 $898.1 million in 1999, $877.4 million in 1998, and $801.8 million in 1997. Included in investments and other property were financial instruments totaling $11.9 million in 1999, $0.0 in 1998, and $16.5 million in 1997. Estimated fair value of these instruments was $11.8 million in 1999, $0.0 in 1998, and $19.9 million in 1997. Note 11 - Industry Segment Information IPC is predominantly a one operating segment company with its regulated electric operations being the most dominant segment. IPC's primary business is the generation, transmission, distribution, purchase and sale of electricity. The Company's primary non-utility segments involve electricity trading and renewable energy products. The following table summarizes the segment information for IPC's regulated electric operations and the total of all other segments, and reconciles this information to total enterprise amounts: Regulated Electric Consolidated Operations Other Total (Thousands of Dollars) 1999 Revenues $ 658,336 $ - $ 658,336 Income from operations 172,458 - 172,458 Other income 5,120 26,122 31,242 Interest expense 56,679 3,943 60,622 Income before income taxes 120,899 22,179 143,078 Income taxes 46,395 (845) 45,550 Net income 74,504 23,024 97,528 Total assets 2,355,907 203,467 2,559,374 Expenditures for long- lived assets 112,772 22,685 135,457 1998 Revenues $ 756,410 $ - $ 756,410 Income from operations 180,584 - 180,584 Other income 5,909 14,184 20,093 Interest expense 56,646 3,047 59,693 Income before income taxes 135,505 5,479 140,984 Income taxes 47,552 (2,487) 45,065 Net income 87,953 7,966 95,919 Total assets 2,251,077 170,713 2,421,790 Expenditures for long- lived assets 91,803 19,197 111,000 1997 Revenues $ 605,183 $ - $ 605,183 Income from operations 180,731 - 180,731 Other income 3,894 14,379 18,273 Interest expense 57,653 2,605 60,258 Income before income taxes 132,148 6,598 138,746 Income taxes 47,618 (1,146) 46,472 Net income 84,530 7,744 92,274 Total assets 2,272,752 179,064 2,451,816 Expenditures for long- lived assets 98,219 17,457 115,676 Substantially all of the Company's revenues come from the sale of electricity and related services, predominately in the United States. The Company also trades electricity and sells renewable energy products and other miscellaneous services. Revenues from these operations are not significant. INDEPENDENT AUDITORS' REPORT To The Board of Directors and Shareowner 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, 1999, 1998 and 1997, 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, 1999, 1998 and 1997, 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 31, 2000 SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA: The following unaudited information is presented for each quarter of 1999, 1998 and 1997 (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 1999 Revenues $174,149 $165,072 $161,978 $157,136 Income from operations 59,829 39,724 39,942 32,963 Income taxes 16,700 10,525 10,574 7,874 Net income 29,501 21,242 22,019 18,588 Earnings per share of common stock 0.78 0.56 0.59 0.49 1998 Revenues $170,913 $167,132 $230,200 $188,164 Income from operations 55,769 39,097 44,037 41,681 Income taxes 13,125 9,213 12,392 9,900 Net income 28,050 20,351 22,305 18,468 Earnings per share of common stock 0.75 0.54 0.59 0.49 1997 Revenues $145,735 $147,133 $159,702 $152,614 Income from operations 58,459 41,019 41,889 39,365 Income taxes 16,361 9,126 10,715 10,270 Net income 28,986 19,377 19,719 19,018 Earnings per share of common stock 0.77 0.52 0.52 0.51 Idaho Power Company Quarter Ended March 31 June 30 September 30 December 31 1999 Revenues $174,149 $165,072 $161,978 $157,136 Income from operations 59,829 39,724 39,942 32,963 Income taxes 16,582 10,479 10,419 8,071 Net income 30,784 22,796 23,371 20,576 Dividends on preferred stock 1,368 1,352 1,401 1,451 Earnings on common stock 29,416 21,444 21,970 19,125 1998 Revenues $170,913 $167,132 $230,200 $188,164 Income from operations 55,769 39,097 44,037 41,681 Income taxes 13,125 9,213 12,392 10,335 Net income 29,455 21,768 23,715 20,979 Dividends on preferred stock 1,405 1,417 1,410 1,426 Earnings on common stock 28,050 20,351 22,305 19,553 1997 Revenues $145,735 $147,133 $159,702 $152,614 Income from operations 58,459 41,019 41,889 39,365 Income taxes 16,361 9,126 10,715 10,270 Net income 30,380 20,042 21,141 20,715 Dividends on preferred stock 1,394 665 1,422 1,696 Earnings on common stock 28,986 19,377 19,719 19,018 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 SCHEDULE AND REPORTS ON FORM 8-K (a) Please refer to Item 8, "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules. (b) Reports on SEC Form 8-K. The following Report on Form 8-K was filed for the three months ended December 31, 1999 Items Reported Date of Report Filed by Item 7 - Financial November 17,1999 IPC Statements 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) 1-3198 4(b) By-laws of IPC amended on September Form 10-Q 9, 1999, and presently in effect. *3(d) 33-56071 3(d) Articles of Share Exchange, 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 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) 1-14465 3(c) Amended Bylaws of IDACORP, Inc. as Form 10-Q of July 8, 1999. for 6/30/99 *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 1, 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) 1-14465 4 Rights Agreement, dated as of Form 8-K September 10, 1998, between IDACORP, dated Inc. and the Bank of New York as September Rights Agent. 15, 1998 *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 1-14465 10(h)(iv) The Revised Security Plan for Board 1-3198 of Directors - a non-qualified, Form 10-K deferred compensation plan effective for 1998 August 1, 1996, revised March 2, 1999. *10(h)(v) 1-3198 10(e) IDACORP, Inc. Non-Employee Directors Form 10-Q Stock Compensation Plan as of May for 6/30/99 17, 1999. *10(h)(vi) 1-3198 10(y) Executive Employment Agreement dated Form 10-K November 20, 1996 between IPC and for 1997 Richard R. Riazzi. *10(h)(vii) 1-3198 10(g) Executive Employment Agreement dated Form 10-Q April 12, 1999 between IPC and for 6/30/99 Marlene Williams. *10(h)(viii) 1-14465 10(h) Agreement between IDACORP, Inc. and Form 10-Q Jan B. Packwood, J. LaMont Keen, for 9/30/99 James C. Miller, Richard Riazzi, Darrel T. Anderson, Bryan Kearney, Cliff N. Olson, Robert W. Stahman and Marlene K. Williams. 10(h)(ix) 1 IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. *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. 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, 1999, 1998 and 1997 Column A Column B Column C Column D Column E Additions Charged Balance Charged (Credited) Balance At to to Other Deductions At End Classification Beginning Income Accounts (1) Of Of Period Period (Thousands of Dollars) 1999: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $ 1,397 $ - $ 3,162(2) $ 3,162 $ 1,397 Other Reserves: Rate refunds $ 5,356 $10,543 $ - $ 7,006 $ 8,893 Injuries and damages reserve $ 1,500 $ - $ - $ - $ 1,500 Miscellaneous operating reserves $ 6,907 $ 3,242 $ - $ 1,676 $ 8,473 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 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, 1999, 1998 and 1997 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 caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. IDACORP, Inc. (Registrant) March 16, 2000 By: /s/Jan B. Packwood Jan B. Packwood President, 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/ Jon H. Miller /s/ Chairman of the Board March 16, 2000 Jon H. Miller By: /s/ Jan B. Packwood /s/ President and Chief " Executive Jan B. Packwood Officer and Director By: /s/ J. LaMont Keen /s/ Senior Vice President, " Administration J. LaMont Keen and Chief Financial Officer (Principal Financial Officer) By: /s/ Darrel T. Anderson /s/ Vice President, Finance " and Treasurer Darrel T. Anderson (Principal Accounting Officer) By: /s/ Rotchford L. Barker By: /s/ Jack K. Lemley " Rotchford L. Barker Jack K. Lemley Director Director By: /s/ Robert D. Bolinder By: /s/ Evelyn Loveless " Robert D. Bolinder Evelyn Loveless 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/ Robert A. Tinstman " John B. Carley Robert A. Tinstman Director Director By: /s/ Peter T. Johnson " Peter T. Johnson Director SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. IDAHO POWER COMPANY (Registrant) March 16, 2000 By: /s/Jan B. Packwood Jan B. Packwood President, 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/ Jon H. Miller /s/ Chairman of the Board March 16, 2000 Jon H. Miller By: /s/ Jan B. Packwood /s/ President and Chief " Executive Jan B. Packwood Officer and Director By: /s/ J. LaMont Keen /s/ Senior Vice President, " Administration J. LaMont Keen and Chief Financial Officer (Principal Financial Officer) By: /s/ Darrel T. Anderson /s/ Vice President, Finance " and Treasurer Darrel T. Anderson (Principal Accounting Officer) By: /s/ Rotchford L. Barker By: /s/ Jack K. Lemley " Rotchford L. Barker Jack K. Lemley Director Director By: /s/ Robert D. Bolinder By: /s/ Evelyn Loveless " Robert D. Bolinder Evelyn Loveless 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/ Robert A. Tinstman " John B. Carley Robert A. Tinstman Director Director By: /s/ Peter T. Johnson " Peter T. Johnson Director EXHIBIT INDEX Exhibit Page Number Number 10(h)(ix) IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. 12 Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(a) Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.) 12(b) Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.) 12(c) Statements Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.) 12(d) Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IPC) 12(e) Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC) 12(f) Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC) 12(g) Statements 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 _______________________________ 1 Compensatory plan 1 1 Compensatory plan 1 EX-10 2 -1- Exhibit 10(h)(ix)1 IDACORP, INC. 2000 LONG-TERM INCENTIVE AND COMPENSATION PLAN 1. Article Establishment, Purpose and Duration 1.1 Establishment of the Plan. IDACORP, Inc., an Idaho corporation (hereinafter referred to as the "Company"), hereby establishes an incentive and compensation plan for officers, key employees and directors, to be known as the "IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan" (hereinafter referred to as the "Plan"), as set forth in this document. The Plan permits the grant of nonqualified stock options (NQSO), incentive stock options (ISO), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares and other awards. The Plan shall become effective when approved by the shareholders at the 2000 Annual Meeting of Shareholders (the "Effective Date") and shall remain in effect as provided in Section 1.3 herein. 1.1 Purpose of the Plan. The purpose of the Plan is to promote the success and enhance the value of the Company by linking the personal interests of Participants to those of Company shareholders and customers. The Plan is further intended to provide flexibility to the Company in its ability to motivate, attract and retain the services of Participants upon whose judgment, interest and special effort the successful conduct of its operations is largely dependent. 1.1 Duration of the Plan. The Plan shall commence on the Effective Date, as described in Section 1.1 herein, and shall remain in effect, subject to the right of the Board of Directors to terminate the Plan at any time pursuant to Article 15 herein, until all Shares subject to it shall have been purchased or acquired according to the Plan's provisions. 1. Article Definitions Whenever used in the Plan, the following terms shall have the meanings set forth below and, when such meaning is intended, the initial letter of the word is capitalized: 1.1 Award means, individually or collectively, a grant under the Plan of NQSOs, ISOs, SARs, Restricted Stock, Restricted Stock Units, Performance Units, Performance Shares or any other type of award permitted under Article 10 of the Plan. 1.1 Award Agreement means an agreement entered into by each Participant and the Company, setting forth the terms and provisions applicable to an Award granted to a Participant under the Plan. 1.1 Base Value of an SAR shall have the meaning set forth in Section 7.1 herein. 1.2 Board or Board of Directors means the Board of Directors of the Company. 1.1 Change in Control means the earliest of the following to occur: (a) the public announcement by the Company or by any person (which shall not include the Company, any subsidiary of the Company or any employee benefit plan of the Company or of any subsidiary of the Company) ("Person") that such Person, who or which, together with all Affiliates and Associates (within the meanings ascribed to such terms in Rule 12b-2 of the Exchange Act) of such Person, shall be the beneficial owner of twenty percent (20%) or more of the voting stock then outstanding; (a) 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; (a) 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; (a) 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-thirds (2/3) of the directors then still in office who were members of the Board at the beginning of the period; (a) 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; (a) 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; or (a) any other event which shall be deemed by a majority of the Executive Committee of the Board to constitute a "Change in Control." 1.1 Code means the Internal Revenue Code of 1986, as amended from time to time. 1.1 Committee means the committee, as specified in Article 3, appointed by the Board to administer the Plan with respect to Awards. 1.1 Company means IDACORP, Inc., an Idaho corporation, or any successor thereto as provided in Article 17 herein. 1.1 Covered Employee means any Participant who would be considered a "covered employee" for purposes of Section 162(m) of the Code. 1.1 Director means any individual who is a member of the Board of Directors of the Company. 1.1 Disability means the continuous inability of an Employee because of illness or injury to engage in any occupation or employment for wage or profit with the Company or any other employer (including self-employment) for which he is reasonably qualified by education, training or experience. An Employee will not be considered disabled during any period unless he is under the regular care and attendance of a duly qualified physician. 1.1 Dividend Equivalent means, with respect to Shares subject to an Award, a right to be paid an amount equal to dividends declared on an equal number of outstanding Shares. 1.1 Eligible Person means a Person who is eligible to participate in the Plan, as set forth in Section 5.1 herein. 1.1 Employee means an individual who is paid on the payroll of the Company or of the Company's Subsidiaries, who is not covered by any collective bargaining agreement to which the Company or any of its Subsidiaries is a party, and is classified in the payroll system as a regular full-time, part-time or temporary employee. For purposes of the Plan, transfer of employment of a Participant between the Company and any one of its Subsidiaries (or between Subsidiaries) shall not be deemed a termination of employment. 1.1 Exchange Act means the Securities Exchange Act of 1934, as amended from time to time, or any successor act thereto. 1.1 Exercise Period means the period during which an SAR or Option is exercisable, as set forth in the related Award Agreement. 1.1 Fair Market Value means the average of the high and low sale prices as reported in the consolidated transaction reporting system, or, if there was no such sale on the relevant date, then on the last previous day on which a sale was reported. 1.1 Freestanding SAR means an SAR that is not a Tandem SAR. 1.1 Incentive Stock Option or ISO means an option to purchase Shares, granted under Article 6 herein, which is designated as an Incentive Stock Option and satisfies the requirements of Section 422 of the Code. 1.1 Nonqualified Stock Option or NQSO means an option to purchase Shares, granted under Article 6 herein, which is not intended to be an Incentive Stock Option under Section 422 of the Code. 1.1 Option means an Incentive Stock Option or a Nonqualified Stock Option. 1.1 Option Exercise Price means the price at which a Share may be purchased by a Participant pursuant to an Option, as determined by the Committee and set forth in the Option Award Agreement. 1.1 Participant means an Eligible Person who has outstanding an Award granted under the Plan. 1.1 Performance Goals means the performance goals established by the Committee, which shall be based on one or more of the following measures: sales or revenues, earnings per share, shareholder return and/or value, funds from operations, operating income, gross income, net income, cash flow, return on equity, return on capital, earnings before interest, operating ratios, stock price, customer satisfaction, accomplishment of mergers, acquisitions, dispositions or similar extraordinary business transactions, profit returns and margins, financial return ratios and/or market performance. Performance goals may be measured solely on a corporate, subsidiary or business unit basis, or a combination thereof. Performance goals may reflect absolute entity performance or a relative comparison of entity performance to the performance of a peer group of entities or other external measure. 1.1 Performance Period means the time period during which Performance Unit/Performance Share Performance Goals must be met. 1.1 Performance Share means an Award described in Article 9 herein. 1.1 Performance Unit means an Award described in Article 9 herein. 1.1 Period of Restriction means the period during which the transfer of Restricted Stock is limited in some way, as provided in Article 8 herein. 1.1 Person shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act, as used in Sections 13(d) and 14(d) thereof, including usage in the definition of a "group" in Section 13(d) thereof. 1.1 Plan means the IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. 1.1 Qualified Restricted Stock means an Award of Restricted Stock designated as Qualified Restricted Stock by the Committee at the time of grant and intended to qualify for the exemption from the limitation on deductibility imposed by Section 162(m) of the Code that is set forth in Section 162(m)(4)(C). 1.1 Qualified Restricted Stock Unit means an Award of Restricted Stock Units designated as Qualified Restricted Stock Units by the Committee at the time of grant and intended to qualify for the exemption from the limitation on deductibility imposed by Section 162(m) of the Code that is set forth in Section 162(m)(4)(C). 1.1 Restricted Stock means an Award described in Article 8 herein. 1.1 Restricted Stock Unit means an Award described in Article 8 herein. 1.1 Retirement means a Participant's termination from employment with the Company or a Subsidiary at the Participant's Early or Normal Retirement Date, as applicable. (a) Early Retirement Date -- shall mean the date on which a Participant terminates employment, if such termination date occurs on or after Participant's attainment of age fifty-five (55) but prior to Participant's Normal Retirement Date. (b) Normal Retirement Date -- shall mean the date on which the Participant terminates employment, if such termination date occurs on or after the Participant attains age sixty-two (62). 1.1 Securities Act means the Securities Act of 1933, as amended. 1.1 Shares means the shares of common stock, no par value, of the Company. 1.1 Stock Appreciation Right or SAR means a right, granted alone or in connection with a related Option, designated as an SAR, to receive a payment on the day the right is exercised, pursuant to the terms of Article 7 herein. Each SAR shall be denominated in terms of one Share. 1.1 Subsidiary means any corporation (other than the Company) in an unbroken chain of corporations beginning with the Company if each of the corporations other than the last corporation in the unbroken chain owns stock possessing 50 percent or more of the total combined voting power of all classes of stock in one of the other corporations in such chain. 1.1 Tandem SAR means an SAR that is granted in connection with a related Option, the exercise of which shall require forfeiture of the right to purchase a Share under the related Option (and when a Share is purchased under the Option, the Tandem SAR shall be similarly canceled). 2. Article Administration 1.1 The Committee. The Plan shall be administered by the Compensation Committee or such other committee (the "Committee") as the Board of Directors shall select consisting solely of two or more members of the Board. The members of the Committee shall be appointed from time to time by, and shall serve at the discretion of, the Board of Directors. 1.1 Authority of the Committee. The Committee shall have full power except as limited by law, the Articles of Incorporation or the Bylaws of the Company, subject to such other restricting limitations or directions as may be imposed by the Board and subject to the provisions herein, to determine the Eligible Persons to receive Awards; to determine the size and types of Awards; to determine the terms and conditions of such Awards; to construe and interpret the Plan and any agreement or instrument entered into under the Plan; to establish, amend or waive rules and regulations for the Plan's administration; and (subject to the provisions of Article 15 herein) to amend the terms and conditions of any outstanding Award. Further, the Committee shall make all other determinations which may be necessary or advisable for the administration of the Plan. As permitted by law, the Committee may delegate its authorities as identified hereunder. 1.1 Restrictions on Distribution of Shares and Share Transferability. Notwithstanding any other provision of the Plan, the Company shall have no liability to deliver any Shares or benefits under the Plan unless such delivery would comply with all applicable laws (including, without limitation, the Securities Act) and applicable requirements of any securities exchange or similar entity and unless the Participant's tax obligations have been satisfied as set forth in Article 16. The Committee may impose such restrictions on any Shares acquired pursuant to Awards under the Plan as it may deem advisable, including, without limitation, restrictions to comply with applicable Federal securities laws, with the requirements of any stock exchange or market upon which such Shares are then listed and/or traded and with any blue sky or state securities laws applicable to such Shares. 1.1 Decisions Binding. All determinations and decisions made by the Committee pursuant to the provisions of the Plan and all related orders or resolutions of the Board shall be final, conclusive and binding on all persons, including the Company, its shareholders, Eligible Persons, Employees, Participants and their estates and beneficiaries. 1.1 Costs. The Company shall pay all costs of administration of the Plan. 1. Article Shares Subject to the Plan 1.1 Number of Shares. Subject to Section 4.2 herein, the maximum number of Shares available for grant under the Plan shall be 750,000. Shares underlying lapsed or forfeited Awards, or Awards that are not paid in Shares, may be reused for other Awards; if the Option Exercise Price is satisfied by tendering Shares, only the number of Shares issued net of the Shares tendered shall be deemed issued under the Plan. Shares granted pursuant to the Plan may be (i) authorized but unissued Shares of common stock, (ii) treasury shares or (iii) Shares purchased on the open market. 1.2 Adjustments in Authorized Shares and Awards. In the event of any merger, reorganization, consolidation, recapitalization, liquidation, stock dividend, split-up, spin- off, stock split, reverse stock split, share combination, share exchange or other change in the corporate structure of the Company affecting the Shares, such adjustment shall be made in the outstanding Awards, the number and class of Shares which may be delivered under the Plan, and in the number and class of and/or price of Shares subject to outstanding Awards granted under the Plan, as may be determined to be appropriate and equitable by the Committee, in its sole discretion, to prevent dilution or enlargement of rights. Notwithstanding the foregoing, (i) each such adjustment with respect to an Incentive Stock Option shall comply with the rules of Section 424(a) of the Code and (ii) in no event shall any adjustment be made which would render any Incentive Stock Option granted hereunder to be other than an incentive stock option for purposes of Section 422 of the Code. In no event shall the Committee have the right to amend an outstanding Option Award for the sole purpose of reducing the exercise price thereof. 1.1 Individual Limitations. Subject to Section 4.2 above, (i) the total number of Shares with respect to which Options or SARs may be granted in any calendar year to any Covered Employee shall not exceed 100,000 Shares; (ii) the total number of Qualified Restricted Stock Shares or Qualified Restricted Stock Units that may be granted in any calendar year to any Covered Employee shall not exceed 100,000 Shares or Units, as the case may be; (iii) the total number of Performance Shares or Performance Units that may be granted in any calendar year to any Covered Employee shall not exceed 100,000 Shares or Units, as the case may be; (iv) the total number of Shares that are intended to qualify for deduction under Section 162(m) of the Code granted pursuant to Article 10 herein in any calendar year to any Covered Employee shall not exceed 100,000 Shares; (v) the total cash Award that is intended to qualify for deduction under Section 162(m) of the Code that may be paid pursuant to Article 10 herein in any calendar year to any Covered Employee shall not exceed $300,000; and (vi) the aggregate number of Dividend Equivalents that are intended to qualify for deduction under Section 162(m) of the Code that a Covered Employee may receive in any calendar year shall not exceed 400,000. 1. Article Eligibility and Participation 1.1 Eligibility. Persons eligible to participate in the Plan ("Eligible Persons") include all officers, key employees and directors of the Company and its Subsidiaries, as determined by the Committee. 1.1 Actual Participation. Subject to the provisions of the Plan, the Committee may, from time to time, select from all Eligible Persons those to whom Awards shall be granted. 1. Article Stock Options 1.1 Grant of Options. Subject to the terms and conditions of the Plan, Options may be granted to an Eligible Person at any time and from time to time, as shall be determined by the Committee. The Committee shall have complete discretion in determining the number of Shares subject to Options granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such Options. The Committee may grant ISOs, NQSOs or a combination thereof. 1.1 Option Award Agreement. Each Option grant shall be evidenced by an Option Award Agreement that shall specify the Option Exercise Price, the term of the Option, the number of Shares to which the Option pertains, the Exercise Period and such other provisions as the Committee shall determine, including but not limited to any rights to Dividend Equivalents. The Option Award Agreement shall also specify whether the Option is intended to be an ISO or a NQSO. 1.1 Exercise of and Payment for Options. Options granted under the Plan shall be exercisable at such times and shall be subject to such restrictions and conditions as the Committee shall in each instance approve. A Participant may exercise an Option at any time during the Exercise Period. Options shall be exercised by the delivery of a written notice of exercise to the Company, setting forth the number of Shares with respect to which the Option is to be exercised, accompanied by provision for full payment for the Shares. The Option Exercise Price shall be payable: (a) in cash or its equivalent, (b) by tendering previously acquired Shares having an aggregate Fair Market Value at the time of exercise equal to the total Option Exercise Price, (c) by broker-assisted cashless exercise or (d) by a combination of (a), (b) and/or (c). 1.1 Termination. Each Option Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the Option following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries. Such provisions shall be determined in the sole discretion of the Committee (subject to applicable law), shall be included in the Option Award Agreement entered into with Participants, need not be uniform among all Options granted pursuant to the Plan or among Participants and may reflect distinctions based on the reasons for termination. 1.1 Transferability of Options. Except as otherwise determined by the Committee, all Options granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant, and no Option granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. ISOs are not transferable other than by will or by the laws of descent and distribution. 1. Article Stock Appreciation Rights 1.1 Grant of SARs. Subject to the terms and conditions of the Plan, an SAR may be granted to an Eligible Person at any time and from time to time as shall be determined by the Committee. The Committee may grant Freestanding SARs, Tandem SARs or any combination of these forms of SARs. The Committee shall have complete discretion in determining the number of SARs granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such SARs. The Base Value of a Freestanding SAR shall equal the Fair Market Value of a Share on the date of grant of the SAR. The Base Value of Tandem SARs shall equal the Option Exercise Price of the related Option. 1.1 SAR Award Agreement. Each SAR grant shall be evidenced by an SAR Award Agreement that shall specify the number of SARs granted, the Base Value, the term of the SAR, the Exercise Period and such other provisions as the Committee shall determine. 1.1 Exercise and Payment of SARs. Tandem SARs may be exercised for all or part of the Shares subject to the related Option upon the surrender of the right to exercise the equivalent portion of the related Option. A Tandem SAR may be exercised only with respect to the Shares for which its related Option is then exercisable. Notwithstanding any other provision of the Plan to the contrary, with respect to a Tandem SAR granted in connection with an ISO: (i) the Tandem SAR will expire no later than the expiration of the underlying ISO; (ii) the value of the payout with respect to the Tandem SAR may be for no more than one hundred percent (100%) of the difference between the Option Exercise Price of the underlying ISO and the Fair Market Value of the Shares subject to the underlying ISO at the time the Tandem SAR is exercised; and (iii) the Tandem SAR may be exercised only when the Fair Market Value of the Shares subject to the ISO exceeds the Option Exercise Price of the ISO. Freestanding SARs may be exercised upon whatever terms and conditions the Committee, in its sole discretion, imposes upon them. A Participant may exercise an SAR at any time during the Exercise Period. SARs shall be exercised by the delivery of a written notice of exercise to the Company, setting forth the number of SARs being exercised. Upon exercise of an SAR, a Participant shall be entitled to receive payment from the Company in an amount equal to the product of: (a) the excess of (i) the Fair Market Value of a Share on the date of exercise over (ii) the Base Value multiplied by (a) the number of Shares with respect to which the SAR is exercised. At the sole discretion of the Committee, the payment to the Participant upon SAR exercise may be in cash, in Shares of equivalent value or in some combination thereof. 1.1 Termination. Each SAR Award Agreement shall set forth the extent to which the Participant shall have the right to exercise the SAR following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the SAR Award Agreement entered into with Participants, need not be uniform among all SARs granted pursuant to the Plan or among Participants and may reflect distinctions based on the reasons for termination. 1.1 Transferability of SARs. Except as otherwise determined by the Committee, all SARs granted to a Participant under the Plan shall be exercisable during his or her lifetime only by such Participant or his or her legal representative, and no SAR granted under the Plan may be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. 1. Article Restricted Stock and Restricted Stock Units 1.1 Grant of Restricted Stock and Restricted Stock Units. Subject to the terms and conditions of the Plan, Restricted Stock and/or Restricted Stock Units may be granted to an Eligible Person at any time and from time to time, as shall be determined by the Committee. The Committee shall have complete discretion in determining the number of shares of Restricted Stock and/or Restricted Stock Units granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such Awards. In addition, the Committee may, prior to or at the time of grant, designate an Award of Restricted Stock or Restricted Stock Units as Qualified Restricted Stock or Qualified Restricted Stock Units, as the case may be, in which event it will condition the grant or vesting, as applicable, of such Qualified Restricted Stock or Qualified Restricted Stock Units, as the case may be, upon the attainment of the Performance Goals selected by the Committee. 1.1 Restricted Stock/Restricted Stock Unit Award Agreement. Each grant of Restricted Stock and/or Restricted Stock Units grant shall be evidenced by a Restricted Stock and/or Restricted Stock Unit Award Agreement that shall specify the number of shares of Restricted Stock and/or Restricted Stock Units granted, the initial value (if applicable), the Period or Periods of Restriction, and such other provisions as the Committee shall determine. 1.1 Transferability. Restricted Stock and Restricted Stock Units granted hereunder may not be sold, transferred, pledged, assigned, or otherwise alienated or hypothecated until the end of the applicable Period of Restriction established by the Committee and specified in the Award Agreement. During the applicable Period of Restriction, all rights with respect to the Restricted Stock and Restricted Stock Units granted to a Participant under the Plan shall be available during his or her lifetime only to such Participant or his or her legal representative. 1.1 Certificates. No certificates representing Stock shall be issued until such time as all restrictions applicable to such Shares have been satisfied. 1.1 Removal of Restrictions. Restricted Stock shall become freely transferable by the Participant after the last day of the Period of Restriction applicable thereto. Once Restricted Stock is released from the restrictions, the Participant shall be entitled to receive a certificate. Payment of Restricted Stock Units shall be made after the last day of the Period of Restriction applicable thereto. The Committee, in its sole discretion, may pay Restricted Stock Units in cash or in Shares (or in a combination thereof), which have an aggregate Fair Market Value equal to the value of the Restricted Stock Units. 1.1 Voting Rights. During the Period of Restriction, Participants may exercise full voting rights with respect to the Restricted Stock. 1.1 Dividends and Other Distributions. Subject to the Committee's right to determine otherwise at the time of grant, during the Period of Restriction, Participants shall receive all regular cash dividends paid with respect to the Shares while they are so held. All other distributions paid with respect to such Restricted Stock shall be credited to Participants subject to the same restrictions on transferability and forfeitability as the Restricted Stock with respect to which they were paid and shall be paid to the Participant promptly after the full vesting of the Restricted Stock with respect to which such distributions were made. Rights, if any, to Dividend Equivalents on Restricted Stock Units shall be established by the Committee at the time of grant and set forth in the Award Agreement. 1.1 Termination. Each Restricted Stock/Restricted Stock Unit Award Agreement shall set forth the extent to which the Participant shall have the right to receive Restricted Stock and/or a Restricted Stock Unit payment following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with Participants, need not be uniform among all grants of Restricted Stock/Restricted Stock Units or among Participants and may reflect distinctions based on the reasons for termination. 1. Article Performance Units and Performance Shares 1.1 Grant of Performance Units and Performance Shares. Subject to the terms and conditions of the Plan, Performance Units and/or Performance Shares may be granted to an Eligible Person at any time and from time to time, as shall be determined by the Committee. The Committee shall have complete discretion in determining the number of Performance Units and/or Performance Shares granted to each Eligible Person (subject to Article 4 herein) and, consistent with the provisions of the Plan, in determining the terms and conditions pertaining to such Awards. 1.1 Performance Unit/Performance Share Award Agreement. Each grant of Performance Units and/or Performance Shares shall be evidenced by a Performance Unit and/or Performance Share Award Agreement that shall specify the number of Performance Units and/or Performance Shares granted, the initial value (if applicable), the Performance Period, the Performance Goals and such other provisions as the Committee shall determine, including but not limited to any rights to Dividend Equivalents. 1.1 Value of Performance Units/Performance Shares. Each Performance Unit shall have an initial value that is established by the Committee at the time of grant. The value of a Performance Share shall be equal to the Fair Market Value of a Share. The Committee shall set Performance Goals in its discretion which, depending on the extent to which they are met, will determine the number and/or value of Performance Units/Performance Shares that will be paid out to the Participants. 1.1 Earning of Performance Units/Performance Shares. After the applicable Performance Period has ended, the Participant shall be entitled to receive a payout with respect to the Performance Units/Performance Shares earned by the Participant over the Performance Period, to be determined as a function of the extent to which the corresponding Performance Goals have been achieved. 1.1 Form and Timing of Payment of Performance Units/Performance Shares. Payment of earned Performance Units/Performance Shares shall be made following the close of the applicable Performance Period. The Committee, in its sole discretion, may pay earned Performance Units/Shares in cash or in Shares (or in a combination thereof), which have an aggregate Fair Market Value equal to the value of the earned Performance Units/Shares at the close of the applicable Performance Period. Such Shares may be granted subject to any restrictions deemed appropriate by the Committee. 1.1 Termination. Each Performance Unit/Performance Share Award Agreement shall set forth the extent to which the Participant shall have the right to receive a Performance Unit/Performance Share payment following termination of the Participant's employment with or service on the Board of the Company and its Subsidiaries during a Performance Period. Such provisions shall be determined in the sole discretion of the Committee, shall be included in the Award Agreement entered into with Participants, need not be uniform among all grants of Performance Units/Performance Shares or among Participants and may reflect distinctions based on reasons for termination. 1.1 Transferability. Except as otherwise determined by the Committee, a Participant's rights with respect to Performance Units/Performance Shares granted under the Plan shall be available during the Participant's lifetime only to such Participant or the Participant's legal representative and Performance Units/Performance Shares may not be sold, transferred, pledged, assigned or otherwise alienated or hypothecated, other than by will or by the laws of descent and distribution. 1. Article Other Awards The Committee shall have the right to grant other Awards which may include, without limitation, the grant of Shares based on attainment of Performance Goals established by the Committee, the payment of Shares in lieu of cash or cash based on attainment of Performance Goals established by the Committee, and the payment of Shares in lieu of cash under other Company incentive or bonus programs. Payment under or settlement of any such Awards shall be made in such manner and at such times as the Committee may determine. 1. Article Beneficiary Designation Each Participant under the Plan may, from time to time, name any beneficiary or beneficiaries (who may be named contingently or successively) to whom any benefit under the Plan is to be paid in case of the Participant's death before the Participant receives any or all of such benefit. Each such designation shall revoke all prior designations by the same Participant, shall be in a form prescribed by the Company and will be effective only when filed by the Participant in writing with the Company during the Participant's lifetime. In the absence of any such designation, benefits remaining unpaid at the Participant's death shall be paid to the Participant's estate. The spouse of a married Participant domiciled in a community property jurisdiction shall join in any designation of beneficiary or beneficiaries other than the spouse. 1. Article Deferrals The Committee may permit a Participant to defer the Participant's receipt of the payment of cash or the delivery of Shares that would otherwise be due to such Participant under the Plan. If any such deferral election is permitted, the Committee shall, in its sole discretion, establish rules and procedures for such payment deferrals. 1. Article Rights of Participants 1.1 Termination. Nothing in the Plan shall interfere with or limit in any way the right of the Company or any Subsidiary to terminate any Participant's employment or other relationship with the Company or any Subsidiary at any time, for any reason or no reason in the Company's or the Subsidiary's sole discretion, nor confer upon any Participant any right to continue in the employ of, or otherwise in any relationship with, the Company or any Subsidiary. 1.1 Participation. No Eligible Person shall have the right to be selected to receive an Award under the Plan, or, having been so selected, to be selected to receive a future Award. 1.1 Limitation of Implied Rights. Neither a Participant nor any other Person shall, by reason of the Plan, acquire any right in or title to any assets, funds or property of the Company or any Subsidiary whatsoever, including, without limitation, any specific funds, assets or other property which the Company or any Subsidiary, in their sole discretion, may set aside in anticipation of a liability under the Plan. A Participant shall have only a contractual right to the Shares or amounts, if any, payable under the Plan, unsecured by any assets of the Company or any Subsidiary. Nothing contained in the Plan shall constitute a guarantee that the assets of such companies shall be sufficient to pay any benefits to any Person. Except as otherwise provided in the Plan, no Award under the Plan shall confer upon the holder thereof any right as a shareholder of the Company prior to the date on which the individual fulfills all conditions for receipt of such rights. 1. Article Change in Control The terms of this Article 14 shall immediately become operative, without further action or consent by any person or entity, upon a Change in Control, and once operative shall supersede and take control over any other provisions of this Plan. Upon a Change in Control (a) Any and all Options and SARs granted hereunder shall become immediately vested and exercisable; (a) Any restriction periods and restrictions imposed on Restricted Stock, Restricted Stock Units, Qualified Restricted Stock or Qualified Restricted Stock Units shall be deemed to have expired; any Performance Goals shall be deemed to have been met at the target level; such Restricted Stock and Qualified Restricted Stock shall become immediately vested in full, and such Restricted Stock Units and Qualified Restricted Stock Units shall be paid out in cash; and (a) The target payout opportunity attainable under all outstanding Awards of Performance Units and Performance Shares and any other Awards shall be deemed to have been fully earned for the entire Performance Period(s) as of the effective date of the Change in Control. All Awards shall become immediately vested. All Performance Shares and other Awards denominated in Shares shall be paid out in Shares, and all Performance Units and other Awards shall be paid out in cash. 1. Article Amendment, Modification and Termination 1.1 Amendment, Modification and Termination. The Board may, at any time and from time to time, alter, amend, suspend or terminate the Plan in whole or in part. 1.1 Awards Previously Granted. No termination, amendment or modification of the Plan shall adversely affect in any material way any Award previously granted under the Plan without the written consent of the Participant holding such Award, unless such termination, modification or amendment is required by applicable law and except as otherwise provided herein. 1. Article Withholding 1.1 Tax Withholding. The Company shall have the power and the right to deduct or withhold, or require a Participant to remit to the Company, an amount (including any Shares withheld as provided below) sufficient to satisfy Federal, state and local taxes (including the Participant's FICA obligation) required by law to be withheld with respect to an Award made under the Plan. 1.1 Share Withholding. With respect to tax withholding required upon the exercise of Options or SARs, upon the lapse of restrictions on Restricted Stock, or upon any other taxable event arising out of or as a result of Awards granted hereunder, Participants may elect to satisfy the withholding requirement, in whole or in part, by tendering Shares held by the Participant or by having the Company withhold Shares having a Fair Market Value equal to the minimum statutory total tax which could be imposed on the transaction. All elections shall be irrevocable, made in writing and signed by the Participant. 1. Article Successors All obligations of the Company under the Plan, with respect to Awards granted hereunder, shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, consolidation or otherwise of all or substantially all of the business and/or assets of the Company. 1. Article Legal Construction 1.1 Gender and Number. Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular and the singular shall include the plural. 1.1 Severability. In the event any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had not been included. 1.1 Requirements of Law. The granting of Awards and the issuance of Shares under the Plan shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required. Governing Law. To the extent not preempted by Federal law, the Plan, and all agreements hereunder, shall be construed in accordance with, and governed by, the laws of the State of Idaho. EX-12 3
Ex12 IDACORP, Inc. Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method 0 0 0 458 435 investments Minority interest in losses of majority owned subsidiaries 0 0 0 (125) (37) Fixed charges, as below 70,215 70,418 69,634 69,923 72,243 Total earnings, as defined $ 195,499 $ 204,252 $ 199,261 $ 199,365 $ 208,825 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975 Preferred stock dividends of subsidiaries- gross up-IDACORP rate 12,834 12,079 7,891 8,445 8,313 Rental interest factor 925 991 982 801 955 Total fixed charges, as defined $ 70,215 $ 70,418 $ 69,634 $ 69,923 $ 72,243 Ratio of earnings to fixed charges 2.78x 2.90x 2.86x 2.85x 2.89x
EX-12 4
Ex12a IDACORP, Inc. Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method investments 0 0 0 458 435 Minority interest in losses of majority owned subsidiaries 0 0 0 (125) (37) Supplemental fixed charges, as below 72,826 73,018 72,208 72,496 74,800 Total earnings, as defined $ 198,110 $ 206,852 $ 201,835 $ 201,938 $ 211,382 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975 Preferred stock dividends of subsidiaries- gross up-IDACORP rate 12,834 12,079 7,891 8,445 8,313 Rental interest factor 925 991 982 801 955 Total fixed charges 70,215 70,418 69,634 69,923 72,243 Supplemental increment to fixed charges* 2,611 2,600 2,574 2,573 2,557 Total supplemental fixed charges $ 72,826 $ 73,018 $ 72,208 $ 72,496 $ 74,800 Supplemental ratio of earnings to fixed charges 2.72 x 2.83 x 2.80 x 2.79 x 2.83 x *Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.
EX-12 5
Ex12b IDACORP, Inc. Consolidated Financial Information Ratio of Earnings to Combined Fixed Charges and Preferred Dividends Requirements Twelve Months Ended December 31, (Thousands of Dollars) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method investments 0 0 0 458 435 Minority interest in losses of majority owned subsidiaries 0 0 0 (125) (37) Fixed charges, as below 70,215 70,418 69,634 69,923 72,243 Total earnings, as defined $ 195,499 $ 204,252 $ 199,261 $ 199,365 $ 208,825 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975 Preferred stock dividends of subsidiaries- gross up-IDACORP rate 12,834 12,079 7,891 8,445 8,313 Rental interest factor 925 991 982 801 955 Total fixed charges 70,215 70,418 69,634 69,923 72,243 Preferred dividends requirements 0 0 0 0 0 Total combined fixed charges and preferred dividends $ 70,215 $ 70,418 $ 69,634 $ 69,923 $ 72,243 Ratio of earnings to combined fixed charges and preferred dividends 2.78x 2.90x 2.86x 2.85x 2.89x
EX-12 6
Ex12c 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) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 127,342 $ 135,247 $ 133,570 $ 133,806 $ 137,021 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method investments 0 0 0 458 435 Minority interest in losses of majority owned subsidiaries 0 0 0 (125) (37) Supplemental fixed charges and preferred dividends, as below 72,826 73,018 72,208 72,496 74,800 Total earnings, as defined $ 198,110 $ 206,852 $ 201,835 $ 201,938 $ 211,382 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,677 $ 62,975 Preferred stock dividends of subsidiaries-gross up-IDACORP rate 12,834 12,079 7,891 8,445 8,313 Rental interest factor 925 991 982 801 955 Total fixed charges 70,215 70,418 69,634 69,923 72,243 Supplemental increment to fixed charges* 2,611 2,600 2,574 2,573 2,557 Supplemental fixed charges 72,826 73,018 72,208 72,496 74,800 Preferred dividends requirements 0 0 0 0 0 Total combined supplemental fixed charges and preferred dividends $ 72,826 $ 73,018 $ 72,208 $ 72,496 $ 74,800 Supplemental ratio of earnings to combined fixed charges and preferred dividends 2.72x 2.83x 2.80x 2.79x 2.83x *Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.
EX-12 7
Ex12d Idaho Power Company Consolidated Financial Information Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method investments 0 0 0 476 0 Minority interest in losses of majority owned subsidiaries 0 0 0 (125) 0 Fixed charges, as below 57,381 58,339 61,743 61,394 62,969 Total earnings, as defined $ 190,656 $ 199,636 $ 196,546 $ 198,032 $ 205,210 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014 Rental interest factor 925 991 982 801 955 Total fixed charges, as defined $ 57,381 $ 58,339 $ 61,743 $ 61,394 $ 62,969 Ratio of earnings to fixed charges 3.32x 3.42x 3.18x 3.23x 3.26x
EX-12 8
Ex12e Idaho Power Company Consolidated Financial Information Supplemental Ratio of Earnings to Fixed Charges Twelve Months Ended December 31, (Thousands of Dollars) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method investments 0 0 0 476 0 Minority interest in losses of majority owned subsidiaries 0 0 0 (125) 0 Supplemental fixed charges, as below 59,992 60,939 64,317 63,967 65,526 Total earnings, as defined $ 193,267 $ 202,236 $ 199,120 $ 200,605 $ 207,767 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014 Rental interest factor 925 991 982 801 955 Total fixed charges 57,381 58,339 61,743 61,394 62,969 Supplemental increment to fixed charges* 2,611 2,600 2,574 2,573 2,557 Total supplemental fixed charges $ 59,992 $ 60,939 $ 64,317 $ 63,967 $ 65,526 Supplemental ratio of earnings to fixed charges 3.22x 3.32 x 3.10x 3.14x 3.17x *Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.
EX-12 9
Ex12f 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) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method investments 0 0 0 476 0 Minority interest in losses of majority owned subsidiaries 0 0 0 (125) 0 Fixed charges, as below 57,381 58,339 61,743 61,394 62,969 Total earnings, as defined $ 190,656 $ 199,636 $ 196,546 $ 198,032 $ 205,210 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014 Rental interest factor 925 991 982 801 955 Total fixed charges 57,381 58,339 61,743 61,394 62,969 Preferred stock dividends-gross up Idaho Power rate 12,392 12,146 7,803 8,275 8,133 Total combined fixed charges and preferred dividends $ 69,773 $ 70,485 $ 69,546 $ 69,669 $ 71,102 Ratio of earnings to combined fixed charges and preferred dividends 2.73x 2.83x 2.83x 2.84x 2.89x
EX-12 10
Ex12g 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) 1995 1996 1997 1998 1999 Earnings, as defined: Income before income taxes $ 135,333 $ 142,710 $ 138,746 $ 140,984 $ 143,078 Adjust for distributed income of equity investees (2,058) (1,413) (3,943) (4,697) (837) Equity in loss of equity method investments 0 0 0 476 0 Minority interest in losses of majority owned subsidiaries 0 0 0 (125) 0 Supplemental fixed charges and preferred dividends, as below 59,992 60,939 64,317 63,967 65,526 Total earnings, as defined $ 193,267 $ 202,236 $ 199,120 $ 200,605 $ 207,767 Fixed charges, as defined: Interest charges $ 56,456 $ 57,348 $ 60,761 $ 60,593 $ 62,014 Rental interest factor 925 991 982 801 955 Total fixed charges 57,381 58,339 61,743 61,394 62,969 Supplemental increment to fixed charges* 2,611 2,600 2,574 2,573 2,557 Supplemental fixed charges 59,992 60,939 64,317 63,967 65,526 Preferred stock dividends-gross up Idaho Power rate 12,392 12,146 7,803 8,275 8,133 Total combined supplemental fixed charges and preferred dividends $ 72,384 $ 73,085 $ 72,120 $ 72,242 $ 73,659 Supplemental ratio of earnings to combined fixed charges and preferred dividends 2.67x 2.77x 2.76x 2.78x 2.82x *Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.
EX-21 11 EXHIBIT 21 SUBSIDIARIES OF REGISTRANTS IDACORP, Inc: 1. Idaho Power Company, an Idaho Corporation 2. Ida-West Energy Company, an Idaho Corporation 3. IDACORP Energy Solutions Company, a Nevada Corporation, doing business as Idaho Power Services 4. IDACORP Energy Solutions L.P., A Delaware Limited Partnership 5. IDACORP Energy Services Company, a Nevada Corporation 6. IDACORP Retail Enterprises Co., an Idaho Corporation 7. IDACORP Technologies, Inc., an Idaho Corporation 8. Northwest Power Systems LLC, an Oregon Limited Liability Company Idaho Power Company 1. Applied Power Corporation, a Washington Corporation (see note) 2. IDACORP Financial Services, Inc., an Idaho Corporation (see note) 3. Idaho Energy Resources Company, a Wyoming Corporation 4. Idaho Power Resources Corporation, an Idaho Corporation 5. Idaho Power Diversified Enterprises Company, an Idaho Corporation 6. Pathnet/Idaho Equipment, LLC., an Idaho Limited Liability Company Note: on January 1, 2000 ownership of this subsidiary was transferred to IDACORP, Inc. 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. 333-00139 and 333-64737 on Form S-3 and Registration Statement Nos. 33-56071, 333-89445 and 333-65157 on Form S-8 of our reports dated January 31, 2000 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, 1999. DELOITTE & TOUCHE LLP Boise, Idaho March 20, 2000 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-31-1999 DEC-31-1999 PER-BOOK 1,745,683 146,019 350,408 394,883 0 2,636,993 451,343 0 301,627 752,970 0 105,811 808,062 0 13,496 19,757 89,101 0 0 0 847,796 2,636,993 658,336 45,672 485,878 531,550 126,786 31,718 158,504 67,155 91,349 0 91,349 69,863 54,294 230,588 2.43 2.43
EX-27 14 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
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-31-1999 DEC-31-1999 PER-BOOK 1,742,394 117,759 305,119 394,102 0 2,559,374 94,031 358,384 275,715 728,130 0 105,811 808,062 0 13,496 23,934 89,101 0 0 0 790,840 2,559,374 658,336 45,550 485,878 531,428 126,908 31,242 158,150 60,622 97,528 5,572 91,956 69,912 54,150 213,845 0 0
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