10-K405 1 a10k405.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K405 (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 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 Registrant as specified in its charter, Commission address of principal executive IRS Employer File Number offices and telephone number Identification Number 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 Preferred Stock Purchase Rights New York and Pacific SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Preferred Stock Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ( X ) No ( ) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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: None Number of shares of common stock outstanding at February 28, 2002: 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 2002 Annual Meeting of Shareholders to be held on May 16, 2002. GLOSSARY AFDC - Allowance for Funds Used During Construction APB - Accounting Principles Board BPA - Bonneville Power Administration CSPP - Cogeneration and Small Power Production DIG - Derivatives Implementation Group DSM - Demand-Side Management EITF - Emerging Issue Task Force EPA - Environmental Protection Agency FASB - Financial Accounting Standards Board FERC - Federal Energy Regulatory Commission FPA - Federal Power Act Ida-West - Ida-West Energy IE - IDACORP Energy IFS - IDACORP Financial Services IPC - Idaho Power Company IPUC - Idaho Public Utilities Commission IRP - Integrated Resource Plan kW - kilowatt kWh - kilowatt-hour MD&A - Management's Discussion and Analysis MW - Megawatt MWh - Megawatt-hour OPUC - Oregon Public Utility Commission PCA - Power Cost Adjustment PUCN - Public Utility Commission of Nevada PURPA - Public Utilities Regulatory Policy Act REA - Rural Electrification Administration RFP - Request for proposals RTOs - Regional Transmission Organizations SFAS - Statement of Financial Accounting Standards SPPCo - Sierra Pacific Power Company Valmy - North Valmy Steam Electric Generating Plant TABLE OF CONTENTS PART I PAGE ITEM 1. BUSINESS 1 ITEM 2. PROPERTIES 10 ITEM 3. LEGAL PROCEEDINGS 11 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 11 EXECUTIVE OFFICERS OF THE REGISTRANT 12 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS 14 ITEM 6. SELECTED FINANCIAL DATA 14 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 15 ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 30 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 56 PART III ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT* 56 ITEM 11.EXECUTIVE COMPENSATION* 56 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT* 56 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 56 PART IV ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K 56 SIGNATURES 61 *INCORPORATED BY REFERENCE. 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. PART I ITEM 1. BUSINESS OVERVIEW Idaho Power Company (IPC) was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. IPC is a parent to Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to IPC's Jim Bridger generating plant. The outstanding shares of IPC's common stock were exchanged on a share-for-share basis into common stock of IDACORP, Inc. (IDACORP) on October 1, 1998 and are no longer actively traded. IPC's preferred stock and debt securities were unaffected and remain outstanding with IPC. Over the last several years, IPC has transferred to its parent, IDACORP, ownership of several of its subsidiaries. Effective January 2000, ownership of IDACORP Financial Services (IFS) and Applied Power Company (sold January 2001) were transferred to IDACORP. Effective June 11, 2001 IPC transferred its non-utility wholesale electricity marketing operations (Energy Marketing) to IDACORP Energy (IE), a subsidiary of IDACORP. See Note 11 to the Consolidated Financial Statements "Discontinued Operations." After the transfer of Energy Marketing, IPC consists of one operating segment, Utility Operations. The Utility Operations segment has two primary sources of income, the regulated operations of IPC and income from its joint venture in Bridger Coal Company. IPC is an electric utility regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho, Oregon, Nevada and Wyoming, and is involved in the generation, purchase, transmission, distribution and sale of electric energy in a 20,000 square mile area in southern Idaho and eastern Oregon, with an estimated population of 873,000. IPC holds franchises in 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 and three counties in Oregon. As of December 31, 2001, IPC supplied electric energy to over 401,000 general business customers and had 1,688 full-time employees. IPC owns and operates 17 hydroelectric power plants, one natural gas-fired plant and shares ownership in three coal-fired generating plants. These generating plants and their capacities are listed in Item 2. "Properties." IPC's coal-fired plants are in Wyoming, Oregon and Nevada, and use low-sulfur coal from Wyoming and Utah. IPC relies heavily on hydroelectric power for its generating needs and is one of the nation's few investor-owned utilities with a predominantly hydroelectric generating base. Because of its reliance on hydro generation, IPC's generation operations can be significantly affected by the weather. The availability of inexpensive hydroelectric power depends on snowpack in the mountains above IPC's hydro facilities, precipitation and other weather and streamflow management considerations. When hydroelectric generation decreases and customer demand increases, IPC increases its use of more expensive thermal generation and purchased power. The rates IPC charges to its general business customers are determined by the various regulatory authorities. Approximately 95 percent of IPC's general business revenue and sales come from customers in Idaho. The rates charged to these customers are adjusted annually by a power cost adjustment (PCA) mechanism. The PCA adjusts rates to reflect the changes in costs incurred by IPC to supply power. Throughout the year, IPC compares its actual power supply costs to the amounts it is recovering in rates. Most, but not all, of this difference is deferred and included in the calculation of rates for future years. The PCA is discussed in more detail below in "Rates" and in Note 12 to the Consolidated Financial Statements. The primary influences on electricity sales are weather and economic conditions. 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. IPC's principal commercial and industrial customers are involved in: food processing, electronics and general manufacturing, lumber, beet sugar refining, and the skiing industry. Regulation IPC is under the regulatory jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the FERC, the Idaho Public Utilities Commission (IPUC), the Oregon Public Utility Commission (OPUC) and the Public Utility Commission of Nevada (PUCN). 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 (FPA) 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 FPA, 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 FPA 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 FPA or IPC's FERC license (see Item 2. "Properties"). Rates Idaho Jurisdiction: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail electric customers. These adjustments, which take effect annually in May, are based on forecasts of net power supply expenses and the true-up of the prior year's forecast. During the year, the difference between the actual costs incurred and the forecasted costs is deferred, with interest. The balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment. So far in the 2001-2002 rate year actual power supply costs included in the PCA have been significantly greater than forecast due to purchased power volumes and prices being greater than originally forecasted and the implementation of the voluntary load reduction payments with Astaris and the irrigation customers. To account for these higher-than-forecasted costs, and the unamortized portion of the 2000-2001 PCA balance, IPC has recorded regulatory assets of $290 million as of December 31, 2001. In the 2001 PCA filing, IPC requested recovery of $227 million of power supply costs. In May, the IPUC authorized recovery of $168 million, but deferred recovery of $59 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59 million the IPUC authorized recovery of $48 million plus $1 million of accrued interest, beginning in October 2001. The remaining $11 million not recovered in rates from the PCA filing was written off in September 2001. Other Jurisdictions: IPC filed an application with the OPUC to begin recovering extraordinary 2001 power supply costs in its Oregon jurisdiction. On June 18, 2001, the OPUC approved new rates that would recover $1 million over the next year. Under the provisions of the deferred accounting statute, annual rate recovery amounts were limited to three percent of IPC's 2000 gross revenues in Oregon. During the 2001 session, the Oregon Legislature amended the statute giving the OPUC authority to increase the maximum annual rate of recovery of deferred amounts to six percent for electric utilities. IPC subsequently filed on October 5, 2001 to recover an additional three percent extraordinary deferred power supply costs. As a result of this filing, the OPUC issued Order No. 01-994 allowing IPC to increase its rate of recovery to six percent effective November 28, 2001. The Oregon deferral balance is $15 million as of December 31, 2001, net of the June 18, 2001 and November 28, 2001 recovery. 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 wholesalers. IPC's generating stations and capacities are listed in "Item 2. Properties." IPC's system is dual peaking, with the larger peak demand generally occurring in the summer. The system peak demand for 2001 was 2,570 MW, set on July 2, 2001. Peak demands in 2000 and 1999 were 2,919 MW and 2,839 MW, respectively. IPC expects total system energy requirements to grow 2.2 percent annually over the next three years. The amounts of electricity IPC is able to generate from its hydro plants depend on a number of factors, primarily snowpack in the mountains above its hydro facilities, reservoir storage, and streamflow requirements. When these factors are favorable, IPC can generate more electricity using its hydroelectric plants. When these factors are unfavorable, IPC must increase its reliance on more expensive thermal plants and purchased power. Below normal water conditions in 2001 yielded a system generation mix of 43 percent hydro and 57 percent thermal. Historically, under normal water conditions, IPC's system generation mix is approximately 57 percent hydro and 43 percent thermal. The Snake River Basin snowpack numbers offer the promise of improved streamflows for 2002. IPC's mid-February 2002 accumulations were 84 percent of normal, compared to 51 percent at the same time a year earlier. Even though snowpack is closer to normal, reservoir storage is not, meaning hydro conditions will not fully return to normal in 2002. In September 2001, IPC placed in service Danskin Power Plant, a 90- MW natural gas-fired combustion turbine plant, located near Mountain Home, Idaho. 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 NorthWestern Energy under a contract that expires December 2003 and with Seattle City Light under a contract that expires October 2002. IPC's generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum load-carrying capability and reliability. IPC's transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration (BPA), Avista Corporation, PacifiCorp, NorthWestern Energy and Sierra Pacific Power Company (SPPCo). Such interconnections, coupled with transmission line capacity made available under agreements with certain of the above utilities, permit the interchange, purchase and sale of power among 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. These groups are being formed to more efficiently coordinate transmission reliability and planning throughout the western grid. See "Competition - Wholesale" discussion below. Integrated Resource Plan (IRP): Every two years, IPC is required to file with the IPUC and OPUC an IRP, a comprehensive look at IPC's present and future demands for electricity and plans for meeting that demand. The 2000 IRP identified a potential electricity shortfall within our utility service territory by mid- 2004. The plan projected a 250-MW resource need in 2004 to satisfy energy demand during IPC's peak periods. The IRP calls for IPC to use purchases from the Northwest energy markets to meet short-term energy needs. The 2000 IRP anticipates that after 2004, transmission constraints will not allow IPC to cover increasing demand using wholesale purchases from the Pacific Northwest. As a result of the 2000 IRP, IPC issued a request for proposals (RFP), seeking bids for 250-MWs of additional generation to support the growing demand in IPC's utility service territory. A proposal by Garnet Energy LLC, a subsidiary of Ida-West (a subsidiary of IDACORP), was selected by IPC. In December 2001, IPC signed an agreement with Garnet to define the conditions under which the utility will purchase energy to be produced by Garnet's proposed 273-MW natural gas-fired, combined cycle combustion turbine facility in Canyon County, Idaho, located in the southwest part of the state. In December 2001, IPC filed an application with the IPUC requesting authorization to include Garnet related expenses in IPC's PCA. On February 27, 2002, the IPUC tentatively set hearings in June 2002 to hear Idaho Power's request. 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 total cost of power purchased from CSPP projects was $45 million in 2001. During 2001, IPC purchased 728,155 MWh from these private developers at a blended price of 6.2 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 five entities. These contracts are for various amounts of energy, up to 36 average megawatts, and are of various lengths expiring between 2002 and 2009. Transmission Services: IPC has a long history of providing wholesale transmission service and provides various firm and non-firm wheeling services for several surrounding utilities. IPC's system lies between and is interconnected to the winter-peaking northern and summer-peaking southern regions of the western interconnected power system. This position allows IPC to provide transmission services and reach a broad power sales market. In December 1999, the FERC issued Order No. 2000 encouraging companies with transmission assets to form Regional Transmission Organizations (RTOs). See further discussion in "Competition - Wholesale." 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. SPPCo, with whom IPC is a joint (50/50) participant in the ownership and operation of the North Valmy Steam Electric Generating plant (Valmy), 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. Black Butte is expected to discontinue delivery to the Valmy project as IPC has fulfilled its purchase obligation specified in the coal supply agreement. This agreement had provided for Black Butte to supply coal to the Valmy project under a flexible delivery schedule that allowed for variations in the number of tons to be delivered ranging from a minimum of 300,000 tons per year to a maximum of one million tons per year. SPPCo is currently negotiating a coal sales agreement with Arch Coal Sales Company, Inc. to supply coal to the Valmy project from 2002 through 2006. IPC would be obligated to purchase one-half of the coal, ranging from approximately 515,000 tons to 762,500 tons annually, under this agreement. 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 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 FPA. 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 proceeding and 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 and facilities 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 2002 capital expenditures for environmental matters, excluding allowance for funds used during construction (AFDC), will total $14 million. Studies and measures related to mitigation of environmental concerns due to relicensing of hydro facilities account for $10 million and investments in environmental equipment and facilities at the thermal plants account for $4 million. During the 2003-2004 period, environmental-related capital expenditures are estimated to be $31 million. IPC anticipates $23 million in annual operating costs for environmental facilities during the 2002-2004 period. Clean Air: IPC has analyzed the Clean Air Act legislation and its effects upon IPC and its customers. IPC's coal-fired plants in Oregon and Nevada 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. IPC has sufficient SO2 allowances to provide compliance for all three coal-fired facilities and its Danskin natural gas-fired facility. Therefore, IPC does not foresee any 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 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. On May 14, 1999, a federal court ruling blocked implementation of these standards, which EPA proposed in 1997. In November 2000, the EPA appealed to the U.S. Supreme Court to reconsider that decision. No ruling has been made by the court as of December 31, 2001. Impacts of the ozone and PM regulations and regional haze regulations on IPC's thermal operations are unknown at this time. 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. The Danskin gas turbine plant in Mountain Home is operating in compliance with a "permit to construct" issued by the Idaho Department of Environmental Quality. The units are fitted with dry- low- NO x burners and a continuous emissions monitoring system. This will ensure that the facility will operate within the permitted federal and state NO x and carbon monoxide limits. 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, Shoshone Falls, Twin Falls, Upper Salmon, Lower Salmon and Bliss 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 by the Idaho Department of Fish and Game. At December 31, 2001, the investment in these facilities was $10 million and the annual cost of operation pursuant to FERC License 1971 is approximately $2 million. Endangered Species: Several species of fish and Snake River snails 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 and Legal 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. 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 costs for the identification and disposal of PCBs from IPC's system were less than $1 million each year for 2001, 2000 and 1999, respectively. IPC believes that all generation facilities are presently non-PCB. Competition Retail: 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. 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 changes and conforming regulations may result in increased 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. Wholesale: The 1992 Energy Act (Energy Act) and the FERC's rulemaking activities have established the regulatory framework to open the wholesale energy market to competition. The Energy Act permits utilities to develop independent electric generating plants for sales to wholesale customers, and authorizes the FERC to order transmission access for third parties to transmission facilities owned by another entity. The Energy Act does not, however, permit the FERC to require transmission access to retail customers. Open-access transmission for wholesale customers provides energy suppliers with opportunities to sell and deliver electricity at market-based prices. In December 1999 the FERC, in its landmark Order 2000, said that all companies with transmission assets must file to form RTOs or explain why they cannot. Order 2000 is a follow up to Orders No. 888 and 889 issued in 1996, which required transmission owners to provide non-discriminatory transmission service to third parties. By encouraging the formation of RTOs, the FERC seeks to further facilitate the formation of efficient, competitive wholesale electricity markets. In response to FERC Order 2000, IPC and other regional transmission owners filed, in October 2000, a plan to form RTO West, an entity that will operate the transmission grid in seven western states. RTO West will have its own independent governing board. The participating transmission owners will retain ownership of the lines, but will not have a role in operating the grid. This previous FERC filing represents a portion of the filing necessary to form RTO West. However, substantial additional filings will be necessary to include the tariff and integration agreements associated with the new entity. There will also need to be filings for state approvals. IPC expects the "Stage 2" FERC filing to be completed by March 2002. State filings may be initiated in late 2002. Utility Operating Statistics The following table presents IPC's revenues and volumes for the last three years: Years Ended December 31, 2001 2000 1999 Revenues (thousands of dollars) Residential $260,251 225,336 213,547 Commercial 164,019 132,023 123,069 Industrial 154,318 133,171 117,366 Irrigation 72,020 74,827 62,166 Total general business 650,608 565,357 516,148 Off-system sales 219,966 229,986 119,785 Other 41,738 40,319 22,403 Total $912,312 835,662 658,336 Energy use (thousands of MWhs) Residential 4,307 4,393 4,200 Commercial 3,380 3,404 3,194 Industrial 3,925 4,808 4,666 Irrigation 1,419 1,993 1,706 Total general business 13,031 14,598 13,766 Off-system sales 2,387 4,529 5,924 Total 15,418 19,127 19,690 RESEARCH AND DEVELOPMENT In 2001, IPC spent approximately $2 million to promote energy efficiency, including payments of $1 million to the Northwest Energy Efficiency Alliance and amounts totaling less than $1 million to low-income weatherization programs in Idaho and Oregon. In addition to increasing the funding level for low-income weatherization, IPC began a new conservation program late in the year funded through a conservation credit from the BPA to assist customers coping with higher winter electricity bills. During 2001, IPC spent less than $1 million on research and development through membership in Electric Power Research Institute (EPRI). EPRI creates science technology solutions for the global energy and energy service. Some of the subjects of EPRI projects include: risk based system planning, understanding green power markets, wind generated electricity and renewable energy application in distribution generation. CAPITAL REQUIREMENTS Capital expenditures of $391 million and debt maturities of $157 million are expected to be paid from 2002 through 2004. IPC utility construction expenditures exclude AFDC. Over the next three years internally generated cash and debt issuances are expected to meet the majority of the funds needed to meet our capital requirements. Internally generated cash is expected to provide 100 percent in 2002 and an average of 82 percent in 2003 and 2004. 2002 2003-2004 (Millions of dollars) Capital Expenditures (excluding AFDC): Construction Expenditures: Generating facilities Hydro $ 15 $ 35 Thermal 13 27 Total generating facilities 28 62 Transmission lines and substations 18 46 Distribution lines and substations 57 119 General 21 40 Total construction expenditures 124 267 Long-term debt maturities 27 130 Other 3 9 Total capital requirements $154 $406 IPC has no nuclear involvement and its future construction plans do not include development of any nuclear generation. IPC's capital expenditures are primarily for maintaining current infrastructures and meeting anticipated electricity demands. 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. The above 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. IPC 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, 2001, net earnings were 6.44 times. Additional preferred stock may be issued when earnings for twelve consecutive months within the preceding fifteen months are at least equal to 1.75 times the aggregate annual interest requirements on all debt securities and dividend requirements on preferred stock. At December 31, 2001, the actual preferred dividend earnings coverage was 2.79 times. If the dividends on the shares of Auction Preferred Stock were to reach the maximum allowed, the preferred dividend earnings coverage would be 2.55 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. CREDIT RATINGS All of the Company's publicly traded debt have received investment grade ratings from each of the three major credit rating agencies. The changes in the energy industry and the recent bankruptcy of Enron Corp. have caused the rating agencies to refocus their attention on the credit characteristics and credit protection measures of industry participants and in some cases the rating agencies appear to have tightened the standards for a given rating level. The Company will continue to evaluate its capital structure, financing requirements, competitive strategies and future capital expenditures to try to maintain investment grade ratings. However, there is no assurance that these current ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downgrade or revision may adversely affect the market price of the Company's securities and serve to increase its cost of capital. ITEM 2. PROPERTIES IPC's system includes 17 hydroelectric generating plants located in southern Idaho and eastern Oregon (detailed below), one natural gas-fired plant and an interest in three coal-fired steam electric generating plants. The system also includes approximately 4,653 miles of high voltage transmission lines; 21 step-up transmission substations located at power plants; 18 transmission substations; 7 transmission switching stations; and 208 energized distribution substations (excludes mobile substations and dispatch centers). IPC holds licenses under the FPA for 13 hydroelectric projects from the FERC. These and the other generating stations and their capacities are listed below: Maximum Non- Coincident Operating Nameplate License Project Capacity 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 1999 (a) Shoshone Falls 12,500 12,500 1999 (a) C J Strike 89,000 82,800 2000 (a) 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 2040 Steam and Other Generating Plants: Other Hydroelectric 10,400 11,300 Jim Bridger (coal-fired) 706,667 709,617 Valmy (coal-fired) 260,650 260,650 Boardman (coal-fired) 55,200 56,050 Danskin (gas-fired) 100,000 90,000 Salmon (diesel-internal 5,500 5,000 combustion) (a) Renewed on a year-to-year basis; application for relicense is pending. At December 31, 2001, the composite average ages of the principal parts of IPC's system, based on dollar investment, were: production plant, 18 years; transmission system and substations, 20 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 FPA 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. Jim Bridger, Valmy and Boardman are jointly owned generating facilities. IPC's ownership percentages are thirty-three, fifty and ten, respectively. 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. Relicensing As a result of various federal legislative actions and proposals (such as the Electric Consumers Protection Act of 1986, Energy Policy Act of 1992, Clean Water Act Reauthorization and Endangered Species Act Reauthorization), a major issue facing 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 will continue for the next ten to 15 years, depending on environmental issues and political processes. The most significant relicensing effort is the Hells Canyon Complex, which provides over half of IPC's hydro generation capacity and 40 percent of its total generating capacity. Presently, IPC is developing its draft license application with the assistance 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 draft license application in September 2002, with the final application following in July 2003. Shoshone Falls, Upper Salmon Falls, Lower Salmon Falls and Bliss hydroelectric projects are awaiting an Environmental Impact Statement (EIS) from the federal government, which is necessary prior to license issuance. IPC completed 64 Additional Information Requests (AIRs) from the agencies and non-governmental organizations in early 2000 which, combined with recently filed, final recommendations, terms and conditions, was used by the FERC to produce a draft EIS for these projects in January 2002. A final EIS is expected in August 2002. IPC filed its application for a new license for the C J Strike project in November 1998. Similarly, 21 AIRs were issued on this project and the FERC has noticed that this project is Ready for Environmental Analysis, which gives the agencies and interested parties 60 days to provide their final recommendations, terms and conditions for this project. A draft EIS is expected by June 2002. The Upper and Lower Malad projects are on schedule to file the new license application in July 2002. The draft application was sent to agencies and non-governmental organizations in October 2001. ITEM 3. LEGAL PROCEEDINGS None 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 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. Name, Age and Position Business Experience During Past Five (5) Years Jan B. Packwood, 57 Appointed March 1, 2002. Mr. Chief Executive Officer Packwood was President and Chief Executive Officer from May 30, 1999 to March 1, 2002, President and Chief Operating Officer from September 1, 1997 to May 30, 1999 and Executive Vice President from July 11, 1996 to September 1, 1997. J. LaMont Keen, 49 Appointed March 1, 2002. Mr. Keen President and Chief was Senior Vice President- Operating Officer Administration and Chief Financial Officer from May 5, 1999 to March 1, 2002, Senior Vice President- Administration, Chief Financial Officer and Treasurer from March 15, 1999 to May 5, 1999 and Vice President, Chief Financial Officer and Treasurer from March 14, 1996 to March 15, 1999. James C. Miller, 47 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. Darrel T. Anderson, 43 Appointed March 1, 2002. Mr. Vice President, Chief Anderson was Vice President-Finance Financial Officer and and Treasurer from May 5, 1999 to Treasurer March 1, 2002, Corporate Controller from January 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. John R. Gale, 51 Appointed March 15, 2001. Mr. Gale Vice President, Regulatory was General Manager of Pricing & Affairs Regulatory Services (1997-2001). Bryan A.B. Kearney, 39 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) and Chief Information Officer for Shasta County, California (1996-1998). Gregory W. Panter, 53 Appointed April 1, 2001. Mr. Panter Vice President - Public was self-employed with Panter & Affairs Associates from 1989 to 2001. John P. Prescott, 45 Appointed November 18, 1999. Mr. Vice President - Generation Prescott was Vice President of 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. Cliff N. Olson, 52 Appointed July 11, 1991. Vice President - Corporate Services Robert W. Stahman, 57 Appointed July 13, 1989. Vice President - General Counsel and Secretary Marlene K. Williams, 49 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 RELATED STOCKHOLDER MATTERS 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. ITEM 6. SELECTED FINANCIAL DATA SUMMARY OF OPERATIONS (thousands of dollars) For the Years Ended December 31, 2001 2000 1999 1998 1997 Operating revenues $ 912,312 $ 835,662 $ 658,336 $ 756,410 $ 605,183 Income from operations 90,020 169,636 172,458 180,584 180,731 Income from continuing operations 28,295 79,968 83,465 90,743 90,429 At December 31, Total long-term debt* $ 802,201 808,977 821,558 815,937 746,142 Total assets** 2,859,704 2,617,092 2,559,374 2,421,790 2,451,816 Utility Customer Data: General business customers 401,739 393,831 384,421 373,730 363,085 Average kWh per customer 30,846 37,068 36,379 36,368 37,080 Average rate per kWh (in cents) 5.25 3.87 3.75 3.85 3.63 *Excludes amount due within one year. ** 1997-1999 include assets of discontinued operations. The above data should be read in conjunction with Idaho Power Company's consolidated financial statements and notes to consolidated financial statements included in Form 10-K. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION In Management's Discussion and Analysis we explain the general financial condition and results of operations of Idaho Power Company (IPC). IPC is an electric utility with a service territory covering over 20,000 square miles, primarily in southern Idaho and eastern Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to IPC's Jim Bridger generating plant. Over the last several years, IPC has transferred to its parent, IDACORP, Inc. (IDACORP), ownership of several of its subsidiaries. Effective January 2000, ownership of IDACORP Financial Services (IFS) and Applied Power Company were transferred to IDACORP. In June 2001, IPC transferred its non-utility wholesale electricity marketing operations to IDACORP Energy (IE), a subsidiary 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, 2001, 2000 and 1999. Results of the non-utility wholesale electricity marketing operations are presented as discontinued operations on our 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 IPC 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); the current energy situation in the western United States; 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; 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 IPC. Any forward-looking statement speaks only as of the date on which such statement is made. 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 In this section we discuss our earnings and the factors that affected them, beginning with a general overview: 2001 2000 1999 (thousands of dollars) Income from continuing operations $ 28,295 $ 79,968 $ 83,465 Discontinued energy marketing operations 49,943 57,520 14,063 Net income $ 78,238 137,488 97,528 High wholesale energy prices and a severe drought had a negative effect on income from continuing operations from 2000 to 2001. Of the $51 million decrease from 2000, $26 million is attributable to increases in power supply expenses absorbed by IPC and $7 million is due to the write-off of amounts disallowed in IPC's 2001 power cost adjustment. Additional increases in operating expenses for maintenance, depreciation, interest and customer expenses decreased earnings by approximately $13 million. The decrease in income from continuing operations from 1999 to 2000 is predominantly the result of increased net power supply costs of $69 million, due to declining hydroelectric generating conditions and increased market prices for purchased power. These costs were partially offset by a $49 million increase in increased general business revenue resulting from rate increases, customer growth, and weather conditions. In 2000 we recorded a $7 million pension credit and in 1999 we recorded a $9 million reduction to income for shared revenue (see "Regulatory Issues - Regulatory Settlement"). UTILITY OPERATIONS IPC's utility operations are subject to regulation by, among others, the state public utility commissions of Idaho, Oregon and Nevada and by the FERC. Before we discuss the changes in income from our utility operations, we'll describe these operations and the significant factors that influenced them in 2001 and 2000. The main catalysts for the changes that occurred in our utility operations were high wholesale energy prices and the drought in the Northwest. In late 2000 and early 2001, prices for electricity in the wholesale markets became highly volatile, reaching unprecedented levels. Faced with soaring demand, exorbitant prices and very little water to produce power, we set in motion a number of measures to decrease our reliance on the wholesale power markets, by decreasing demand and increasing our generating capabilities. Some of these measures were: The IPUC approved a two-year agreement through which we compensate our largest industrial customer, Astaris, for reducing its load by 50 MW. The IPUC and OPUC approved programs that compensated irrigation customers capable of reducing usage by at least 100 MWh. As part of the May 2001 Power Cost Adjustment (PCA), the IPUC required IPC to implement a tiered rate structure for Idaho residential customers. This rate structure increases rates as a customer's usage increases. In September 2001, we placed in service Danskin Power Plant, a 90-MW natural gas-fired combustion turbine plant, located near Mountain Home, Idaho. Mobile generators with total generating capacity of 40 MW were sited at various locations in Boise during portions of the year. In May 2001, we made the largest filing in the nine years that our PCA mechanism has been in effect, seeking recovery of $227 million, 96 percent of which we are now recovering. IPC owns and operates 17 hydroelectric power plants, one natural gas- fired plant and shares ownership in three coal-fired generating plants. The following table presents IPC's system generation for the last three years: Percent of total MWhs (in thousands) generation 2001 2000 1999 2001 2000 1999 Hydroelectric 5,638 8,500 10,652 43% 52% 59% Thermal 7,622 7,701 7,266 57 48 41 Total system generation 13,260 16,201 17,918 100% 100% 100% As the table shows, we rely on low-cost hydroelectric plants for a significant portion of our generation. Over the last ten years, hydro generation has averaged 8.7 million MWh, 57 percent of our total generation. The amounts of electricity we are able to generate from these hydro plants depend on a number of factors, primarily snowpack in the mountains above our hydro facilities, reservoir storage, and streamflow requirements. When these factors are favorable, we can generate more electricity using our hydroelectric plants. When these factors are unfavorable, we must increase our reliance on more expensive thermal plants and purchased power. As of this writing, Snake River Basin snowpack numbers offer the promise of improved streamflows. Our mid-February 2002 accumulations were 84 percent of normal, compared to 51 percent at the same time a year earlier. Even though snowpack is closer to normal, reservoir storage is not, meaning hydro conditions will not fully return to normal in 2002. Regulatory authorities determine the rates we charge to our general business customers. Approximately 95 percent of our general business revenue and sales come from customers in the state of Idaho. The rates we charge these customers are adjusted annually by a PCA mechanism. The PCA adjusts rates to reflect the changes in costs incurred by IPC to supply power. Throughout the year, we compare our actual power supply costs to the amounts we are recovering in rates. Most, but not all, of this difference is deferred and included in the calculation of rates for future years. The primary influences on electricity sales volumes are weather and economic conditions. 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 addition, in 2001 we put in place several demand management programs designed to reduce energy consumption by our customers. Finally, the significant rate increases implemented in this year's PCA have reduced demand. General business customer growth continued, with 2.5 percent and 2.4 percent annual increases over the last two years in our Idaho-Oregon service territory. The following table summarizes our income from operations. Each line is analyzed in more detail below. 2000-2001 1999-2000 Increase Increase 2001 2000 (Decrease) 1999 (Decrease) (thousands of dollars) Revenues: General $ 650,608 $565,357 $ 85,251 $516,148 $ 49,209 business Off-system 219,966 229,986 (10,020) 119,785 110,201 Other 41,738 40,319 1,419 22,403 17,916 Total revenues 912,312 835,662 76,650 658,336 177,326 Expenses: Purchased power 584,209 398,649 185,560 106,344 292,305 Fuel 98,318 94,215 4,103 86,617 7,598 PCA (175,925) (120,688) (55,237) (502) (120,186) Other operating 315,690 293,850 21,840 293,419 431 expenses Total expenses 822,292 666,026 156,266 485,878 180,148 Income from $ 90,020 $169,636 $(79,616) $172,458 $ (2,822) operations General Business Revenue The following table presents IPC's general business revenues and volumes for the last three years: Revenues Volumes (thousands of dollars) (in thousands of MWh) 2001 2000 1999 2001 2000 1999 Residential $260,251 $225,336 $213,547 4,307 4,393 4,200 Commercial 164,019 132,023 123,069 3,380 3,404 3,194 Industrial 154,318 133,171 117,366 3,925 4,808 4,666 Irrigation 72,020 74,827 62,166 1,419 1,993 1,706 Total $650,608 $565,357 $516,148 13,031 14,598 13,766 As mentioned above, our general business revenue is dependent on many factors, including the number of customers we serve, the rates we charge, and weather conditions. 2001 vs. 2000: In 2001, the following factors influenced the 15.0 percent increase in general business revenue: Increased average rates, resulting from the PCA, increased revenue $137 million. We discuss the PCA in more detail below in "Regulatory Issues - Power Cost Adjustment"; A 2.5 percent increase in general business customers increased revenue $16 million; Conservation programs, including irrigation and large customer buybacks, and other usage factors, decreased energy consumption, reducing revenues $67 million. 2000 vs. 1999: The 9.5 percent increase in general business revenues is due to the following factors: Increased average rates, resulting from the PCA and special- contract customers, increased revenues $17 million; Increased usage per customer, resulting from weather conditions and other factors, increased revenues $26 million. Decreased precipitation during the growing season increased sales to irrigation customers, and hotter summer and colder winter temperatures increased sales to the other customer classes; Our average number of customers increased 2.4 percent over 1999, increasing revenue $6 million. Off-system sales Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy. $ (in thousands) MWh (in thousands) Revenue per MWh 2001 2000 1999 2001 2000 1999 2001 2000 1999 $219,966 $229,986 $119,785 2,387 4,529 5,924 $92.14 $50.78 $20.22 2001 vs. 2000: Off-system sales decreased due principally to a 47 percent decrease in volume sold, a result of poor hydro generating conditions. The volume decrease was partially offset by an 81 percent increase in price per MWh. 2000 vs. 1999: Off-system sales increased due predominantly to significant increases in prices for surplus system energy, which increased our average revenue per MWh by over 150 percent. A 24 percent decrease in volumes of electricity sold, due to decreased availability, partially offset the increase in market prices. Power Supply The power supply components of operating income include off-system sales (described and analyzed above) and purchased power, fuel and PCA expenses (analyzed below). The impact of the changes in net power supply costs was an increase in net power supply expense of $144 million in 2001 and $70 million in 2000. Purchased power $ (in thousands) MWh (in thousands) Cost per MWh 2001 2000 1999 2001 2000 1999 2001 2000 1999 $584,209 $398,649 $106,344 3,445 4,311 3,127 $169.58 $92.47 $34.01 2001 vs. 2000: Purchased power expenses increased $185 million in 2001. Contributing to these results are a number of factors, including wholesale market conditions, and $132 million of irrigation and Astaris load reduction program costs. 2000 vs. 1999: Purchased power expenses increased $293 million in 2000 due to major increases in prices in the energy markets, and to increased volumes purchased. The increase in volumes was necessitated by decreased generation at our hydroelectric plants and increased customer demand. Fuel expense Thermal MWh generated $ (in thousands) (in thousands) 2001 2000 1999 2001 2000 1999 $98,318 $94,215 $86,617 7,622 7,701 7,266 2001 vs. 2000: Expenses increased in 2001, despite decreased generation. Average coal prices increased, and our new 90-MWH gas- fired plant went on-line in September 2001. 2000 vs. 1999: Fuel expenses increased by $7 million in 2000, due primarily to increased generation at our coal-fired plants, necessitated by decreased generation at our hydroelectric plants and increased customer demand. Power Cost Adjustment The PCA component of expenses is related to IPC'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. We discuss the PCA in more detail in "Regulatory Issues - Power Cost Adjustment." 2001 vs. 2000: The PCA credit increased $55 million in 2001, due to 2001's power supply costs being greater than forecast, a result of higher prices and greater volumes of purchased power and the costs related to the load reduction programs that we introduced this year. 2000 vs. 1999: The PCA expense was a credit of $121 million in 2000, due predominantly to the considerable increases in purchased power costs not anticipated in our 2000-2001 rate year forecast. In 1999, actual power supply costs were near forecast, causing the PCA component of expense to be minimal. Other Utility Operating Expenses 2001 vs. 2000: Other operations and maintenance expenses increased $22 million in 2001. The most significant changes were: Depreciation and amortization expenses increased $7 million, due primarily to plant additions; Costs at thermal plants increased a total of $7 million, primarily due to unscheduled maintenance; Leased diesel generators to protect against electricity supply shortages, totaled $5 million; Operating costs related to the implementation of our new customer accounting system, and write-offs of uncollectible accounts increased $4 million. 2000 vs. 1999: Other operations and maintenance expenses in 2000 were substantially unchanged from 1999. The most significant changes were: Pension expenses decreased $7 million due to favorable returns on plan assets; Distribution line maintenance expenses increased $4 million, primarily due to increased tree clearing and pole maintenance; Operating costs related to our customer accounting system increased $2 million; Depreciation expenses increased $2 million, primarily due to plant additions. OTHER INCOME AND EXPENSES Other Income 2001 vs. 2000: The $7 million increase in other income results primarily from a $6 million increase in interest on deferred PCA balances. 2000 vs. 1999: The $6 million increase in other income is primarily the result of the transfer of IFS. In 1999 IFS recorded $6 million of amortization expense on affordable housing investments. IFS was transferred to IDACORP on January 1, 2000. Interest Charges 2001 vs. 2000: Interest charges increased $7 million in 2001, predominantly the result of higher short-term debt balances to finance power purchased for IPC's system, partially offset by significant decreases in borrowing rates. Our average short-term debt in 2001 was $145 million, compared to $21 million in 2000. 2000 vs. 1999: The $5 million decrease in interest charges is primarily the result of the transfer of IFS. In 1999 IFS recorded $6 million of interest expense related to affordable housing investments. Income taxes Fluctuations in income tax expense result primarily from changes in net income before taxes, and, for 2000, the transfer of IFS. IFS recorded $9 million in affordable housing credits in 1999. LIQUIDITY AND CAPITAL RESOURCES Cash Flow Operating cash flows and working capital levels declined in 2001, predominantly due to the growth in our PCA regulatory asset balance, reflecting increased power supply expenditures that we have not yet recovered through PCA rate adjustments. Our net cash generated from operations totaled $316 million for the three-year period 1999-2001. After deducting common dividends of $210 million, net cash generation from operations provided approximately $106 million for our construction program and other capital requirements. Internal cash generation after dividends provided 68 percent of our total capital requirements in 2000 and 105 percent in 1999. We forecast that internal cash generation after dividends will provide approximately 100 percent of total capital requirements in 2002 and 82 percent during the two-year period 2003-2004. We expect to continue financing our utility construction program and other capital requirements with both internally generated funds and, as discussed below, externally financed capital. The following table presents IPC's total contractual cash obligations: 2002 2003 2004 2005 2006 Thereafter (millions of dollars) Long-term debt $27 $80 $50 $60 $ - $612 Fuel supply contracts 38 33 30 27 19 11 At December 31, 2001, IPC had regulatory authority to incur up to $500 million of short-term indebtedness. At December 31, 2001, IPC's short-term borrowing totaled $282 million, consisting of $100 million of floating rate notes and $182 million of commercial paper, compared to $60 million of commercial paper at December 31, 2000. The increase is primarily a result of the unrecovered power supply expenditures mentioned above. IPC has a $165 million credit facility that expires April 26, 2002 and a $120 million facility that expires April 18, 2002. Under these facilities IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC's First Mortgage Bond Rating. IPC's commercial paper may be issued up to the amount supported by the bank credit facilities. We are currently in the process of renewing our credit lines, for $200 million, with closing anticipated in March 2002. Credit Ratings All of the Company's publicly traded debt have received investment grade ratings from each of the three major credit rating agencies. The changes in the energy industry and the recent bankruptcy of Enron Corp. have caused the rating agencies to refocus their attention on the credit characteristics and credit protection measures of industry participants and in some cases the rating agencies appear to have tightened the standards for a given rating level. The Company will continue to evaluate its capital structure, financing requirements, competitive strategies and future capital expenditures to try to maintain investment grade ratings. However, there is no assurance that these current ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downgrade or revision may adversely affect the market price of the Company's securities and serve to increase its cost of capital. Working Capital Net working capital (current assets less current liabilities) decreased approximately $156 million from December 31, 2000 to December 31, 2001. The most significant fluctuation was a $222 million increase in notes payable resulting from increased power supply expenditures that we have not yet recovered through rate adjustments. We discuss recovery of these costs in "Regulatory Issues" later in the MD&A. In addition, accounts payable decreased $95 million, due primarily to decreased purchased power payables resulting from decreased market prices and volumes purchased at December 31, 2001. Construction Program Our consolidated cash construction expenditures totaled $157 million in 2001, $132 million in 2000, and $108 million in 1999. Approximately 27 percent of these expenditures were for generation facilities, 20 percent for transmission facilities, 32 percent for distribution facilities, and 21 percent for general plant and equipment. We estimate that our cash construction and acquisition programs will require $124 million in 2002 and $267 million in 2003-2004. These estimates are subject to revision in light of changing economic, regulatory, environmental, and conservation factors. Financing Program Our consolidated capital structure fluctuated slightly during the period, with common equity ending at 46 percent, preferred stock 6 percent, and long-term debt 48 percent at December 31, 2001. At December 31, 2001, IPC also had $100 million of floating rate notes outstanding, payable on September 1, 2002 included in notes payable. In February 2002, IPC notified holders of its $50 million 8 3/4% First Mortgage Bonds due 2027 of its intent to redeem these bonds on March 15, 2002. In March 2000 IPC filed a $200 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes), unsecured debt, or preferred stock. In December 2000, $80 million of Secured Medium-Term Notes were issued by IPC. Proceeds from this issuance were used in January 2001 for the early redemption of $75 million of First Mortgage Bonds originally due in 2021. In March 2001, IPC issued $120 million of Secured Medium-Term Notes, with the proceeds used to reduce short-term borrowing incurred in support of ongoing long-term construction requirements. In August 2001, IPC filed a $200 million shelf registration that can be used for first mortgage bonds (including medium-term notes), unsecured debt, or preferred stock. At December 31, 2001, no amounts have been issued. In August 2001, $25 million of First Mortgage Bonds due in 2031 were redeemed early. In April 2000, at our request, the American Falls Reservoir District issued its American Falls Refunding Replacement Dam Bonds, Series 2000. Proceeds from issuance of these bonds, in the aggregate amount of $20 million, were used to refund the same amount of bonds dated May 1, 1990. IPC has guaranteed repayment of these bonds. In May 2000 $4 million of tax-exempt Pollution Control Revenue Refunding Bonds were issued by Port of Morrow, Oregon. Proceeds were used to refund in August 2000 the same amount of Pollution Control Revenue Bonds, Series 1978. CURRENT ISSUES In this section we address a number of other issues that affect or could affect our operations. Regulatory Issues Idaho Jurisdiction Power Cost Adjustment (PCA): IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail electric customers. Approved in 1992, the PCA was designed to pass through approximately 90 percent of the variance from forecasted net power supply costs. These adjustments, which take effect annually in May, are based on forecasts of net power supply expenses and the true- up of the prior year's forecast. During the year, the difference between the actual and forecasted costs is deferred with interest. The balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment. In the 2001 PCA filing, IPC requested recovery of $227 million of power supply costs. In May, the IPUC authorized recovery of $168 million, but deferred recovery of $59 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59 million the IPUC authorized recovery of $48 million plus $1 million of accrued interest, beginning in October 2001. The remaining $11 million not recovered in rates from the PCA filing was written off in September 2001. Of the $227 million requested by IPC, $185 million related to the true-up of power supply costs incurred in the 2000-2001 PCA year and $42 million was for recovery of excess power supply costs forecasted in the 2001-2002 PCA year. The forecast amount, however, underestimated expected power supply costs due to reservoir water levels coming in below forecast, necessitating the use of higher cost alternatives to hydro generation. Also market prices for purchased power were higher than forecast earlier in the PCA year. As part of the May 2001 PCA, the IPUC required us to implement a three-tiered rate structure for Idaho residential customers. The IPUC determined that the approved rates for residential customers should increase as customer's electricity consumption increases. The residential rate increases are 14.4 percent for the first 800 kWh of usage, 28.8 percent for the next 1,200 kWh, and 62 percent for the usage over 2,000 kWh. On October 18, 2001 IPC filed an application with the IPUC for an order approving the costs to be included in the 2002-2003 PCA for the Irrigation Load Reduction Program and the Astaris Load Reduction Agreement. These two programs were implemented in 2001 to reduce demand and were approved by the IPUC and the OPUC. The costs incurred in 2001 for these two programs were $70 million for the Irrigation Load Reduction Program and $62 million for the Astaris Load Reduction Agreement. On August 31, 2001 IPC filed a request with the IPUC to implement a rate credit to qualifying residential and small farm customers. The credit is the result of a settlement agreement between IPC and the Bonneville Power Administration (BPA), which will pass on the benefits of the Federal Columbia River Power System. IPC estimates the credit could be as much as $3.60 per month for residential customers who use 1,200 kWh per month and $300 per month for farm customers that use 100,000 kWh. The IPUC, by Order No. 28868, approved the credit to be passed to the qualified customers effective October 1, 2001. In its May 2001 rate authorization the IPUC also directed IPC to reinstate a comprehensive conservation program given the current volatility of market prices and the opportunity to incorporate long- term conservation. In response to that directive, IPC filed a report of present energy efficiency activities, a list of conservation measures, an examination of funding options and a detailed program structure that could be implemented should the Commission determine that additional conservation programs, including the funding of these programs, is in the public interest. The Commission has delayed further deliberations until the spring of 2002. So far in the 2001-2002 rate year actual power supply costs included in the PCA have been significantly greater than forecast due to purchased power volumes and prices being greater than originally forecasted and the implementation of the voluntary load reduction programs with Astaris and the irrigation customers. To account for these higher-than-forecasted costs and the unamortized portion of the 2000-2001 PCA balance, IPC has recorded a regulatory asset of $290 million as of December 31, 2001. The May 2000 rate adjustment increased Idaho general business customer rates by 9.5 percent, and resulted from forecasted below- average hydroelectric generating conditions. Overall, the PCA adjustment increased general business revenue by approximately $38 million during the 2000-2001 rate period, partially offsetting the forecasted increase in power supply 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 1999-2000 rate period and a true-up from the 1998-1999 rate period. Overall, the May 1999 rate adjustment decreased annual general business revenue by approximately $40 million during the 1999-2000 rate period. Regulatory Settlement: IPC had a settlement agreement with IPUC that expired at the end of 1999. Under the terms of the settlement, when earnings in IPC's Idaho jurisdiction exceeded an 11.75 percent return on the year-end common equity, IPC set aside 50 percent of the excess for the benefit of the Idaho retail customers. In March 2000 IPC submitted its 1999 annual earnings sharing compliance filing to the IPUC. This filing indicated that there was almost $10 million in 1999 earnings and $3 million in unused 1998 reserve balances available for the benefit of our Idaho customers. In April 2000 the IPUC issued Order 28333, which ordered that $7 million of the revenue sharing balance be refunded to Idaho customers through rate reductions effective May 16, 2000. The Order also approved IPC's continued participation in the Northwest Energy Efficiency Alliance for the years 2000-2004, ordering IPC to set aside the remaining $6 million of revenue sharing dollars to fund that participation. Demand-Side Management (Conservation) Expenses (DSM): IPC requested that the IPUC allow for the recovery of post-1993 DSM expenses and acceleration of the recovery of DSM expenditures authorized in the last general rate case. In its Order No. 27660 issued on July 31, 1998, the IPUC set a new amortization period of 12 years instead of the 24-year period previously adopted. On April 17, 2000, the Idaho Supreme Court affirmed the IPUC order, after hearing an appeal by a group of industrial customers. On February 23, 2001 the IPUC approved IPC's Green Energy Purchase Program. The Green Program is an optional program available to all IPC customers in Idaho, allowing them to pay a premium to purchase energy generated by alternative sources such as solar and wind. Creating the Green Program will provide additional means for customers to stimulate demand for new green resources and their development. Oregon Jurisdiction IPC filed an application with the OPUC to begin recovering extraordinary 2001 power supply costs in its Oregon jurisdiction. On June 18, 2001, the OPUC approved new rates that would recover $1 million over the next year. Under the provisions of the deferred accounting statute, annual rate recovery amounts were limited to three percent of IPC's 2000 gross revenues in Oregon. During the 2001 session, the Oregon Legislature amended the statute giving the OPUC authority to increase the maximum annual rate of recovery of deferred amounts to six percent for electric utilities. IPC subsequently filed on October 5, 2001 to recover an additional three percent extraordinary deferred power supply costs. As a result of this filing, the OPUC issued Order No. 01-994 allowing IPC to increase its rate of recovery to six percent effective November 28, 2001. The Oregon deferral balance is $15 million as of December 31, 2001, net of the June 18, 2001 and November 28, 2001 recovery. IPC filed with the OPUC a request to implement the same BPA program as in Idaho. The OPUC held a public meeting on October 22, 2001 and subsequently approved IPC's request to implement the BPA Residential and Small Farm Energy Credit for the benefits derived during the period October 1, 2001 through September 30, 2006. In 1998, IPC received authority from the OPUC to reduce the amortization period for the regulatory assets associated with DSM programs from 24 years to 5 years. The OPUC also approved additional Oregon allocated DSM expenditures for recovery through rates. The Oregon costs will be recovered by extending an existing surcharge until the amounts are collected. Nevada Jurisdiction The IPUC and PUCN approved IPC's sale of its Nevada service territory to Raft River Electric Co-Op (Raft River). This sale transferred the distribution facilities and rights-of-way that serve about 1,250 customers in northern Nevada and about 90 customers in southern Idaho. The FERC approved a power supply agreement between IPC and Raft River. This sale will allow IDACORP to participate in a deregulated electric utility market in Nevada should that state resume deregulation activities. New Idaho Legislation Idaho Senate Bill No. 1255, chapter 15, title 61, Idaho Code (the Act), was signed into law on April 10, 2001. It authorizes the IPUC to allow public utilities or their assignees to issue energy cost recovery bonds to finance, among other things, significant increases in the cost of electricity resulting from shortfalls in available hydroelectric power for which higher-cost replacement power must be substituted. The legislative intent of the Act is to provide utilities with a mechanism for recovery of these increased costs while leveling the rate impact of such increases on the utilities' customers. Energy cost recovery bonds must have an expected maturity date no later than five years after issuance and a legal maturity date no later than seven years after issuance. Under the Act, the IPUC may issue an energy cost financing order in favor of the utility, pursuant to which a charge, known as an energy cost bond charge, would be included on the bills of the utility's Idaho customers. The Act requires the energy cost bond charge to remain in effect until the energy cost recovery bonds are paid in full. In addition, the charge is subject to periodic adjustment to ensure the timely payment of principal and interest on the energy cost recovery bonds and the recovery of certain related expenses. An energy cost financing order creates energy cost property, which includes the right to receive revenues arising from the energy cost bond charge. Energy cost property may be sold or otherwise transferred to, among others, the assignee of the public utility that issues energy cost recovery bonds, and it may be pledged as security for such bonds. The Act requires that, before it issues an energy cost financing order, the IPUC must find that the public interest would be better served if increased costs reflected in a fuel or power cost adjustment and related expenses were recovered through the issuance of energy cost recovery bonds than if these amounts were recovered over a one-year period assuming a conventional financing. Before seeking to recover costs through the issuance of energy bonds, IPC must file with the IPUC a proposal to establish a threshold energy cost amount, or trigger. In June 2001, the IPUC approved IPC's application, establishing a one cent per kWh trigger amount. Electric Industry Restructuring 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. Integrated Resource Plan (IRP) Every two years, IPC is required to file with the IPUC and OPUC an IRP, a comprehensive look at IPC's present and future demands for electricity and plan for meeting that demand. The 2000 IRP identified a potential electricity shortfall within our utility service territory by mid-2004. The plan projected a 250-MW resource need in 2004 to satisfy energy demand during IPC's peak periods. The IRP calls for IPC to use purchases from the Northwest energy markets to meet short-term energy needs. The 2000 IRP anticipates that after 2004, transmission constraints will not allow IPC to continue to cover increasing demand using wholesale purchases from the Pacific Northwest. As a result of the 2000 IRP, IPC issued a request for proposals (RFP), seeking bids for 250 MW of additional generation to support the growing demand in IPC's utility service territory. A proposal by Garnet Energy LLC, a subsidiary of Ida-West, was selected by IPC. In December 2001 IPC signed an agreement with Garnet to define the conditions under which the utility will purchase energy to be produced by Garnet's 273-MW natural gas-fired combined cycle combustion turbine facility in Canyon County, Idaho, located in the southwest part of the state. In December 2001, IPC filed an application with the IPUC requesting authorization to include Garnet related expenses in IPC's PCA. Regional Transmission Organizations IPC has a long history of providing wholesale transmission services. IPC provides various firm and non-firm wheeling services for several surrounding utilities. In December 1999 the FERC, in its landmark Order 2000, said that all companies with transmission assets must file to form regional transmission organizations (RTOs) or explain why they cannot. Order 2000 is a follow up to orders 888 and 889 issued in 1996, which required transmission owners to provide non- discriminatory transmission service to third parties. By encouraging the formation of RTOs, FERC seeks to further facilitate the formation of efficient, competitive wholesale electricity markets. In response to FERC Order 2000, IPC and other regional transmission owners filed in October 2000 a plan to form RTO West, an entity that will operate the transmission grid in seven western states. RTO West will have its own independent governing board. The participating transmission owners will retain ownership of the lines, but will not have a role in operating the grid. The previous FERC filing represents a portion of the filing necessary to form RTO West. However, substantial additional filings will be necessary to include the tariff and integration agreements associated with the new entity. There will also need to be filings for state approvals. We expect the "Stage 2" FERC filings to be completed by March 2002. State filings may be initiated in 2002. Relicensing of Hydroelectric Projects IPC, like other utilities that operate nonfederal hydroelectric projects, has obtained licenses for its hydroelectric projects from the FERC. These licenses generally last for 30 to 50 years depending on the size of the project. By 2010, the licenses for eight of our hydro projects will have expired. We are actively pursuing the relicensing of these 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 filed applications seeking renewal of licenses for our Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, and Shoshone Falls Hydroelectric Projects. The licenses for the Upper and Lower Malad Project expires in 2004, the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon dams) in 2005, and the Swan Falls Project in 2010. We are currently engaged in procedures necessary to file timely license applications for each of these projects. Although various federal and state requirements and issues must be resolved through the license renewal process, we anticipate that we will relicense each of the 10 facilities. At this point, however, we cannot predict what type of environmental or operational requirements we may face, nor can we estimate the cost of license renewal. At December 31, 2001, $39 million of relicensing costs were included in Construction Work in Progress. Market Risk 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, 2001. We buy and sell electricity as part of our ongoing utility operations. These operations are subject to commodity price risk. We are exposed to this risk to the extent that a portion of the electric energy we are required to sell to our customers at fixed rates may be purchased at wholesale electric market prices, which can be higher than the fixed sales rate we receive. Our exposure to this risk is largely offset by the PCA mechanism in place in Idaho, which we discussed previously. The objective of our market price risk management program is to mitigate the risk associated with the purchase and sale of electricity, while balancing this risk against system reliability and cost considerations. Our Risk Management Committee (RMC), comprised of IPC officers, oversees the risk management program. On a regular basis, our RMC reviews multiple system resource and load projections and evaluates the potential impacts of changes in three key variables, wholesale prices, system loads and system resources. The RMC controls the risk by assessing the impact of changes in the variables on PCA deferral balances and projected volumetric surplus and deficit data, and by reviewing forward price curves for electricity. The RMC then takes an appropriate risk mitigating action. We have no foreign exchange exposure, and, except for the transferred energy-marketing operations, have not transacted in interest rate futures and swaps. With the June 2001 transfer of our non-utility energy marketing operations to IE, IPC no longer holds for trading purposes any derivative or derivative commodity instruments. Interest Rate Risk The majority of our debt is held in fixed rate securities with embedded call options. We owe $72 million in variable-rate tax- exempt debt, and 25 percent of our total debt is variable in the form of commercial paper or short-term notes. 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 following table presents the principal cash flows by maturity date and the related average interest rate for our fixed-rate debt at December 31, 2001. The table also presents the fair value of these fixed rate instruments, based on market rates for similar instruments as of that date. Average Expected interest Maturity Date Amount due rate (millions of dollars) 2002 $ 27 6.8% 2003 80 6.4% 2004 50 8.0% 2005 60 5.8% 2006 - - Thereafter 540 7.3% Total $ 757 7.1% Fair Value $ 795 Environmental 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 November of 1991, the National Marine Fisheries Service (NMFS) listed the Snake River Sockeye Salmon as endangered under the Endangered Species Act (ESA). Subsequently, in April 1992, NMFS listed the Snake River Fall Chinook and the Snake River Spring/Summer Chinook as threatened under the ESA. Only the Snake River Fall Chinook inhabit the Snake River in the vicinity of our three-dam Hells Canyon Complex (HCC). These listings have not had any major effects on our operations. In 1991, IPC voluntarily initiated a Fall Chinook Interim Recovery Plan and Study intended to address concerns relative to Fall Chinook spawning immediately below Hells Canyon Dam. Since the inception of that plan, IPC has been managing releases from the HCC during the Fall Chinook spawning season to provide stable conditions for spawning Fall Chinook below Hells Canyon Dam. These conditions are maintained through fry emergence in the spring. In connection with the relicensing of the HCC, IPC is engaged in ongoing discussions with the FERC and NMFS relative to ESA issues associated with the HCC. In December 2000, NMFS issued a final Biological Opinion (BiOp) on the operation of the Federal Columbia River Power System (FCRPS). This BiOp resulted from ESA Section 7 consultation on the operations of the federal projects operated by the U.S. Army Corps of Engineers and U.S. Bureau of Reclamation on the lower Snake and Columbia Rivers. It did not relate to the operations of our HCC and did not call for any changes in the operations of the HCC. In May of 2001, NMFS issued a final BiOp on the operations of the U.S. Bureau of Reclamation (BOR) projects in the Snake River basin above the HCC. This BiOp was interim in nature, expiring in March 2002. NMFS and the BOR are currently negotiating an extension of this BiOp for subsequent years operations. Portions of the 2000 FCRPS BiOp and the 2001 BOR BiOp provide for the acquisition of water from Idaho by the BOR in order to provide augmentation flows to assist with the downstream migration of ESA listed anadromous fish through the lower Snake River FCRPS projects. For the past several years, the BOR has been leasing water from willing lessors in Idaho in an effort to provide the augmentation flows. In connection with these flow augmentation efforts, IPC has been cooperating with the federal agencies by moving and shaping water acquired by the BOR through the HCC. In the past, IPC has been reimbursed for any energy losses incurred as a result of this cooperation through an agreement with the BPA. While this agreement expired in April of 2001, IPC has advised federal interests of its willingness to continue to assist with the movement and shaping of federal flow augmentation water provided any adverse impact to its customers is satisfactorily addressed. 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 listing as an issue 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. During relicensing, the FERC is required by the Endangered Species Act (Section 7) to consult with the USFWS. This consultation has been requested by the FERC. 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. IPC has sufficient SO2 allowances to provide compliance for all three coal-fired facilities and the Danskin natural gas-fired facility. Therefore, we foresee no adverse effects on our operations with regard to SO2 emissions. New Accounting Pronouncements In July 2001 the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 141, "Business Combinations," which addresses accounting and reporting for business combinations. SFAS 141 requires that all business combinations initiated after June 30, 2001 be accounted for using one method, the purchase method. The adoption of SFAS 141 did not have a significant effect on our financial statements. Also in July 2001 the FASB issued SFAS 142, "Goodwill and Other Intangible Assets," which is effective January 1, 2002. SFAS 142 changes the accounting for goodwill from an amortization method to an impairment-only method. Thus, amortization of goodwill, including goodwill recorded in past transactions, will cease. IPC will be required to complete transitional goodwill impairment tests within six months of the date of adoption, and at least annually thereafter. The standard also includes provisions for the reclassification of certain existing recognized intangibles to goodwill, reassessment of the useful lives of existing recognized intangibles and reclassification of certain intangibles out of goodwill. The adoption of SFAS 142 did not have a significant effect on our financial statements. In August 2001 the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which is effective for fiscal years beginning after June 15, 2002. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset. IPC is currently assessing but has not yet determined the impact of SFAS 143 on our financial position and results of operations. Also in August 2001 the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which is effective for fiscal years beginning after December 15, 2001. SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets, superseding SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." IPC is currently assessing but has not yet determined the impact of SFAS 144 on its financial position and results of operations. Critical Accounting Policies IPC follows SFAS 71, "Accounting for the Effects of Certain Types of Regulation," and our financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating IPC. The primary result of this policy is that IPC has deferred $600 million of regulatory assets at December 31, 2001. Of this amount, $305 million relates to current year power supply expenditures. While we expect to fully recover this amount, such recovery is subject to final review by the regulatory entities. 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 Risk." ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE PAGE Management's Responsibility for Financial Statements 31 Consolidated Financial Statements: Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999 33 Consolidated Balance Sheets as of December 31, 2001 and 2000 34-35 Consolidated Statements of Capitalization as of December 31, 2001 and 2000 36 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 37 Consolidated Statements of Retained Earnings and Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999 38 Notes to Consolidated Financial Statements 39 Independent Auditors' Report 54 Supplemental Financial Information and Financial Statement Schedule Supplemental Financial Information (Unaudited) 55 Financial Statement Schedule for the Years Ended December 31, 2001, 2000 and 1999: Schedule II-Consolidated Valuation and Qualifying Accounts 60 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Idaho Power Company is responsible for the preparation and presentation of the information and representations contained in the accompanying financial statements. The financial statements have been prepared in conformance with generally accepted accounting principles. 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. IPC maintains systems of internal accounting controls and related policies and procedures. The systems are designed to provide reasonable assurance that all assets are protected against loss or unauthorized use. Also, the systems provide that transactions are executed in accordance with management's authorization and properly recorded to permit preparation of reliable financial statements. The systems are supported by a staff of corporate accountants and internal auditors who, among other duties, evaluate and monitor the systems of internal accounting control in coordination with the independent auditors. The staff of internal auditors conducts special and operational audits in support of these accounting controls throughout the year. The Board of Directors, through its Audit Committee comprised entirely of outside directors, meets periodically with management, internal auditors and independent auditors to discuss auditing, internal control and financial reporting matters. To ensure their independence, both the internal auditors and independent auditors have full and free access to the Audit Committee. The financial statements have been audited by Deloitte & Touche LLP, IPC's independent auditors, who were responsible for conducting their audit in accordance with generally accepted auditing standards. J. LaMont Keen Darrel T. Anderson President and Chief Vice President, Chief Financial Operating Officer Officer and Treasurer Idaho Power Company Consolidated Statements of Income Year Ended December 31, 2001 2000 1999 (thousands of dollars) REVENUES: General business $ 650,608 $ 565,357 $ 516,148 Off-system sales 219,966 229,986 119,785 Other revenues 41,738 40,319 22,403 Total revenues 912,312 835,662 658,336 EXPENSES: Operation: Purchased power 584,209 398,649 106,344 Fuel expense 98,318 94,215 86,617 Power cost adjustment (175,925) (120,688) (502) Other 153,079 146,424 151,800 Maintenance 55,877 46,973 42,067 Depreciation 87,041 80,287 77,833 Taxes other than income taxes 19,693 20,166 21,719 Total expenses 822,292 666,026 485,878 INCOME FROM OPERATIONS 90,020 169,636 172,458 OTHER INCOME: Allowance for equity funds used during construction 752 2,565 1,667 Other - net 19,847 11,389 6,369 Total other income 20,599 13,954 8,036 INTEREST CHARGES: Interest on long-term debt 55,704 53,253 54,150 Other interest 10,402 4,544 7,864 Allowance for borrowed funds used during construction (3,737) (2,346) (1,392) Total interest charges 62,369 55,451 60,622 INCOME BEFORE INCOME TAXES 48,250 128,139 119,872 INCOME TAXES 19,955 48,171 36,407 INCOME FROM CONTINUING OPERATIONS 28,295 79,968 83,465 DISCONTINUED OPERATIONS: Income from operations of energy marketing transferred to parent (net of tax of $33,574, $37,397 and $9,143) 49,943 57,520 14,063 NET INCOME 78,238 137,488 97,528 Dividends on preferred stock 5,400 5,929 5,572 EARNINGS ON COMMON STOCK $ 72,838 $131,559 $ 91,956 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Assets December 31, 2001 2000 (thousands of dollars) ELECTRIC PLANT: In service (at original cost) $2,989,630 $2,799,590 Accumulated provision for depreciation (1,220,002) (1,142,572) In service - Net 1,769,628 1,657,018 Construction work in progress 86,010 130,477 Held for future use 2,232 2,167 Electric plant - Net 1,857,870 1,789,662 INVESTMENTS AND OTHER PROPERTY 37,432 21,502 CURRENT ASSETS: Cash and cash equivalents 43,040 83,494 Receivables: Customer 58,702 74,225 Allowance for uncollectible accounts (1,500) (1,397) Notes 3,488 2,945 Employee notes 6,274 4,742 Related parties 37,517 311 Other 2,280 4,943 Taxes receivable 8,244 - Accrued unbilled revenues 37,400 44,825 Materials and supplies (at average cost) 23,280 24,685 Fuel stock (at average cost) 8,726 5,105 Prepayments 31,897 24,145 Regulatory assets 55,107 8,672 Net assets of discontinued operations - 37,702 Total current assets 314,455 314,397 DEFERRED DEBITS: American Falls and Milner water rights 31,585 31,585 Company-owned life insurance 39,602 39,554 Regulatory assets 544,134 370,535 Other 34,626 49,857 Total deferred debits 649,947 491,531 TOTAL $2,859,704 $2,617,092 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Balance Sheets Capitalization and Liabilities December 31, 2001 2000 (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 Premium on capital stock 362,602 362,430 Capital stock expense (4,144) (4,024) Retained earnings 316,856 313,800 Accumulated other comprehensive income (loss) (3,719) (921) Total common stock equity 765,626 765,316 Preferred stock 104,387 105,066 Long-term debt 802,201 808,977 Total capitalization 1,672,214 1,679,359 CURRENT LIABILITIES: Long-term debt due within one year 27,078 30,077 Notes payable 282,000 59,700 Accounts payable 68,806 164,237 Notes and accounts payable to related parties 6,931 4,212 Taxes accrued - 12,983 Derivative liabilities 40,528 - Interest accrued 13,115 15,002 Deferred income taxes 14,578 8,672 Other 16,118 18,460 Total current liabilities 469,154 313,343 DEFERRED CREDITS: Deferred income taxes 541,482 452,404 Derivative liabilities - long-term 7,253 - Regulatory liabilities 113,957 110,901 Other 55,644 61,085 Total deferred credits 718,336 624,390 COMMITMENTS AND CONTINGENT LIABILITIES TOTAL $2,859,704 $2,617,092 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Capitalization December 31, 2001 % 2000 % (thousands of dollars) COMMON STOCK EQUITY: Common stock $ 94,031 $ 94,031 Premium on capital stock 362,602 362,430 Capital stock expense (4,144) (4,024) Retained earnings 316,856 313,800 Accumulated other comprehensive income (loss) (3,719) (921) Total common stock equity 765,626 46 765,316 46 PREFERRED STOCK: 4% preferred stock 14,387 15,066 7.68% Series, serial preferred stock 15,000 15,000 7.07% Series, serial preferred stock 25,000 25,000 Auction rate preferred stock 50,000 50,000 Total preferred stock 104,387 6 105,066 6 LONG-TERM DEBT: First mortgage bonds: 6.93% Series due 2001 - 30,000 6.85% Series due 2002 27,000 27,000 6.40% Series due 2003 80,000 80,000 8 % Series due 2004 50,000 50,000 5.83% Series due 2005 60,000 60,000 7.38% Series due 2007 80,000 80,000 7.20% Series due 2009 80,000 80,000 6.60% Series due 2011 120,000 - Maturing 2021 through 2031 with rates ranging from 7.5% to 9.52% 130,000 230,000 Total first mortgage bonds 627,000 637,000 Amount due within one year (27,000) (30,000) Net first mortgage bonds 600,000 607,000 Pollution control revenue bonds: 8.30% Series 1984 due 2014 49,800 49,800 6.05% Series 1996A due 2026 68,100 68,100 Variable Rate Series 1996B due 2026 24,200 24,200 Variable Rate Series 1996C due 2026 24,000 24,000 Variable Rate Series 2000 due 2007 4,360 4,360 Total pollution control revenue bonds 170,460 170,460 REA notes 1,263 1,339 Amount due within one year (78) (77) Net REA notes 1,185 1,262 American Falls bond guarantee 19,885 19,885 Milner Dam note guarantee 11,700 11,700 Unamortized premium/discount - Net (1,029) (1,330) Total long-term debt 802,201 48 808,977 48 TOTAL CAPITALIZATION $1,672,214 100 $1,679,359 100 The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Cash Flows Year Ended December 31, 2001 2000 1999 (thousands of dollars) OPERATING ACTIVITIES: Net income $ 78,238 $ 137,488 $ 97,528 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Allowance for uncollectible accounts 20,277 21,682 - Unrealized (gains) losses (100,653) 21,847 (3,502) Depreciation and amortization 99,565 92,677 95,154 Deferred taxes and investment tax credits 103,425 44,911 (1,747) Accrued PCA costs (184,584) (122,353) (891) Change in: Receivables and prepayments (20,837) (165,759) (489) Accrued unbilled revenue 7,425 (12,831) 2,616 Materials and supplies and fuel stock (2,216) 5,544 (1,050) Accounts payable (26,142) 156,932 28,397 Taxes (receivable) accrued (21,227) (8,326) (3,391) Other current assets and liabilities (2,081) (3,572) 4,710 Other - net (10,788) (6,843) (3,490) Net cash provided by (used in) operating activities (59,598) 161,397 213,845 INVESTING ACTIVITIES: Additions to utility plant (156,787) (131,711) (108,498) Investments in affordable housing projects - - (19,554) Investments in company - owned life insurance - - (5,862) Note receivable payment from parent 42,743 - - Net cash of affiliates transferred to parent - (4,737) - Other - net 149 838 (3,066) Net cash used in investing activities (113,895) (135,610) (136,980) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 120,000 80,000 80,000 Pollution control revenue bonds - 4,360 - Long-term debt related to affordable housing projects - - 18,730 Retirement of: First mortgage bonds (130,000) (80,000) - Pollution control revenue bonds - (4,360) - Long-term debt related to affordable housing projects - - (9,650) Subsidiary debt - - (165) Dividends on common stock (69,782) (69,850) (69,912) Dividends on preferred stock (5,400) (5,929) (5,572) Increase (decrease) in short- 222,300 39,943 (14,607) term borrowings Other - net (4,079) (1,495) (680) Net cash provided by (used in) financing activities 133,039 (37,331) (1,856) Net increase (decrease) in cash and cash equivalents (40,454) (11,544) 75,009 Cash and cash equivalents at beginning of period 83,494 95,038 20,029 Cash and cash equivalents at end of period $ 43,040 $ 83,494 $ 95,038 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (received) during the period for: Income taxes $ (28,510) $ 47,732 $ 50,532 Interest (net of amount capitalized) $ 61,600 $ 58,090 $ 55,186 Net non-cash assets of affiliates transferred to parent $ - $ 17,353 $ - Net assets transferred to parent for notes receivable $ 76,250 $ - $ - The accompanying notes are an integral part of these statements. Idaho Power Company Consolidated Statements of Retained Earnings Year Ended December 31, 2001 2000 1999 (thousands of dollars) RETAINED EARNINGS, BEGINNING OF YEAR $313,800 $274,181 $252,137 NET INCOME 78,238 137,488 97,528 Total 392,038 411,669 349,665 DIVIDENDS: Common stock ($1.86 per share) (69,782) (69,850) (69,912) Preferred stock (5,400) (5,929) (5,572) TRANSFER TO IDACORP, INC. - (22,090) - RETAINED EARNINGS, END OF YEAR $316,856 $313,800 $274,181 The accompanying notes are an integral part of these statements. Consolidated Statements of Comprehensive Income Year Ended December 31, 2001 2000 1999 (thousands of dollars) NET INCOME $ 78,238 $137,488 $ 97,528 OTHER COMPREHENSIVE INCOME (LOSS): Unrealized gains on securities (net of tax of ($1,044), ($1,713) and $677) (1,770) (2,335) 1,017 Minimum pension liability adjustment (net of tax of ($649), ($78) and $189) (1,028) (119) 291 TOTAL COMPREHENSIVE INCOME $ 75,440 $135,034 $ 98,836 The accompanying notes are an integral part of these statements. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Nature of Business Idaho Power Company (IPC) is an electric utility 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. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to IPC's Jim Bridger generating plant. The outstanding shares of IPC's common stock were exchanged on a share-for-share basis into common stock of IDACORP, Inc. (IDACORP) on October 1, 1998 and are no longer actively traded. IPC's preferred stock and debt securities were unaffected and remain outstanding with IPC. Effective June 11, 2001 IPC transferred its wholesale electricity marketing operations (Energy Marketing) to IDACORP Energy (IE), see Note 11 "Discontinued Operations." After the transfer of Energy Marketing, all of IPC consists of one operating segment, Utility Operations. The Utility Operations segment has two primary sources of income, the regulated operation of IPC and income from its joint venture in Bridger Coal Company. Principles of Consolidation The consolidated financial statements include the accounts of IPC and its wholly-owned subsidiary. All significant intercompany transactions and balances have been eliminated in consolidation. Investments in business entities in which IPC and its subsidiary 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. Property, Plant and Equipment The cost of additions to utility 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 expensed to operations. IPC records repair and maintenance costs associated with planned major maintenance as these costs are incurred. 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 property, plant and equipment. Allowance for Funds Used During Construction (AFDC) AFDC, a non-cash item, represents the composite interest costs of debt, and a return on equity funds, used to finance utility 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 2001, 2000 and 1999 were 5.4 percent, 8.3 percent, and 7.8 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. Derivative Financial Instruments Prior to the June 11 transfer of Energy Marketing to IE (Note 11), IPC used financial instruments such as commodity futures, forwards, options and swaps to manage exposure to commodity price risk in the electricity markets. The objective of IPC's risk management program was to mitigate the risk associated with the purchase and sale of electricity as well as to optimize its energy marketing portfolio. The accounting for derivative financial instruments used to manage risk were in accordance with the concepts established in EITF 98-10, "Accounting for Contracts Involved in Energy Trading Activities," and SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities." Power Cost Adjustment (PCA) IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail electric customers. These adjustments, which take effect annually in May, are based on forecasts of net power supply expenses and the true-up of the prior year's forecast. During the year, the difference between the actual and forecasted costs is deferred with interest. The balance of this deferral, called a true-up, is then included in the calculation of the next year's PCA adjustment. Depreciation All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.98 percent in 2001 and 2.94 percent in 2000 and 1999. Income Taxes IPC 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 Idaho Public Utility Commission (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). IPC's operations are included in IDACORP's consolidated federal and state income tax returns. The income tax expense and deferred income taxes payable included in the accompanying consolidated financial statements for 2001 and 2000 are determined after considering all income and expense items and tax credits generated by the consolidated group. The tax receivable is classified based upon the time period in which cash settlement to IDACORP is expected to occur. The State of Idaho allows a three-percent investment tax credit (ITC) upon certain qualifying plant additions. ITC's 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. Stock Based Compensation SFAS 123, "Accounting for Stock-Based Compensation" encourages a fair-value based method of accounting for stock-based compensation. As permitted by SFAS 123, IPC adopted disclosure-only requirements and continues to account for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees" (APB 25), as interpreted by Financial Accounting Standards Board (FASB) Interpretation 44 "Accounting for Certain Transactions Involving Stock Compensation," and various EITF issues. 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 accounting principles generally accepted in the United States of America, 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 IPC follows SFAS 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. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). Comprehensive Income Components of IPC's comprehensive income include net income, unrealized holding gains (losses) on marketable securities, IPC's proportionate share of unrealized holding gains (losses) 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 July 2001 the FASB issued SFAS 141, "Business Combinations," which addresses accounting and reporting for business combinations. SFAS 141 requires that all business combinations initiated after June 30, 2001 be accounted for using one method, the purchase method. The adoption of SFAS 141 did not have a significant effect on IPC's financial statements. Also in July 2001 the FASB issued SFAS 142, "Goodwill and Other Intangible Assets," which is effective January 1, 2002. SFAS 142 changes the accounting for goodwill from an amortization method to an impairment-only method. Thus, amortization of goodwill, including goodwill recorded in past transactions will cease. IPC will be required to complete transitional goodwill impairment tests within six months of the date of adoption, and at least annually thereafter. The standard also includes provisions for the reclassification of certain existing recognized intangibles to goodwill, reassessment of the useful lives of existing recognized intangibles and reclassification of certain intangibles out of goodwill. The adoption of SFAS 142 did not have a significant effect on IPC's financial statements. In August 2001 the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations," which is effective for fiscal years beginning after June 15, 2002. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. An obligation may result from the acquisition, construction, development and the normal operation of a long-lived asset. IPC is currently assessing but has not yet determined the impact of SFAS 143 on its financial position and results of operations. Also in August 2001 the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which is effective for fiscal years beginning after December 15, 2001. SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets, superseding SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to be Disposed of." IPC is currently assessing but has not yet determined the impact of SFAS 144 on its 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 2001 have been reclassified to conform to the current year's presentation. Net income and common stock equity were not affected by these reclassifications. 2. INCOME TAXES: IPC has settled Federal and Idaho tax liabilities on all open years through the 1997 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: 2001 2000 1999 (thousands of dollars) Computed income taxes based on statutory federal income tax rate $ 46,118 $ 78,070 $ 50,077 Change in taxes resulting from: AFDC (1,571) (1,719) (1,071) Investment tax credits (3,169) (3,083) (3,032) Repair allowance (2,800) (4,550) (2,800) Settlement of prior years tax - 2 (478) returns State income taxes (net of 4,313 9,465 5,475 Federal reduction) Depreciation 9,790 8,243 7,292 Affordable housing tax - - (8,934) credits Other 848 (860) (979) Total provision for federal and state income taxes $ 53,529 $ 85,568 $ 45,550 Effective tax rate 40.6% 38.4% 31.8% The provision for income taxes consists of the following: 2001 2000 1999 (Thousand of Dollars) Income taxes currently (receivable) payable: Federal $(37,352) $ 35,259 $ 38,169 State (12,544) 5,398 9,128 Total (49,896) 40,657 47,297 Income taxes deferred - Net of amortization: Federal 84,372 38,887 2,246 State 17,087 7,407 (2,030) Total 101,459 46,294 216 Investment tax credits: Deferred 5,135 1,700 1,069 Restored (3,169) (3,083) (3,032) Total 1,966 (1,383) (1,963) Total provision for income taxes $ 53,529 $ 85,568 $ 45,550 The tax effects of significant items comprising IPC's net deferred tax liability are as follows: 2001 2000 (thousands of dollars) Deferred tax assets: Regulatory liabilities $ 41,290 $ 40,230 Advances for construction 3,941 9,224 Other 16,825 23,586 Total 62,056 73,040 Deferred tax liabilities: Electric plant 250,180 249,546 Regulatory assets 209,832 213,552 Conservation programs 11,138 13,561 PCA 119,436 47,189 Other 27,530 10,268 Total 618,116 $534,116 Net deferred tax liabilities $556,060 $461,076 3. PREFERRED STOCK: The number of shares of preferred stock outstanding at December 31, 2001 and 2000 were as follows: Shares Outstanding at Call Price December 31, Per Share 2001 2000 Preferred stock: Cumulative, $100 par value: 4% preferred stock (authorized 215,000 shares) 143,872 150,656 $104.00 Serial preferred stock, 7.68% Series (authorized 150,000 shares) 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 $103.535 to $100.354 Auction rate preferred stock, $100,000 stated value (authorized 500 shares)(b) 500 500 $100,000.00 Total 544,372 551,156 (a) The preferred stock is not redeemable prior to July 1, 2003. (b) Dividend rate at December 31, 2001 was 3.65% and ranged between 3.12% and 4.95% during the year. During 2001 and 2000 IPC reacquired and retired 6,784 and 7,456 shares of 4% preferred stock. As of December 31, 2001, the overall effective cost of all outstanding preferred stock was 5.13 percent. 4. LONG-TERM DEBT: At December 31, 2001, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars): 2002 $ 27,078 2003 80,083 2004 50,077 2005 60,080 2006 82 Thereafter 611,879 Total $829,279 On March 23, 2000, IPC filed a $200 million shelf registration statement that could be used for First Mortgage Bonds (including medium term notes), unsecured debt, or preferred stock. On December 1, 2000, IPC issued $80 million principal amount of Secured Medium Term Notes, Series C, 7.38% Series due 2007. Proceeds were used for the early redemption in January 2001 of the $75 million First Mortgage Bonds 9.50% Series due 2021. On March 2, 2001, IPC issued $120 million principal amount of Secured Medium Term Notes, Series C, 6.60% Series due 2011 with the proceeds used to reduce short-term borrowing incurred in support of ongoing long-term construction requirements. At December 31, 2001, no amount remained to be issued on this shelf registration statement. On August 16, 2001, IPC filed a $200 million shelf registration statement that can be used for First Mortgage Bonds (including medium-term notes), unsecured debt or preferred stock. At December 31, 2001, no amounts had been issued. In August 2001, $25 million First Mortgage Bonds 9.52% Series due 2031 were redeemed early. The amount of first mortgage bonds issuable by IPC is limited to a maximum of $900 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. On April 26, 2000, at the request of IPC, the American Falls Reservoir District issued its American Falls Refunding Replacement Dam Bonds, Series 2000, in the aggregate principal amount of $20 million for the purpose of refunding on April 26, 2000 a like amount of its bonds dated May 1, 1990. IPC has guaranteed repayment of these bonds. On May 17, 2000, tax exempt Pollution Control Revenue Refunding Bonds Series 2000 in the aggregate principal amount of $4 million were issued by Port of Morrow, Oregon for the purpose of refunding on August 1, 2000, a like amount of its Pollution Control Revenue Bonds, Series 1978. At December 31, 2001 and 2000 the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 7.0 percent and 7.52 percent, respectively. 5. FAIR VALUE OF FINANCIAL INSTRUMENTS: The estimated fair value of IPC's financial instruments has been determined by IPC 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 notes receivable, long-term debt and investments are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate. The total estimated fair value of IPC's debt was approximately $868 million in 2001 and $866 million in 2000. Included in receivables were notes totaling $12 million in 2001 and $8 million in 2000. Estimated fair value of these instruments was $11 million in 2001 and $8 million in 2000. Included in investments and other property were financial instruments totaling $24 million in 2001 and $19 million in 2000. Estimated fair value of these instruments was $23 million in 2001 and $19 million in 2000. 6. NOTES PAYABLE: At December 31, 2001, IPC had regulatory authority to incur up to $500 million of short-term indebtedness. IPC has a $165 million facility that expires April 26, 2002 and a $120 million facility that expires April 18, 2002. Under these facilities IPC 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 amounts supported by the bank credit facilities. Also at December 31, 2001, IPC had $100 million of floating rate notes outstanding, payable on September 1, 2002. Balances and interest rates of short-term borrowings were as follows at December 31 (in thousands of dollars): 2001 2000 Balance at end of year $282,000 $ 59,700 Effective annual interest rate at end of year 2.1% 6.8% 7. COMMITMENTS AND CONTINGENT LIABILITIES: Commitments under contracts and purchase orders relating to IPC's program for construction and operation of facilities amounted to approximately $9 million at December 31, 2001. The commitments are generally revocable by IPC subject to reimbursement of manufacturers' expenditures incurred and/or other termination charges. IPC is currently purchasing energy from 66 on-line cogeneration and small power production facilities with contracts ranging from 1 to 30 years. Under these contracts IPC is required to purchase all of the output from these facilities. During the fiscal year ended December 31, 2001, IPC purchased 728,155 MWh at a cost of $45 million. From time to time IPC is party to various legal claims, actions, and complaints, certain of which may involve material amounts. Although IPC is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings, or, if not, what the impact might be, based upon the advice of legal counsel, management presently believes that disposition of these matters will not have a material adverse effect on IPC's financial position, results of operations or cash flows. 8. STOCK-BASED COMPENSATION: IPC participates in two stock-based compensation plans of IDACORP that are intended to align employee and shareholder objectives related to the long-term growth of IPC. IDACORP adopted the 2000 Long-Term Incentive and Compensation Plan (LTICP) for officers, key employees and directors. The LTICP permits the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares, and other awards. In 2001 and 2000, IPC's employees were issued IDACORP stock options with an exercise price equal to the market price of the IDACORP stock on the date of grant. The maximum term of the options is ten years, and they vest over a five-year period. In accordance with APB 25, no compensation costs have been recognized for these awards. Stock option transactions are summarized as follows. 2001 2000 Weighted Weighted average average Number exercise Number exercise of shares price of shares price Outstanding beginning of year 220,000 $ 35.81 - $ - Granted 174,000 40.31 220,000 35.81 Exercised - - - - Cancelled - - - - Outstanding end of year 394,000 $ 37.80 220,000 $ 35.81 Exercisable: 44,000 $ 35.81 - $ - The outstanding options had a range of exercise prices from $35.81 to $40.31. As of December 31, 2001 the weighted average remaining contractual life is 8.8 years. IDACORP also has a restricted stock plan for certain key employees. Each grant made under this plan has a three-year restricted period, and the final award amounts depend on the attainment of cumulative earnings per share performance goals. At December 31, 2001 there were 265,766 IDACORP shares remaining available under this plan. Restricted stock awards are compensatory awards and IPC accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 2001, 2000 and 1999, total compensation accrued under the plan was less than $1 million for each year. The following table summarizes restricted stock activity for the years 2001, 2000 and 1999: 2001 2000 1999 Shares outstanding - beginning of year 49,290 41,277 41,934 Shares granted 22,118 32,268 22,288 Shares forfeited (474) - (9,585) Shares issued (18,678) (24,255) (13,360) Shares outstanding - end of year 52,256 49,290 41,277 Weighted average fair value of current year stock grants on grant date $ 40.56 $ 34.44 $ 32.88 Had compensation cost for the stock-based compensation plans been determined on the basis of fair value pursuant to the provisions of SFAS 123, net income would have been as follows (in thousands of dollars): 2001 2000 1999 Net income: As reported $ 78,238 $137,488 $ 97,528 Pro forma $ 77,398 $137,620 $ 97,327 For purposes of the pro forma calculations above, the estimated fair value of the options and restricted stock are amortized to expense over the vesting period. The fair value of the restricted stock is the market price of the stock on the date of grant. The fair value of each option granted was estimated at the date of grant using the Binomial option-pricing model with the following assumptions: 2001 2000 Stock dividend yield 4.60% 5.19% Expected stock price volatility 29% 27% Risk-free interest rate 5.11% 6.15% Expected option lives 7 years 7 years Fair value of options granted $ 9.93 $ 8.42 9. BENEFIT PLANS: Pension Plans IPC 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. IPC's policy is to fund with an independent corporate trustee at least the minimum required under the Employee Retirement Income Security Act of 1974 but not more than the maximum amount deductible for income tax purposes. IPC was not required to contribute to the plan in 2001, 2000 and 1999. The trustee invests the plan assets primarily in listed stocks (both U.S. and foreign), fixed income securities and investment grade real estate. IPC has a nonqualified, deferred compensation plan for certain senior management employees and directors. IPC 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 2001 2000 1999 2001 2000 1999 Service cost $ 7,978 $ 7,442 $ 8,389 $ 624 $ 574 $ 744 Interest cost 17,634 16,718 16,402 2,039 1,965 1,797 Expected return on assets (30,117) (30,095) (25,240) - - - Recognized net actuarial (gain) loss (3,179) (4,503) (344) 281 242 279 Amortization of prior service cost 708 708 708 (345) (353) (325) Amortization of transition asset (263) (263) (263) 613 613 613 Net periodic pension cost $(7,239) $(9,993) $ (348) $3,212 $3,041 $3,108 The following table summarizes the changes in benefit obligation and plan assets of these plans (in thousands of dollars): Deferred Compensation Pension Plan Plan 2001 2000 2001 2000 Change in projected benefit obligation: Benefit obligation at January 1 $241,281 $229,042 $ 27,876 $ 26,925 Service cost 7,978 7,442 624 574 Interest cost 17,634 16,718 2,039 1,965 Actuarial loss (gain) 18,560 455 2,352 840 Benefits paid (12,586) (12,376) (2,420) (2,516) Plan amendments 341 - (66) 88 Benefit obligation at December 31 273,208 241,281 30,405 27,876 Change in plan assets: Fair value at January 1 340,789 340,521 - - Actual return on plan assets (1,936) 12,644 - - Employer contributions - - - - Benefit payments (12,586) (12,376) - - Fair value at December 31 326,267 340,789 - - Funded status 53,059 99,508 (30,405) (27,876) Unrecognized actuarial loss (gain) (31,857) (85,648) 8,513 6,442 Unrecognized prior service cost 7,589 7,954 (75) (355) Unrecognized net transition liability (916) (1,178) 2,149 2,762 Net amount recognized $ 27,875 $ 20,636 $(19,818) $(19,027) Amounts recognized in the statement of financial position consist of: Prepaid (accrued) pension cost $ 27,875 $ 20,636 $(28,500) $(26,365) Intangible asset - - 2,074 2,407 Accumulated other comprehensive income - - 6,608 4,931 Net amount recognized $ 27,875 $ 20,636 $(19,818) $(19,027) The following table sets forth the assumptions used at the end of each year for all IPC-sponsored pension and postretirement benefit plans: Postretirement Pension Benefits Benefits 2001 2000 2001 2000 Discount rate 7.0% 7.5% 7.0% 7.5% Expected long-term rate 9.0 9.0 9.0 9.0 of return on assets Annual salary increases 4.5 4.5 - - Employee Savings Plan IPC has an Employee Savings Plan, which complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. IPC matches specified percentages of employee contributions to the plan. Matching contributions amounted to $4 million in 2001 and $3 million in 2000 and 1999. Postretirement Benefits IPC 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): 2001 2000 1999 Service cost $ 831 $ 851 $ 896 Interest cost 3,589 3,374 2,867 Expected return on plan assets (2,343) (2,522) (2,230) Amortization of unrecognized transition obligation 2,040 2,040 2,040 Amortization of prior service cost (563) (691) (691) Amortization of unrecognized net gains - - - Net periodic post-retirement benefit cost $3,554 $3,052 $2,882 The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars): 2001 2000 Change in accumulated benefit obligation: Benefit obligation at January 1 $ 48,806 $ 41,139 Service cost 831 851 Interest cost 3,589 3,374 Plan amendments 600 1,200 Actuarial loss 3,296 5,635 Benefits paid (3,472) (3,393) Benefit obligation at December 31 53,650 48,806 Change in plan assets: Fair value of plan assets at January 1 26,071 26,805 Actual (loss) return on plan assets (2,004) (760) Employer contributions 4,413 3,108 Benefits paid (3,296) (3,082) Fair value of plan assets at December 31 25,184 26,071 Funded status (28,466) (22,735) Unrecognized prior service cost (6,173) (7,336) Unrecognized actuarial loss 10,828 3,361 (gain) Unrecognized transition 22,440 24,480 obligation Accrued benefit obligations included with other deferred credits $ (1,371) $ (2,230) The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan is 6.75 percent. 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 $ 335 $ (275) Effect on accumulated postretirement benefit obligation $3,167 $(2,709) Postemployment Benefits IPC 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. IPC 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 IPC's consolidated balance sheet at December 31 (in thousands of dollars): 2001 2000 1999 Included with regulatory assets - other $ 1,032 $ 1,517 $ 1,889 Included with other deferred credits $(3,010) $(3,040) $(3,282) 10. UTILITY PLANT IN SERVICE AND JOINTLY-OWNED PROJECTS: The following table sets out the major classifications of IPC's utility plant in service, accumulated provision for depreciation and annual depreciation provisions as a percent of average depreciable balance for the years 2001 and 2000 (in thousands of dollars): 2001 2000 Balance Avg Balance Avg Rate Rate Production $1,424,777 2.58% $1,360,409 2.60% Transmission 460,149 2.30 410,315 2.30 Distribution 854,445 3.34 811,604 3.34 General and Other 250,259 6.12 217,262 5.42 Total in service 2,989,630 2.98% 2,799,590 2.94% Accumulated provision for depreciation (1,220,002) (1,142,572) In service - net $1,769,628 $1,657,018 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's participation as of December 31, 2001 is as follows: Company Ownership Accumulated Utility Provision Plant In for Name of Plant Location Service Depreciation % MW (thousands of dollars) Jim Bridger Units 1-4 Rock Springs, WY $403,514 $ 222,302 33 707 Boardman Boardman, OR 64,580 38,133 10 55 Valmy Units 1 and 2 Winnemucca, NV 303,666 157,177 50 261 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 $43 million in 2001, $44 million in 2000 and $42 million in 1999. IPC has contracts to purchase the energy from four Public Utilities Regulatory Policy Act Qualified Facilities that are 50 percent owned by Ida-West Energy Company, a wholly owned subsidiary of IDACORP. Power purchased from these facilities amounted to $6 million in 2001, $8 million in 2000 and $9 million in 1999. 11. DISCONTINUED OPERATIONS Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations ("Energy Marketing") to IE. Energy Marketing net assets transferred consists primarily of energy trading contracts and trading accounts receivable and accounts payable. The results of operations of Energy Marketing were previously reported on IPC's Statements of Income as "Energy marketing activities - net." For all periods presented, Energy Marketing is reported as a discontinued operation. In exchange for the transfer of Energy Marketing to IE, IPC received a partnership interest in IE, which was transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million of which $43 million had been paid at December 31, 2001. The $76 million represents the historical book value of the transferred Energy Marketing net assets on May 31, 2001 of $21 million and retained intercompany tax liabilities of $55 million. The notes receivable are due over periods of one to ten years and bear interest at IDACORP's overall variable short-term borrowing rate, which was 2.2 percent at December 31, 2001. The net assets identified as part of the disposition of Energy Marketing are reported as "Net assets of discontinued operations" on IPC's consolidated balance sheet and consisted of the following at: May 31, December 31, 2001 2000 (thousands of dollars) Property, plant and equipment - net $ 551 $ 1,021 Investments and other property 864 382 Current assets 489,526 1,070,645 Current liabilities (481,762) (1,031,686) Other net noncurrent assets and liabilities 67,071 (2,660) Net assets of discontinued operations $ 76,250 $ 37,702 Concurrent with this transfer, IE and IPC entered into an Electricity Supply Management Services (Agreement). IPC received approval of the Agreement from the IPUC, the Oregon Public Utility Commission (OPUC) and the FERC. Under the agreement IPC will continue to own, operate and maintain its electric generating equipment and transmission facilities and be responsible for system reliability. IE will manage and dispatch the system resources to balance generation and load within IPC's operating area. IPC paid approximately $2 million in accordance with the Agreement as of December 31, 2001. After the transfer of Energy Marketing, IPC sold $23 million in off-system sales to and purchased $35 million in purchased power from IE. 12. REGULATORY ASSETS AND LIABILITIES: The following is a breakdown of IPC's regulatory assets and liabilities for the years 2001 and 2000: 2001 2000 Assets Liabilities Assets Liabilities (thousands of dollars) Income taxes $ 209,832 $ 41,290 $213,552 $40,230 Conservation 28,324 3,524 32,308 4,419 Employee benefits 2,825 - 3,742 - PCA deferral and amortization 289,623 - 119,905 - Oregon deferral and amortization 14,866 - - - Derivatives 47,781 - - - Other 5,990 1,127 9,700 202 Deferred investment tax credits - 68,016 - 66,050 Total $ 599,241 $113,957 $379,207 $110,901 At December 31, 2001, IPC had $4 million of regulatory assets, which primarily includes SFAS 112 benefits and reorganizations costs, that were not earning a return on investment excluding the $210 million that relates to income taxes and $48 million that relates to derivatives. The amortization periods range from three to four years, respectively. In the event that recovery of costs through rates becomes unlikely or uncertain, SFAS 71 would no longer apply. If IPC were to discontinue application of SFAS 71 for some or all of IPC's operations, then these items may represent stranded investments. If IPC 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. Idaho Jurisdiction PCA: In the 2001 PCA filing, IPC requested recovery of $227 million of power supply costs. In May, the IPUC authorized recovery of $168 million, but deferred recovery of $59 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59 million the IPUC authorized recovery of $48 million plus $1 million of accrued interest, beginning in October 2001. The remaining $11 million not recovered in rates from the PCA filing was written off in September 2001. Of the $227 million requested by IPC, $185 million related to the true-up of power supply costs incurred in the 2000-2001 PCA year and $42 million was for recovery of excess power supply costs forecasted in the 2001-2002 PCA year. The forecast amount, however, underestimated expected power supply costs due to reservoir water levels being less than forecast, necessitating the use of higher cost alternatives to hydro generation. Also market prices for purchased power were higher than forecast earlier in the PCA year. As part of the May 2001 PCA, the IPUC required IPC to implement a three-tiered rate structure for Idaho residential customers. The IPUC determined that the approved rates for residential customers should increase as the customer's electricity consumption increases. The residential rate increases are 14.4 percent for the first 800 kWh of usage, 28.8 percent for the next 1,200 kWh, and 62 percent for the usage over 2,000 kWh. On October 18, 2001 IPC filed an application with the IPUC for an order approving the costs to be included in the 2002-2003 PCA for the Irrigation Load Reduction Program and the Astaris Load Reduction Agreement. These two programs were implemented in 2001 to reduce demand and were approved by the IPUC and the Oregon Public Utility Commission (OPUC). The costs incurred in 2001 for these two programs were $70 million for the Irrigation Load Reduction Program and $62 million for the Astaris Load Reduction Agreement through December 2001. On August 31, 2001 IPC filed a request with the IPUC to implement a rate credit to qualifying residential and small farm customers. The credit is the result of a settlement agreement between IPC and the Bonneville Power Administration (BPA), which will pass on the benefits of the Federal Columbia River Power System. IPC estimates the credit could be as much as $3.60 per month for residential customers who use 1,200 kWh per month and $300 per month for farm customers that use 100,000 kWh. The IPUC, by Order No. 28868, approved the credit to be passed to the qualified customers effective October 1, 2001. In its May 2001 rate authorization the IPUC also directed IPC to reinstate a comprehensive conservation program given the current volatility of market prices and the opportunity to incorporate long- term conservation. In response to that directive, IPC filed a report of present energy efficiency activities, a list of conservation measures, an examination of funding options and a detailed program structure that could be implemented should the Commission determine that additional conservation programs, including the funding of these programs, is in the public interest. The Commission has delayed further deliberations until the spring of 2002. So far in the 2001-2002 rate year actual power supply costs included in the PCA have been significantly greater than forecast due to purchased power volumes and prices being greater than originally forecasted and the implementation of the voluntary load reduction programs with Astaris and the irrigation customers. To account for these higher-than-forecasted costs and the unamortized portion of the 2000-2001 PCA balances, IPC has recorded regulatory assets of $290 million as of December 31, 2001. The May 2000 rate adjustment increased Idaho general business customer rates by 9.5 percent, and resulted from forecasted below- average hydroelectric generating conditions. Overall, the PCA adjustment increased general business revenue by approximately $38 million during the 2000-2001 rate period, partially offsetting the forecasted increase in power supply 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 1999-2000 rate period and a true-up from the 1998-1999 rate period. Overall, the May 1999 rate adjustment decreased annual general business revenue by approximately $40 million during the 1999-2000 rate period. Regulatory Settlement: IPC had a settlement agreement with IPUC that expired at the end of 1999. Under the terms of the settlement, when earnings in IPC's Idaho jurisdiction exceeded an 11.75 percent return on the year-end common equity, IPC set aside 50 percent of the excess for the benefit of the Idaho retail customers. In March 2000 IPC submitted its 1999 annual earnings sharing compliance filing to the IPUC. This filing indicated that there was almost $10 million in 1999 earnings and $3 million in unused 1998 reserve balances available for the benefit of the Idaho customers. In April 2000 the IPUC issued Order 28333, which ordered that $7 million of the revenue sharing balance be refunded to Idaho customers through rate reductions effective May 16, 2000. The Order also approved IPC's continued participation in the Northwest Energy Efficiency Alliance for the years 2000-2004, ordering IPC to set aside the remaining $6 million of revenue sharing dollars to fund that participation. Demand Side Management (DSM): IPC requested that the IPUC allow for the recovery of post-1993 DSM expenses and acceleration of the recovery of DSM expenditures authorized in the last general rate case. In its Order No. 27660 issued on July 31, 1998, the IPUC set a new amortization period of 12 years instead of the 24-year period previously adopted. On April 17, 2000, the Idaho Supreme Court affirmed the IPUC order, after hearing an appeal by a group of industrial customers. On February 23, 2001 the IPUC approved IPC's Green Energy Purchase Program. The Green Program is an optional program available to all IPC customers in Idaho, allowing them to pay a premium to purchase energy generated by alternative sources such as solar and wind. Creating the Green Program will provide additional means for customers to stimulate demand for new green resources and their development. Other Jurisdictions IPC filed an application with the OPUC to begin recovering extraordinary 2001 power supply costs in its Oregon jurisdiction. On June 18, 2001, the OPUC approved new rates that would recover $1 million over the next year. Under the provisions of the deferred accounting statute, annual rate recovery amounts were limited to three percent of IPC's 2000 gross revenues in Oregon. During the 2001 session, the Oregon Legislature amended the statute giving the OPUC authority to increase the maximum annual rate of recovery of deferred amounts to six percent for electric utilities. IPC subsequently filed on October 5, 2001 to recover an additional three percent extraordinary deferred power supply costs. As a result of this filing, the OPUC issued Order No. 01-994 allowing IPC to increase its rate of recovery to six percent effective November 28, 2001. The Oregon deferral balance is $15 million as of December 31, 2001, net of the June 18, 2001 and November 28, 2001 recovery. IPC filed with the OPUC a request to implement the same BPA program as in Idaho. The OPUC held a public meeting on October 22, 2001 and subsequently approved IPC's request to implement the BPA Residential and Small Farm Energy Credit for the benefits derived during the period October 1, 2001 through September 30, 2006. In 1998, IPC received authority from the OPUC to reduce the amortization period for the regulatory assets associated with DSM programs from 24 years to 5 years. The OPUC also approved additional Oregon allocated DSM expenditures for recovery through rates. The Oregon costs will be recovered by extending an existing surcharge until the amounts are collected. 13. DERIVATIVE FINANCIAL INSTRUMENTS: Derivative Assets and Liabilities IPC adopted SFAS 133, as amended, effective January 1, 2001. Contracts company-wide were evaluated based upon the SFAS 133 derivative definitions and requirements. Most of IPC's contracts that meet the derivative definition are the energy trading contracts that were already recorded at fair value under EITF 98-10. Most of the remaining energy contracts meet the definition of a normal purchase or sale and therefore are not considered derivatives. However, IPC has certain electricity contracts that are periodically net settled with the counterparty (booked out). Booking out of electricity contracts is a normal business transaction within the electric utility industry; however the FASB and the Derivative Implementation Group (DIG) of the FASB initially interpreted that book outs did not qualify for the normal purchase and sales exception. IPC has recorded the fair market value of the booked out system electricity contracts within the financial statements as "Derivative liabilities." Such assets and liabilities at January 1 and December 31, 2001 are as follows: January 1, 2001 December 31, 2001 (thousands of dollars) Assets $ 108,909 $ - Liabilities (207,407) (47,781) Net $ (98,498) $(47,781) The electricity contracts identified above are subject to IPC's regulatory processes. Accordingly, SFAS 71, allows the net amount of these derivative assets and liabilities to be offset by regulatory assets or liabilities. The IPUC granted approval of this use of SFAS 71 regulatory assets or liabilities in its Order No. 28661 issued March 12, 2001. In June 2001 the DIG issued Interpretation C-15, which was amended in October 2001, that tentatively concludes that certain booked out contracts now qualify for the normal purchase and sales exception. IPC is evaluating the effect of this new conclusion on its treatment of booked out contracts but expects that some contracts previously classified as derivatives will be exempt when C-15 becomes effective on January 1, 2002. The effect of this change will not have a material effect on IPC's financial position, results of operations, or cash flows. As a result of the items discussed above, IPC's adoption of SFAS 133, as amended, did not have a material effect on its financial position, results of operations, or cash flows. 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, 2001 and 2000, and the related consolidated statements of income, cash flows, retained earnings, and comprehensive income for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the United States of America. 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated 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, 2002 SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED QUARTERLY FINANCIAL DATA: The following unaudited information is presented for each quarter of 2001 and 2000 (in thousands of dollars). In the opinion of IPC, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported. Quarter Ended March 31 June 30 September 30 December 31 2001 Revenues $200,316 $227,930 $286,292 $197,774 Income from operations 32,694 27,780 12,470 17,075 Income taxes* 23,132 25,033 958 4,406 Net income 38,225 34,785 1,274 3,952 Dividends on preferred stock 1,461 1,292 1,347 1,272 Earnings on common stock 36,764 33,493 (100) 2,680 2000 Revenues $166,333 $213,081 $231,539 $224,708 Income from operations 55,966 36,139 39,959 37,572 Income taxes* 21,024 19,341 28,429 16,774 Net income 33,725 32,154 43,095 28,514 Dividends on preferred stock 1,428 1,484 1,511 1,506 Earnings on common stock 32,297 30,670 41,584 27,008 *The income taxes presented for 2001 and 2000 do not include the effect of discontinued operations (see Note 11 to the Consolidated Financial Statements). ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III Part III has been omitted because the registrant will file a definitive proxy statement pursuant to Regulation 14A, which involves the election of Directors, with the Commission within 120 days after the close of the fiscal year portions of which are hereby incorporated by reference (except for information with respect to executive officers which is set forth in Part I hereof). PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K (a) Please refer to Item 8, "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules. (b) Reports on SEC Form 8-K. The following Report on Form 8-K was filed for the three months ended December 31, 2001 Items Reported Date of Report Item 5 - Other Events September 27, 2001 Item 7 - Financial 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(a)(iii) 1-3198 3(a)(iii) Articles of Amendment to Restated Form 10-Q Articles of Incorporation of IPC as for 6/30/00 filed with the Secretary of State of Idaho on June 15, 2000. *3(b) 1-3198 3(c) By-laws of IPC amended on September Form 10-Q 9, 1999, and presently in effect. for 9/30/99 *3(c) 33-56071 3(d) Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998. *4(a)(i) 2-3413 B-2 Mortgage and Deed of Trust, dated as of October 1, 1937, between IPC and Bankers Trust Company and R. G. Page, as Trustees. *4(a)(ii) IPC Supplemental Indentures to Mortgage and Deed of Trust: Number Dated 1-MD B-2-a First July 1, 1939 2-5395 7-a-3 Second November 15, 1943 2-7237 7-a-4 Third February 1, 1947 2-7502 7-a-5 Fourth May 1, 1948 2-8398 7-a-6 Fifth November 1, 1949 2-8973 7-a-7 Sixth October 1, 1951 2-12941 2-C-8 Seventh January 1, 1957 2-13688 4-J Eighth July 15, 1957 2-13689 4-K Ninth November 15, 1957 2-14245 4-L Tenth April 1, 1958 2-14366 2-L Eleventh October 15, 1958 2-14935 4-N Twelfth May 15, 1959 2-18976 4-O Thirteenth November 15, 1960 2-18977 4-Q Fourteenth November 1, 1961 2-22988 4-B-16 Fifteenth September 15, 1964 2-24578 4-B-17 Sixteenth April 1, 1966 2-25479 4-B-18 Seventeenth October 1, 1966 2-45260 2(c) Eighteenth September 1, 1972 2-49854 2(c) Nineteenth January 15, 1974 2-51722 2(c)(i) Twentieth August 1, 1974 2-51722 2(c)(ii) Twenty-first October 15, 1974 2-57374 2(c) Twenty-second November 15, 1976 2-62035 2(c) Twenty-third August 15, 1978 33-34222 4(d)(iii) Twenty-fourth September 1, 1979 33-34222 4(d)(iv) Twenty-fifth November 1, 1981 33-34222 4(d)(v) Twenty-sixth May 1, 1982 33-34222 4(d)(vi) Twenty-seventh May 1, 1986 33-00440 4(c)(iv) Twenty-eighth June 30, 1989 33-34222 4(d)(vii) Twenty-ninth January 1, 1990 33-65720 4(d)(iii) Thirtieth January 1, 1991 33-65720 4(d)(iv) Thirty-first August 15, 1991 33-65720 4(d)(v) Thirty-second March 15, 1992 33-65720 4(d)(vi) Thirty-third April 1, 1993 1-3198 4 Thirty-fourth December 1, 1993 Form 8-K Dated 12/17/93 1-3198 4 Thirty-fifth November 1, 2000 Form 8-K Dated 11/21/00 1-3198 4(a) Thirty-sixth October 1, 2001 Form 8-K Dated 9/27/01 *4(b) 1-3198 4(b) Instruments relating to IPC American Form 10-Q Falls bond guarantee (see Exhibit for 6/30/00 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. *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) 1-3198 10(c) Guaranty Agreement, dated April 11, Form 10-Q 2000, between IPC and Bank One Trust for 6/30/00 Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing 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, 2001. *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 1-14465 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 1-14465 10(h)(ix) IDACORP, Inc. 2000 Long-Term Form 10-K Incentive and Compensation Plan. for 1999 *10(i) 33-65720 10(h) Framework Agreement, dated October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights. *10(i)(i) 33-65720 10(h)(i) Agreement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). *10(i)(ii) 33-65720 10(h)(ii) Contract to Implement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). *10(j) 33-65720 10(m) Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between IPC and the Twin Falls Canal Company and the Northside Canal Company Limited. *10(j)(i) 33-65720 10(m)(i) Guaranty Agreement, dated February 10, 1992, between IPC and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc. 12 Statement Re: Computation of Ratio of Earnings to Fixed Charges. 12(a) Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. 12(b) Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 12(c) Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 21 Subsidiaries of IPC. 23 Independent Auditors' Consent. ____________________________ 1 Compensatory plan IDAHO POWER COMPANY SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2001, 2000 and 1999 Column A Column B Column C Column D Column E Additions Balance Charged Balance At Charged (Credited) At End Beginning to to Other Deductions Of Classification Of Period Income Accounts (1) Period (thousands of dollars) 2001: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts and assets $ 23,079 $ 3,607 $(21,682) $ 3,504 $ 1,500 Other Reserves: Rate refunds $ - $ - $ - $ - $ - Injuries and damages reserve $ 1,500 $ - $ - $ - $ 1,500 Miscellaneous operating reserves $ 4,656 $ 107 $ (11) $ 1,201 $ 3,551 2000: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $ 1,397 $23,340 $ - $ 1,658 $23,079 Other Reserves: Rate refunds $ 8,893 $ 3,505 $ - $12,398 $ - Injuries and damages reserve $ 1,500 $ - $ - $ - $ 1,500 Miscellaneous operating reserves $ 8,473 $ 306 $ - $ 4,123 $ 4,656 1999: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $ 1,397 $ 1,547 $ - $ 1,547 $ 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 Notes: (1) Represents deductions from the reserves for purposes for which the reserves were created. 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 22, 2002 By:/s/J. LaMont Keen J. LaMont Keen President and Chief Operating Officer 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 Chairman of the Board March 22, 2002 Jon H. Miller By:/s/ Jan B. Packwood Chief Executive Officer " Jan B. Packwood and Director By:/s/ J. LaMont Keen President and Chief " J. LaMont Keen Operating Officer By:/s/ Darrel T. Anderson Vice President, Chief " Darrel T. Anderson Financial Officer and Treasurer (Principal Financial Officer) (Principal Accounting Officer) By:/s/ Rotchford L. Barker By:/s/ Evelyn Loveless " Rotchford L. Barker Evelyn Loveless Director Director By:/s/ Roger L. Breezley By:/s/ Gary G. Michael " Roger L. Breezley Gary G. Michael Director Director By:/s/ John B. Carley By:/s/ Peter S. O'Neill " John B. Carley Peter S. O'Neill Director Director By: By:/s/ Robert a. Tinstman " Christopher L. Culp Robert A. Tinstman Director Director By:/s/ Jack K. Lemley Jack K. Lemley Director EXHIBIT INDEX Exhibit Page Number Number 10(n)(ii) The Executive Annual Incentive Plan for senior management employees of IPC effective January 1, 2001. 12 Statements Re: Computation of Ratio of Earnings to Fixed Charges. 12(a) Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. 12(b) Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 12(c) Statements Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. 21 Subsidiaries of IPC 23 Independent Auditors' Consent.