10-K 1 a10k.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934 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 IRS Employer Commission its charter, address of principal executive Identification File Number offices and telephone number Number 1-14465 IDACORP, Inc. 82-0505802 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 Common Stock, without par value New York and Pacific Preferred Stock Purchase Rights SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None 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. ( ) Aggregate market value of voting and non-voting common stock held by nonaffiliates (February 28, 2002): 1,429,987,610 Number of shares of common stock outstanding at February 28, 2002: 37,590,494 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 APC - Applied Power Company BPA - Bonneville Power Administration Cal ISO - California Independent System Operator CalPX - California Power Exchange CSPP - Cogeneration and Small Power Production DIG - Derivatives Implementation Group DSM - Demand-Side Management EITF - Emerging Issues Task Force EPA - Environmental Protection Agency EPS - Earning per share 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 LTICP - Long-Term Incentive and Compensation Plan MD&A - Management's Discussion and Analysis MMbtu - Million British Thermal Units MW - Megawatt MWh - Megawatt-hour OPUC - Oregon Public Utility Commission Overton - Overton Power District No. 5 PCA - Power Cost Adjustment PG&E - Pacific Gas and Electric Company PUCN - Public Utility Commission of Nevada PURPA - Public Utilities Regulatory Policy Act REA - Rural Electrification Administration RFP - Request for proposals RMC - Risk Management Committee RTOs - Regional Transmission Organizations SCE - Southern California Edison SFAS - Statement of Financial Accounting Standards SPPCo - Sierra Pacific Power Company Valmy - North Valmy Steam Electric Generating Plant WSCC - Western Systems Coordinating Council TABLE OF CONTENTS Page PART I ITEM 1. BUSINESS 1 ITEM 2. PROPERTIES 13 ITEM 3. LEGAL PROCEEDINGS 15 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 15 EXECUTIVE OFFICERS OF THE REGISTRANTS 16 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS 17 ITEM 6. SELECTED FINANCIAL DATA 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 18 ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK 39 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 40 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 72 PART III ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS* 72 ITEM 11.EXECUTIVE COMPENSATION* 72 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT* 72 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS* 72 PART IV ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K 72 SIGNATURES 75 *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 IDACORP, Inc. (IDACORP or the Company) is a holding company incorporated in 1998 under the laws of the state of Idaho and is the parent of Idaho Power Company (IPC), IDACORP Energy (IE), and several other entities. 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. IE markets electricity and natural gas, and offers risk management and asset optimization services, to wholesale customers in 31 states and two Canadian provinces. IDACORP's other subsidiaries are: Ida-West Energy (Ida-West) - independent power projects development and management; IdaTech - developer of integrated fuel cell systems; IDACORP Financial Services (IFS) - affordable housing and other real estate investments; Velocitus - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services. IPC transferred its non-utility wholesale electricity marketing operations to IE effective June 11, 2001. At December 31, 2001, the Company had 1,999 full-time employees. Of these employees, 1,688 are employed by IPC. The Company has identified two reportable business segments, the regulated utility operations of IPC, and the energy marketing activities of IE. IPC and IE contributed 16 percent and 84 percent to consolidated operating revenues, respectively, during the year ended December 31, 2001. We present additional information about our operating segments in Note 12 to the Consolidated Financial Statements and below in "Utility Operations" and "Energy Marketing." UTILITY OPERATIONS IPC was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. IPC 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. 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 13 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 (WSCC), 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, 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 the Company'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 should 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 IPC costs for the identification and disposal of PCBs from IPC's system were less than $1 million each year from 1999 to 2001. 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 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 (millions of dollars) Residential $ 260 225 214 Commercial 164 132 123 Industrial 154 133 117 Irrigation 72 75 62 Total general business 650 565 516 Off system sales 220 230 120 Other 44 42 24 Total $ 914 837 660 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 ENERGY MARKETING In January 1997, IPC began implementing a strategy to become a competitive energy provider throughout the western markets. In order to compete as an energy provider of choice, IPC built a trading operation to participate in the electricity, natural gas and other related markets. In 1997 IPC developed natural gas trading operations which were transferred to IE in 1999. Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations ("Energy Marketing") to IE. IE has offices in Boise, Idaho and Houston, Texas and employed approximately 120 people at December 31, 2001. IE's energy marketing strategy has produced increasingly positive results through growing the volume of energy delivered, expanding the geographic area in which IE does business, and capitalizing on the recent high volatility of energy prices. While IE continues to be active in the natural gas markets, its business expansion has primarily been driven from three interdependent strategies in the electricity markets. First, IE uses its expertise in the physical power system within the western United States to purchase the rights to strategic transmission. While IE has no obligation to renew these rights annually, many of them can be extended indefinitely, barring any regulatory changes, giving it the ability to assess the value of the rights on an annual basis before renewal. The second piece of its strategy is to buy and sell energy around these contractual transmission assets and take advantage of market price movements between regions while limiting its market risk. Third, IE uses its knowledge of the physical system coupled with its risk management expertise to create customized, or structured, energy solutions for end-use customers. Additionally, IE offers asset management services to utilities and other regulated energy providers. One such agreement is with the Company's affiliate, IPC. Concurrent with the June 2001 transfer of the non-utility electricity marketing business from IPC to IE, IE and IPC entered into an Electricity Supply Management Services Agreement (Agreement). IPC received approval of the Agreement from the IPUC, OPUC and the FERC. Under the Agreement, IPC will continue to own, operate and maintain its electric generating equipment and transmission facilities (system resources) and be responsible for system reliability. IE will manage and dispatch the system resources to balance generation and load within the IPC operating area. Revenues for the energy marketing segment, including intersegment revenues, for 2001, 2000 and 1999 were $4,893 million, $2,462 million and $872 million respectively. The growth in revenue was due to an increase in wholesale electricity prices and growth in settled physical electricity volume from 14.4 million MWh's in 1999 to 23.5 million MWh's in 2000 and 34.9 million MWh's in 2001. Risk Management: When buying and selling energy, the high volatility of energy prices can have significant negative impact on profitability if not appropriately managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into can withstand potentially dramatic market fluctuations. To manage the risks inherent in the energy commodity industry while implementing the Company's business strategy, the Risk Management Committee (RMC), comprised of Company officers, oversees the Company's risk management program as defined in the risk management policy. The program is intended to manage the impact to earnings caused by the volatility of energy prices by mitigating commodity price risk, credit risk, and other risks related to the energy commodity business. To manage the risks inherent in its portfolio, the Company has established risk limits. Market and credit risk is measured and reported daily to the members of the RMC. Other tools used to manage credit risk are the holding of collateral in the form of cash or letters of credit and the use of margining agreements with counterparties when credit risk exceeds certain pre-determined thresholds. Because of the volatile nature of energy market prices, margining agreements can require the posting of large amounts of cash between counterparties to hold as collateral against the value of the energy contracts. This practice mitigates credit risk but increases the need for cash or other liquid securities to ensure the ability to meet all margin requirements when the markets are most volatile. At year-end 2001, 69 percent of the credit exposure related to IE's unrealized positions is with investment grade counterparties. Less than 0.5 percent is with non-investment grade counterparties. The remaining 31 percent of year-end credit exposure is with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives. See further discussion in Part II Item 7 "Management's Discussion and Analysis - Market Risk." Supply: IE's supply of electricity and natural gas is purchased directly from producers as well as other energy marketers. Sales of energy are made to other marketers, investor owned utilities, municipalities and cooperatives as well as large commercial and industrial customers in regions that allow retail customer choice. Approximately 55 percent of the marketing and trading business in 2001 was with other marketing companies. Competition: Competition in energy marketing and trading continues to increase. There are over 150 counterparties active in the energy markets in the WSCC and all are increasing in their sophistication. IE anticipates that lower prices and decreased volatility may negatively impact its business. While IE is not dependent on market prices for income, its profitability does depend upon volume and spread. Both bid/ask spread and regional pricing spreads are typically much lower during periods of lower prices. Further, deteriorating credit conditions of our counter parties are limiting IE's ability to transact with those counter parties, decreasing the rate of growth of transaction volume. While disciplined adherence to IE's policy toward credit may limit short term profitability, IE believes it is prudent to do so in order to manage risks properly and sustain the quality of earnings in the long run. Energy Marketing Operating Statistics The following table presents IE's revenues and volumes (including intersegment transactions) for the last three years: Years Ended December 31, 2001 2000 1999 Revenues (Millions of dollars) Electricity $ 4,531 $ 2,191 $ 594 Gas 362 271 278 Total $ 4,893 $ 2,462 $ 872 Operating Volumes (Settled) Electricity (MWhs) 34,936,951 23,518,454 14,433,650 Gas (mmbtu's) 97,327,432 80,728,530 141,432,755 IDA-WEST Ida-West develops, acquires, constructs, finances, owns and operates electric power generation facilities. Ida-West has a 50 percent interest in nine operating hydroelectric plants with a total generating capacity of 45 MW. Ida-West is developing the 273-MW Garnet Energy Facility, which will begin operation as soon as 2004, in Canyon County, Idaho. This facility will provide up to 250 MW for IPC's future peak energy needs. The project is the result of a competitive bidding process conducted by IPC, which has indicated it will face an electric energy shortfall during certain months beginning as soon as the summer of 2004. Garnet, a combined-cycle combustion turbine project, is capable of expansion to 540 MW. In 2001 the Friant Power Authority redeemed bonds that represented Ida-West's investment in the Friant Power Project, a 27.4 MW project located in California. The Friant bonds were originally acquired in 1996. Ida-West recorded a pre-tax gain of $5 million on this transaction in 2001. In 2000, Ida-West sold its interest in the Hermiston Power project, a 536-MW gas-fired project currently under construction near Hermiston, Oregon. Ida-West was responsible for managing all permitting and development activities relating to the project since its inception in 1993. Ida-West recorded a pre-tax gain of $14 million on this transaction in 2000. IPC has purchased all of the power generated by Ida- West's four Idaho hydroelectric projects, at a cost of $6 million in 2001. IDATECH IdaTech was organized in 1996 as Northwest Power Systems, LLC with the intent to bring fuel cell technology to market. In April 1999 IDACORP purchased a majority interest in IdaTech. IdaTech is a developer of fuel processors and proton-exchange- membrane fuel cell systems. These fuel cell systems are designed with various outputs for stationary and portable electric power generation. With six patents issued and more than 50 pending, IdaTech's development efforts are focused on the commercialization of a methanol fuel processor, which is capable of producing a very high level of pure hydrogen. Additionally, the company is strengthening its ability to reform other conventional fuels including natural gas, propane, and kerosene. In 2001 IdaTech began the design, production and delivery of the first beta fuel cell systems for testing in 2001 and 2002, as agreed upon in a contract with the Bonneville Power Administration. IdaTech is also field-testing its fuel cell systems in Japan in cooperation with Tokyo Boeki, Ltd., and in Europe in cooperation with Electricite De France (EDF). IdaTech anticipates commercialization of its methanol fuel processor module in 2002, and also plans to continue field-testing its portable fuel cell system. IDACOMM and Velocitus In August 2000, we formed IDACOMM, Inc. and acquired Velocitus, Inc. (formerly Rocky Mountain Communications, Inc.), a Boise, Idaho-based Internet service provider founded in 1992. IDACOMM and Velocitus provide a wide range of integrated communication services to business and residential customers in several western states, Virginia and New York. IDACOMM, an integrated communication provider, delivers high-speed connectivity, using fiber optic network technology. IDACOMM's technologies enable high-speed voice, Internet and data communications, including video conferencing, voice-over IP, off-site training and gigabit Ethernet service. IDACOMM's customers include Fortune 500 companies as well as government entities and school districts. IDACOMM's Metropolitan Area Network in Idaho's Treasure Valley serves Boise, Meridian, Nampa and Caldwell. Velocitus operates as a Managed Service Provider by offering high- speed Internet access, Internet system support and other related services such as Virtual Private Networks, Firewalls and Web Hosting to more than 25,000 customers. Velocitus Internet serves the traditional residential and general consumer segment. Velocitus Broadband targets small to medium size business clients with high- speed connectivity and security solutions, including fixed wireless technology, allowing for rapid deployment and prompt service installation. Velocitus Broadband is currently available to customers in parts of Idaho, Washington, Oregon, California, New Mexico, Arizona and Utah with additional western markets opening in 2002. IDACORP FINANCIAL SERVICES IFS invests primarily in affordable housing projects, which provide a return primarily by reducing federal income taxes through tax credits and tax depreciation benefits. In 2000, IFS expanded its portfolio to include historic rehabilitation projects such as the El Cortez Hotel in San Diego, California and the Empire Building in Boise, Idaho. RESEARCH AND DEVELOPMENT In 2001, IdaTech spent approximately $7 million for research and development of fuel cell technology. IdaTech's research and development program is focused on the adaptation of its methanol fuel processor to operate on all commercially important fuels. Highest priority is given to liquid petroleum gas, natural gas, and kerosene or diesel fuels. IdaTech continues its policy of aggressively pursuing patent protection of its methanol fuel processor in North America, Europe, South America, Asia, and Australia. The patents issued to IdaTech address the design and operation of novel fuel reformers and hydrogen purification devices based on a two-stage hydrogen- selective metal membrane. Cost reduction through improved designs and reduced use of expensive materials are useful objectives of these patents. Additionally, one patent issued to IdaTech in 2001 claims an optimized method for purging hydrogen from the anode compartment of a PEMFC (Proton Exchange Membrane Fuel Cell) stack so as to minimize the loss of hydrogen fuel without adversely affecting the electrical power output from the PEMFC stack. Currently, six- 20 year US patents have been issued to IdaTech. More than 50 pending domestic and foreign patent applications addressing various aspects of fuel processor design, operation, materials, and integration with fuel cell stacks. 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 $660 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) IPC Utility Capital Expenditures (excluding AFDC): Construction Expenditures: Generating facilities Hydro $ 15 $ 35 Thermal 13 27 Total generating facilities 28 62 Transmission lines and 18 46 substations Distribution lines and 57 119 substations General 21 40 124 267 Long-term debt maturities 27 130 Other 3 9 Total IPC Utility 154 406 Ida-West Capital Expenditures 4 130 IE Capital Expenditures 7 2 IFS Capital Expenditures 59 67 Other 11 15 Total Company $235 $620 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. Ida-West's capital expenditures are primarily for development of the 273-MW Garnet Energy Facility, which is expected to begin operation as soon as 2004. IFS's capital expenditures are primarily for additional investments in affordable housing projects. 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. The Company will continue to take advantage of any refinancing opportunities as they become available. Under the terms of the Indenture relating to IPC's First Mortgage Bonds, net earnings must be at least two times the annual interest on all bonds and other equal or senior debt. For the twelve months ended December 31, 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. CREDIT RATINGS All of the Company's publicly traded debt as well as that of IPC 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 and IPC will continue to evaluate their capital structures, 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 or IPC's securities and serve to increase those companies' cost of capital. Some collateral agreements in place between IE and its counterparties include provisions requiring additional margining in the event of a credit rating downgrade. Credit rating changes within the investment grade category should not materially impact the liquidity or financial condition of IE. A credit downgrade below an investment grade rating could result in additional margin calls that could have a material negative impact to the liquidity of IDACORP. The Company believes its existing credit facilities are adequate to fund these potential liquidity requirements. 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 Nameplate Operating Capacity License Project Capacity kw kW Expiration Properties Subject to Federal Licenses: Lower Salmon 70,000 60,000 1997 (a) Bliss 80,000 75,000 1998 (a) Upper Salmon 39,000 34,500 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 combustion) 5,500 5,000 (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. Ida-West holds investments in nine operating hydroelectric plants with a total generating capacity of 45 MW. 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 IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5, a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts of electrical energy per hour from IE at $88.50 per megawatt hour, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract. IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as agreed. On December 14, 2001, IE notified Overton that the contract was terminated due to their failure to meet payment obligations. IE believes that Overton's breach of contract is completely without basis and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits. At December 31, 2001, the Company had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None EXECUTIVE OFFICERS OF THE REGISTRANT The names, ages and positions of all of the executive officers of the Company are listed below along with their business experience during the past five years. 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, 58 Appointed May 30, 1999. Mr. President and Chief Packwood was President and Chief Executive Officer Operating Officer from February 2, 1998 to May 30, 1999. J. LaMont Keen, 49 Appointed March 1, 2002. Mr. Keen Executive Vice President was Senior Vice President, 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 February 2, 1998 to March 15, 1999. Richard Riazzi, 47 Appointed March 1, 2002. Mr. Riazzi Executive Vice President was Senior Vice President, Generation and Marketing from March 15, 1999 to March 1, 2002 and Vice President - Marketing and Sales from January 14, 1999 to March 15, 1999. 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. Bryan Kearney, 39 Appointed March 15, 2001. Vice President and Chief Information Officer Gregory W. Panter, 53 Appointed April 1, 2001. Vice President - Public Affairs Robert W. Stahman, 57 Appointed February 2, 1998. Vice President, General Counsel and Secretary PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS IDACORP's common stock (without par value) is traded on the New York and Pacific Stock Exchanges. At December 31, 2001, there were 20,910 holders of record and the year-end stock price was $40.60 per share. The following table shows the reported high and low sales price and dividends paid for the years 2001 and 2000 as supported by the New York Stock Exchange. 2001 Quarters Common Stock, without par 1st 2nd 3rd 4th value: High $49.38 $41.10 $39.94 $41.14 Low 33.80 34.88 33.55 35.33 Dividends paid per share (in cents) 46.5 46.5 46.5 46.5 ______________________________ 2000 Quarters Common Stock, without par 1st 2nd 3rd 4th value: High $53.00 $37.00 $48.69 $51.81 Low 25.94 31.00 32.38 43.38 Dividends paid per share (in cents) 46.5 46.5 46.5 46.5 ITEM 6. SELECTED FINANCIAL DATA SUMMARY OF OPERATIONS (millions of dollars except for per share amounts) For the Years Ended December 31, 2001 2000 1999 1998 1997 Operating revenues $5,648 $2,996 $1,433 $1,419 $ 834 Income from operations 243 248 187 181 181 Net income 125 140 91 89 87 Earnings per average share outstanding (basic and diluted) 3.35 3.72 2.43 2.37 2.32 Dividends declared per 1.86 1.86 1.86 1.86 1.86 share At December 31, Total long-term debt* 843 864 822 816 746 Total assets 3,642 4,040 2,640 2,457 2,452 *Excludes amount due within one year. The above data should be read in conjunction with the consolidated financial statements and notes to consolidated financial statements included in this 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 IDACORP, Inc. and its subsidiaries (IDACORP or the Company). IDACORP is a holding company formed in 1998 and is the parent of Idaho Power Company (IPC), IDACORP Energy (IE), and several other entities. 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. IE markets electricity and natural gas, and offers risk management and asset optimization services, to wholesale customers in 31 states and two Canadian provinces. In June 2001, IPC transferred its non- utility energy marketing operations to IE. IDACORP's other operating subsidiaries include: Ida-West Energy (Ida-West) - independent power projects development and management; IdaTech - developer of integrated fuel cell systems; IDACORP Financial Services (IFS) - affordable housing and other real estate investments; Velocitus - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services. 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. FORWARD-LOOKING INFORMATION In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), we are hereby filing cautionary statements identifying important factors that could cause our actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of the Company in this Annual Report, any quarterly report on Form 10-Q, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue," or similar expressions) are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions, and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond our control and may cause actual results to differ materially from those contained in forward-looking statements: prevailing governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities Commission (IPUC), the Oregon Public Utilities Commission (OPUC), and the Public Utilities Commission of Nevada (PUCN), with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs); 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 the Company. 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 and then discussing results for each of our operating segments. Earnings per share of common stock 2001 2000 1999 Utility operations $0.60 $1.97 $2.00 Energy marketing 2.87 1.58 0.34 Other operations (0.12) 0.17 0.09 Total earnings per share $3.35 $3.72 $2.43 Return on year-end common equity 14.4% 17.0% 12.1% High wholesale energy prices and a severe drought had a negative effect on utility operations from 2000 to 2001. Of the $1.37 decrease from 2000, $0.70 cents per share is attributable to increases in power supply expenses absorbed by IPC and $0.18 per share is due to the write-off of amounts disallowed in IPC's 2001 power cost adjustment (PCA). Additional increases in operating expenses for maintenance, depreciation, interest and customer expenses decreased earnings by approximately $0.34 per share. The decrease in (earning per share) EPS from utility 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 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"). EPS from energy marketing increased $1.29 per share in 2001 and $1.24 per share in 2000. This strong performance was driven primarily by increased structured origination activities, continued price volatility and increased volumes of transactions. The annual total volume of settled power sales increased 49 percent to 34.9 million megawatt-hours (MWh) in 2001 and increased 63 percent to 23.5 million MWh in 2000. EPS from other operations decreased in 2001 and increased in 2000, principally because of a gain recorded on the sale in March 2000 of the Hermiston Power Project. This gain contributed approximately $0.22 per share in 2000. Increased operating losses at recently acquired subsidiaries was the primary source of the rest of the change in EPS from other operations in both 2001 and 2000. UTILITY OPERATIONS This section discusses IPC's utility operations, which 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 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 and 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: MWhs Percent of total (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 utility operating results. Each line is analyzed in more detail below. 2000-2001 1999-2000 Increase Increase 2001 2000 (Decrease) 1999 (Decrease) (in millions of dollars) Operating revenues: General business $ 650 $ 565 $ 85 $ 516 $ 49 Off-system 220 230 (10) 120 110 Other 44 42 2 24 18 Total operating revenues 914 837 77 660 177 Operating expenses: Purchased power 584 399 185 106 293 Fuel 98 94 4 87 7 PCA (176) (121) (55) (1) (120) Other operating expenses 318 296 22 296 - Total operating expenses 824 668 156 488 180 Operating income $ 90 $ 169 $ (79) $ 172 $ (3) General Business Revenue The following table presents IPC's general business revenues and volumes for the last three years: Revenues Volumes (in millions of (in thousands of dollars) MWh) 2001 2000 1999 2001 2000 1999 Residential $ 260 $ 225 $ 214 4,307 4,393 4,200 Commercial 164 132 123 3,380 3,404 3,194 Industrial 154 133 117 3,925 4,808 4,666 Irrigation 72 75 62 1,419 1,993 1,706 Total $ 650 $ 565 $ 516 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 millions) MWh (in thousands) Revenue per MWh 2001 2000 1999 2001 2000 1999 2001 2000 1999 $220 $230 $120 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 millions) MWh (in thousands) Cost per MWh 2001 2000 1999 2001 2000 1999 2001 2000 1999 $584 $399 $106 3,445 4,311 3,127 $169.52 $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 $ (in millions) Thermal MWh generated (in thousands) 2001 2000 1999 2001 2000 1999 $ 98 $ 94 $ 87 7,622 7,701 7,266 2001 vs. 2000: Expenses increased in 2001, despite decreased generation. Average coal prices increased, and our new 90-MW 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. ENERGY MARKETING IE markets electricity and natural gas, and offers risk management and asset optimization services, to wholesale customers in 31 states and two Canadian provinces. IE has offices in Boise, Idaho and Houston, Texas and employs approximately 120 people. Our energy marketing strategy has produced increasingly positive results through growing the volume of energy delivered, expanding the geographic area in which we do business, and capitalizing on the recent high volatility of energy prices. While we continue to be active in the natural gas markets, our business expansion has primarily been driven from three interdependent strategies in the electricity markets. First, we use our expertise in the physical power system within the western United States to purchase the rights to strategic transmission. While we have no obligation to renew these rights annually, many of them can be extended indefinitely, barring any regulatory changes, giving us the ability to assess the value of the rights on an annual basis before renewal. The second piece of our strategy is to buy and sell energy around these contractual transmission assets and take advantage of market price movements between regions while limiting our market risk. Third, we use our knowledge of the physical system coupled with our risk management expertise to create customized, or structured, energy solutions for end-use customers. Additionally, IE offers asset management services to utilities and other regulated energy providers. One such agreement is with our affiliate, IPC. Concurrent with the June 2001 transfer of the non- utility electricity marketing business from IPC to IE, IE and IPC have entered into an Electricity Supply Management Services Agreement (Agreement). IPC received approval of the Agreement from the IPUC, the OPUC and the FERC. Under the Agreement, IPC will continue to own, operate and maintain its electric generating equipment and transmission facilities (system resources) and be responsible for system reliability. IE will manage and dispatch the system resources to balance generation and load within the IPC operating area. Operating income for IE was $177 million in 2001 compared to $95 million in 2000. Gross margin for 2001 was $243 million, $92 million of which is unrealized gains related to the change in value of our forward position. On a cumulative basis, we anticipate that approximately 39 percent of these unrealized forward positions recorded at year end 2001 will be settled by the end of 2002, 57 percent settled by the end of 2003 and 71 percent settled by the end of 2004. All forward positions at December 31, 2001 should be settled within 10 years. Changes in market conditions in future periods could substantially change the amounts of gain or loss ultimately realized upon settlement of the contracts. Revenues We now report on a gross revenue and gross expense basis, rather than the netting method previously used. Settled physical sales now are reported as revenue and settled physical purchases are reported as operating expenses. Both revenues and expenses have been reclassified to reflect this change. This change has been made since the power marketing operation was consolidated under IE. When power marketing was housed within IPC, the gross method of reporting energy marketing revenues would have a caused a potential distortion to the reported utility results. Therefore, we elected to report energy marketing revenues on a net basis. Now that power marketing is fully separated from the utility, the gross presentation provides a more clear comparison of our marketing and trading activities in relationship to similar companies. The following table presents our energy marketing revenues and volumes (including intersegment transactions) for the last three years: 2000-2001 1999-2000 Increase Increase 2001 2000 (Decrease) 1999 (Decrease) (in millions of dollars) Operating revenues: Electricity $ 4,531 $ 2,191 $ 2,340 $ 594 $ 1,597 Gas 362 271 91 278 (7) Total operating revenues $ 4,893 $ 2,462 $ 2,431 $ 872 $ 1,590 Operating volumes (settled): Electricity (MWh's) 34,936,951 23,518,484 11,418,467 14,433,650 9,084,834 Gas (mmbtu's) 97,327,432 80,728,530 16,598,902 141,432,755 (60,704,225) 2001 vs. 2000: The 99 percent increase in 2001 energy marketing revenue is due primarily to increased volumes and prices. Settled physical electricity sales increased 49 percent. Electricity prices in 2001 were, on average, nearly 40 percent higher than in 2000. 2000 vs. 1999: The 182 percent increase in 2000 energy marketing revenue is also due primarily to increased volumes and prices. Settled physical electricity sales increased 63 percent. Electricity prices in 2000 were, on average, 125 percent higher than in 1999. Operating Expenses The following table presents our energy marketing operating expenses for the last three years: 2000-2001 1999-2000 Increase Increase 2001 2000 (Decrease) 1999 (Decrease) (in millions of dollars) Electricity $ 4,360 $2,098 $ 2,262 $571 $ 1,527 Gas 356 269 87 279 (10) Total operating expenses $ 4,716 $2,367 $ 2,349 $850 $ 1,517 2001 vs. 2000: The 99 percent increase in operating expenses is also due primarily to the increase in volumes and prices. 2000 vs. 1999: The 178 percent increase for the year is due primarily to the increase in volumes and prices and also to an increase in the allowance for bad debt. The expense related to bad debt reserves in 2000 was $22 million compared to $0 in 1999. These reserves are related to trading activities conducted with California entities in 2000. Contracts Accounted for at Fair Value The commodity transactions entered into by IE are classified as energy trading contracts, or derivatives. These contracts are carried on the balance sheet at fair value. This accounting treatment is also referred to as mark-to-market accounting. Mark-to- market accounting can create a disconnect between recorded earnings and realized cash flow. Marking a contract to market consists of reevaluating the market value of the entire term of the contract at each reporting period and reflecting the resulting gain or loss of value in earnings for the period. This change in value represents the difference between the contract price and the current market value of the contract. The change in market value of the contract could result in large gains or losses recorded in earnings at each subsequent reporting period unless there are offsetting changes in value of hedge contracts. The gain or loss in income generated from the change in market value of the energy trading contracts is a non- cash event. If these contracts are held to maturity, the cash flow from the contracts, and their hedges, is realized over the life of the contract. When determining the fair value of our marketing and trading contracts, we use actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities. To determine fair value of contracts with terms that are not consistent with actively quoted prices, we use (when available) prices provided by other external sources. When prices from external sources are not available, we determine prices by using internal pricing models that incorporate available current and historical pricing information. Finally, we adjust the fair market value of our contracts for the impact of market depth and liquidity, potential model error, and expected credit losses at the counterparty level. The following table details the gross margin booked from our marketing operations over the last three years: 2001 2000 1999 (in millions of dollars) Gross Margin: Realized or otherwise settled $ 150 $ 181 $ 28 Unrealized 93 (35) 4 Total gross margin $ 243 $ 146 $ 32 At year-end 2001, 69 percent of the credit exposure related to our unrealized positions is with investment grade couterparties. Less than 0.5 percent is with non-investment grade counterparties. The remaining 31 percent of year-end credit exposure is with non-rated counterparties. The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives. The change in net fair value (energy marketing assets less energy marketing liabilities) between year-end 2000 and year-end 2001 is explained as follows (in millions of dollars): Net fair value of contracts outstanding as of 12/31/2000 $ (3) Contracts realized or otherwise settled during the period (150) Changes in net fair values attributable to changes in valuation techniques and assumptions 7 Changes in net fair value attributable to market prices and other market changes 284 Net fair value of contracts outstanding as of 12/31/2001 $ 138 Net fair value at year-end 2001 disaggregated by source of fair value and maturity of contracts: Maturity Maturity Source of less than Maturity Maturity in excess of Grand Fair Value 1 year 1-3 years 4-5 years 5 years Total (in millions of dollars) Prices actively quoted $ 34 $ 37 $ 3 $ 0 $ 74 Prices provided by other external sources 16 27 (1) 6 48 Prices based on models and other valuation methods 19 (5) 1 1 16 Total $ 69 $ 59 $ 3 $ 7 $ 138 Prices actively quoted are quoted daily by brokers and trading exchanges such as NYMEX, TFS, Intercontinental, and Bloomberg. The time horizon is January 2002 through December 2006. Products include physical, financial, swap, interest rate, index, and basis for both natural gas and heavy load power. Prices provided by other external sources are quoted periodically by brokers and trading exchanges such as TFS, APB, Prebon, Intercontinental, and Bloomberg. The time horizon is January 2002 through December 2010. Products include physical, financial, swap, index, and basis for both natural gas and heavy and light load power. Prices derived from models and other valuation methods incorporate available current and historical pricing information. The time horizon is January 2002 through December 2009. Products include transmission, options, and ancillary services related to heavy and light load power. OTHER OPERATIONS Other operations include the results of operations of our diversified subsidiaries, including IDACOMM, Velocitus, Ida-West, IdaTech, IFS, and Applied Power Company (APC) (sold in January 2001). In August 2000, we formed IDACOMM, Inc. to provide integrated communication services to business customers throughout the West, using fiber optic network technology. Also, in August 2000, we acquired a controlling interest in Velocitus (formerly Rocky Mountain Communications, Inc.), a Boise, Idaho-based Internet service provider. Since the acquisition, Velocitus launched a new service-Velocitus Broadband, which emphasizes the use of fixed wireless technology, allowing for rapid deployment of high-speed connectivity for business customers. Velocitus currently serves more than 25,000 subscribers of traditional and high-speed Internet access services. Ida-West develops, acquires, owns and manages electric power generation projects. In December 2001, IdaTech, a majority owned subsidiary of IDACORP, continued to make progress by delivering nine second generation fuel cell systems, of the first block of 50 units, to the Bonneville Power Administration (BPA) for field testing. IdaTech continues to develop and seek business partners in North America, Europe, and Asia to help support the commercialization of its fuel processor and fuel cell systems. IdaTech has delivered fuel processors and fuel cell systems to companies in those three continents for evaluation and testing in various field applications. IFS, a wholly owned subsidiary of IDACORP, makes investments in projects that provide affordable housing tax credits and historic tax credits. In January 2001, we sold APC to Schott Corp. APC is a manufacturer, supplier and distributor of solar photovoltaic systems. IDACORP originally acquired APC in 1996. Revenues 2001 vs. 2000: Other operations revenues decreased $10 million in 2001 due primarily to the sale of APC. APC generated revenues of $16 million in 2000. This decrease was partially offset by a $5 million increase in sales at Velocitus, which was acquired in August 2000. 2000 vs. 1999: Other operations revenues decreased $4 million in 2000 due primarily to reduced sales made at APC. Expenses 2001 vs. 2000: Other operations expenses decreased $2 million in 2001 due primarily to the sale of APC. APC incurred $17 million of expenses in 2000. Increased expenses related to product development activities at IdaTech ($8 million) and Velocitus ($7 million) offset the decrease from APC. 2000 vs. 1999: Other operations expenses increased $5 million in 2000 due primarily to $5 million of increases from both Velocitus, (acquired in August 2000), and from increased activities at IdaTech, offset by a $5 million reduction in expenses at APC. OTHER INCOME AND EXPENSES Other Income 2001 vs. 2000: Other income decreased $7 million in 2001, due primarily to the sale in 2000 of our interest in the Hermiston Power Project, a 536-MW, gas-fired cogeneration project to be located near Hermiston, Oregon. Ida-West was responsible for managing all permitting and development activities relating to the project since its inception in 1993. We recorded a pre-tax gain of $14 million on this transaction in 2000. This decrease was partially offset by a gain recognized in 2001 related to the early redemption by the Friant Power Authority of outstanding bonds held by Ida-West. 2000 vs. 1999: Other income increased $13 million in 2000 due primarily to the sale of our interest in the Hermiston Power Project. We recorded a pre-tax gain of $14 million on this transaction. Interest Expense and Other Interest expense and other increased $9 million in 2001 and was unchanged in 2000. The increase in 2001 is 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 $232 million, compared to $36 million in 2000. Income taxes Fluctuations in income tax expense result primarily from changes in net income before taxes. 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 $356 million for the three-year period 1999-2001. After deducting common dividends of $210 million, net cash generation from operations provided approximately $146 million for our construction program and other capital requirements. Internal cash generation after dividends provided 42 percent of our total capital requirements in 2000 and 114 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 IDACORP's total contractual cash obligations: 2002 2003 2004 2005 2006 Thereafter (in millions of dollars) Utility long- term debt $27 $80 $50 $60 $ - $612 Other long- term debt 9 9 9 8 6 9 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. We have bank line of credit facilities established at both IPC and IDACORP. 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. IPC's commercial paper may be issued up to the amount supported by the bank credit facilities. IDACORP has a $375 million facility that expires on April 15, 2002 and a $50 million facility that expires on April 20, 2002. Under these facilities we pay a facility fee on the commitment, quarterly in arrears, based on IDACORP's senior unsecured long-term debt rating. Commercial paper may be issued up to the amounts supported by the bank credit facilities. At December 31, 2001, IDACORP's short-term borrowing totaled $81 million, compared to $61 million at December 31, 2000. IDACORP is currently in the process of renewing its credit lines at both IDACORP (for $500 million) and IPC (for $200 million) with closing anticipated in March 2002. Credit Ratings All of the Company's publicly traded debt as well as that of IPC 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 and IPC will continue to evaluate their capital structures, 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 or IPC's securities and serve to increase those companies' cost of capital. Some collateral agreements in place between IE and its counterparties include provisions requiring additional margining in the event of a credit rating downgrade. Credit rating changes within the investment grade category should not materially impact the liquidity or financial condition of IE. A credit downgrade below an investment grade rating could result in additional margin calls that could have a material negative impact to the liquidity of IDACORP. The Company believes its existing credit facilities are adequate to fund these potential liquidity requirements. Working Capital Net working capital (current assets less current liabilities) decreased approximately $213 million from December 31, 2000 to December 31, 2001. The most significant changes were in notes payable and energy marketing assets and liabilities. The primary cause of the increase in notes payable is power supply expenditures. We discuss recovery of these costs in "Regulatory Issues" later in the MD&A. Energy marketing assets and liabilities reflect the fair value of energy marketing contracts as of the reporting date. The fair value of these contracts is unrealized and therefore does not necessarily indicate a current source or use of funds. The decreases in energy marketing assets and liabilities from 2000 to 2001 is primarily a reflection of significantly lower market prices at December 31, 2001, than in the prior year. Additional netting agreements between IE and its counterparties also contributed to a reduction in the energy assets and liabilities. Finally, an increase in posted collateral supporting our energy trading contracts further reduced the energy trading liability. Construction Program Our consolidated cash construction expenditures totaled $180 million in 2001, $140 million in 2000, and $111 million in 1999. Approximately 25 percent of these expenditures were for generation facilities, 19 percent for transmission facilities, 30 percent for distribution facilities, and 26 percent for general plant and equipment. We estimate that our cash construction and acquisition programs will require the following amounts over the next three years. These estimates are subject to revision in light of changing economic, regulatory, environmental, and conservation factors. 2002 2003-2004 (in millions of dollars) Utility $124 $267 Energy marketing 7 2 Other 63 197 Total $194 $466 Financing Program Our consolidated capital structure fluctuated slightly during the three-year period, with common equity ending at 48 percent, preferred stock of IPC 6 percent, and long-term debt 46 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. We are proceeding with our plans to issue equity and debt securities this year. The equity issuance could take the form of common equity, mandatorily redeemable equity securities, or both. We are also planning to raise additional debt to provide balance in the capital that we raise. The Company is still reviewing its options with regard to type of securities, size and timing, but we expect that the capital will be raised in the first half of 2002. In February 2002, IPC notified holders of its $50 million 8 3/4% Series First Mortgage Bonds due 2027 of its intent to redeem these bonds on March 15, 2002. IDACORP currently has a $300 million shelf registration statement that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At December 31, 2001, none had been issued. 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. California Energy Situation As a component of IPC's non-utility energy trading in the state of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation. The CalPX, at that time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold. Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation agreement, if a participant in the CalPX exchange defaults on a payment to the exchange, the other participants are required to pay their allocated share of the default amount to the exchange. The allocated shares are based upon the level of trading activity, which includes both power sales and purchases, of each participant during the preceding three-month period. On January 18, 2001, the CalPX sent IPC an invoice for $2.2 million - a "default share invoice" - as a result of an alleged Southern California Edison (SCE) payment default of $214.5 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5.2 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E), and others. However, because the CalPX owed IPC $11.3 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. IPC essentially discontinued energy trading with California entities in December 2000. IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with FERC to intervene in a proceeding which requested the FERC to suspend the use of the CalPX charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures. A preliminary injunction was granted by a Federal Judge in the Federal District Court for the Central District of California enjoining the CalPX from declaring any CalPX participant in default under the terms of the CalPX Tariff. On March 9, 2001, the CalPX filed for Chapter 11 protection with the U.S. Bankruptcy Court, Central District of California. In April 2001, PG&E filed for bankruptcy. The CalPX and the California Independent System Operator (Cal ISO) were among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of our receivables from the CalPX and Cal ISO our receivables from these entities are at greater risk. Also in April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity market. Subsequently, in its June 19, 2001 Order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to refund portions of their sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act. The June 19 Order also required all buyers and sellers in the Cal ISO market during the subject time-frame to participate in settlement discussions to explore the potential for resolution of these issues without further FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC Chief Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt his methodology set forth in his report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology. The Judge recommended that his methodology should be applied to all sellers except those who at the evidentiary hearing are able to demonstrate that their costs exceed the results of the recommended methodology. On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001. As to potential refunds, if any, the Company believes that its exposure will be more than offset by amounts due it from California entities. In addition, the July 25, 2001 FERC order established another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC Administrative Law Judge (ALJ) submitted her recommendations and findings to the FERC on September 24, 2001. The ALJ found that the prices were just and reasonable and therefore no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have filed requests for rehearing and petitions for review. The ALJ has re-established a procedural schedule which would result in finding of fact and recommended conclusions during August 2002; such schedule is subject to Commission review. Actions of the FERC are appealable to the United States Court of Appeals. The Company will continue to monitor all proceedings to determine the impact on the Company. Counsel has been retained in connection with the CalPX and PG&E bankruptcies and FERC proceedings. Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with the June 11 transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At December 31, 2001, the CalPX and Cal ISO owed $13 million and $31 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $41 million against these receivables. These reserves were calculated taking into account the uncertainty of collection, given the current California energy situation. Based on the reserves recorded as of December 31, 2001, the Company believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on the Company's financial position, results of operations or cash flows. 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 the Company'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 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 the Company'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 now 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. IE buys and sells financial and physical natural gas and electricity commodity contracts as part of our ongoing business. These contracts are subject to electricity and natural gas commodity price risk as well as interest rate risk. We have a risk management policy defining the limits within which we contain our commodity price risk. We trade commodity futures, forwards, options and swaps as a method of managing the commodity price risk and optimizing the profitability of our electricity and natural gas trading. We have minimal foreign exchange exposure related to natural gas trading activities in Canadian dollars. This exposure is periodically offset through the use of foreign exchange swap instruments. Our sensitivity related to foreign exchange rate fluctuations as of December 31, 2001 is immaterial. We also transact in interest rate futures and swaps to manage the interest rate risk embedded in our commodity portfolio. Interest Rate Risk Sensitivity This table presents descriptions of our financial instruments at December 31, 2001, that are sensitive to changes in interest rates. 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 29 percent of our total debt is variable in the form of commercial paper. By nature, the value of our variable rate debt is not sensitive to changes in interest rates, and the value of our commercial paper borrowings does not give rise to significant interest rate risk because these borrowings generally have maturities of less than three months. The table below presents principal cash flows by maturity date and the related average interest rate. The table also presents the fair value for all fixed rate instruments as of December 31, 2001, based on market rates for similar instruments as of that date. Expected Amount Average Maturity Date due interest rate (in millions) 2002 $ 36 6.8% 2003 89 6.5% 2004 59 7.9% 2005 68 6.0% 2006 6 7.2% Thereafter 550 7.4% Total $ 808 7.2% Fair Value $ 847 Commodity Price Risk Sensitivity This analysis presents the December 2001 value-at-risk of our energy commodity contracts and related derivative instruments that are sensitive to changes in commodity prices. We use commodity derivative instruments such as futures, forwards, options and swaps to manage our exposure to commodity price risk in the electricity and natural gas markets. We also use interest rate futures and swaps to manage the interest rate risk embedded in the energy commodity portfolio. When buying and selling energy, the high volatility of energy prices can have significant negative impact on profitability if not appropriately managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into can withstand potentially dramatic market fluctuations. To manage the risks inherent in the energy commodity industry while implementing our business strategy, our Risk Management Committee (RMC), comprised of Company officers, oversees the risk management program as defined in our risk management policy. The objective of our risk management program is to mitigate the risk associated with the purchase and sale of natural gas and electricity. Company policy also allows the use of these commodity derivative instruments for trading purposes in support of our operations. The value-at- risk measure is a tool used by our RMC to understand on a daily basis the potential impact to earnings arising from market price risks as the markets change. The value at risk at year-end 2001 of our energy marketing activity is $1.3 million at a 95 percent confidence level and for a holding period of one business day and $1.8 million at a 99 percent confidence level and a one-day holding period. The average value-at- risk for 2001 at a 95 percent confidence level and one-day holding period was $3.9 million. The value-at-risk was calculated using an analytic value-at-risk methodology. This methodology computes value- at-risk based upon forward market prices and historical volatilities as of December 31, 2001. The value-at-risk is understood to be a forecast and is not guaranteed to occur. The 95 percent confidence level and one-day holding period imply that there is a five percent chance that the daily loss will exceed $1.3 million. The 99 percent confidence level implies a one percent chance that daily loss will exceed $1.8 million. The value-at-risk calculation is principally affected by market prices and volatility of prices. The RMC actively manages the risk to keep our trading activities within trading limits. Environmental and Legal Issues Overton Power District No. 5 IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5 (Overton), a Nevada electric improvement district, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts of electrical energy per hour from IE at $88.50 per megawatt hour, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract. IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as agreed. On December 14, 2001, we notified Overton that we terminated the contract due to their failure to meet payment obligations. We believe that Overton's breach of contract is completely without basis and intend to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits. At December 31, 2001, we had a $74 million long-term asset related to the Overton claim. We will review the recoverability of the asset on an ongoing basis. 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, the Company has been cooperating with the federal agencies by moving and shaping water acquired by the BOR through the HCC. In the past, the Company 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, the Company 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. The Company 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 Company has a $13 million goodwill balance (net of amortization) at December 31, 2001, and recorded amortization expense of approximately $3 million in 2001. The Company will be performing transitional impairment tests of its goodwill balances in the first half of 2002. 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. The Company 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." The Company 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. IE values its energy trading contracts using mark-to-market accounting under Emerging Issue Task Force (EITF) 98-10 and SFAS 133. As explained previously in our discussion of energy marketing, this accounting requires the Company to consider several factors, including current relevant market prices, market depth and liquidity, potential model error, and expected credit losses at the counterparty level. Due to the volatility of energy markets and certain model assumptions, changes in market conditions could substantially change the amounts of gains or losses ultimately realized in settlement of the contracts. 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 41 Consolidated Financial Statements: IDACORP, Inc. Consolidated Statements of Income for the Years Ended December 31, 2001, 2000 and 1999 43 Consolidated Balance Sheets as of December 31, 2001 and 2000 44-45 Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000 and 1999 46 Consolidated Statement of Shareholders' Equity for the Years Ended December 31, 2001, 2000 and 1999 47 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2001, 2000 and 1999 48 Notes to Consolidated Financial Statements 49-69 Independent Auditors' Report 70 Supplemental Financial Information and Financial Statement Schedule Supplemental Financial Information (Unaudited) 71 Financial Statement Schedule for the Years Ended December 31, 2001, 2000 and 1999: Schedule II-Consolidated Valuation and Qualifying Accounts 74 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of IDACORP, Inc. is responsible for the preparation and presentation of the information and representations contained in the accompanying financial statements. The financial statements have been prepared in conformance with generally accepted accounting principles. Where estimates are required to be made in preparing the financial statements, management has applied its best judgment as to the adequacy of the estimates based upon all available information. The Company maintains systems of internal accounting controls and related policies and procedures. The systems are designed to provide reasonable assurance that all assets are protected against loss or unauthorized use. Also, the systems provide that transactions are executed in accordance with management's authorization and properly recorded to permit preparation of reliable financial statements. The systems are supported by a staff of corporate accountants and internal auditors who, among other duties, evaluate and monitor the systems of internal accounting control in coordination with the independent auditors. The staff of internal auditors 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, the Company's independent auditors, who were responsible for conducting their audit in accordance with generally accepted auditing standards. Jan B. Packwood Darrel T. Anderson President and Vice President, Chief Chief Executive Financial Officer and Officer Treasurer IDACORP, Inc. Consolidated Statements of Income Year Ended December 31, 2001 2000 1999 (millions of dollars except for per share amounts) OPERATING REVENUES: Electric utility: General business $ 650 $ 565 $ 516 Off system sales 220 230 120 Other revenues 44 42 24 Total electric utility revenues 914 837 660 Energy marketing commodities and services 4,721 2,136 746 Other 13 23 27 Total operating revenues 5,648 2,996 1,433 OPERATING EXPENSES: Electric utility: Purchased power 584 399 106 Fuel expense 98 94 87 Power cost adjustment (176) (121) (1) Other operations and maintenance 211 196 196 Depreciation 87 80 78 Taxes other than income taxes 20 20 22 Total electric utility expenses 824 668 488 Energy marketing: Cost of energy commodities and services 4,478 1,990 714 Selling, general and administrative 66 51 10 Other 37 39 34 Total operating expenses 5,405 2,748 1,246 OPERATING INCOME: Electric utility 90 169 172 Energy marketing 177 95 22 Other (24) (16) (7) Total operating income 243 248 187 OTHER INCOME 23 30 17 INTEREST EXPENSE AND OTHER: Interest on long-term debt 56 53 54 Other interest 15 8 7 Preferred dividends of Idaho Power Company 5 6 6 Total interest expense and other 76 67 67 INCOME BEFORE INCOME TAXES 190 211 137 INCOME TAXES 65 71 46 NET INCOME $ 125 $ 140 $ 91 AVERAGE COMMON SHARES OUTSTANDING (000'S) 37,387 37,556 37,612 EARNINGS PER SHARE OF COMMON STOCK (basic and diluted) $ 3.35 $ 3.72 $ 2.43 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Balance Sheets December 31, 2001 2000 (millions of dollars) ASSETS CURRENT ASSETS: Cash and cash equivalents $ 67 $ 107 Receivables: Customer 207 244 Allowance for uncollectible accounts (43) (23) Employee notes 6 5 Other 11 16 Energy marketing assets 194 1,060 Taxes receivable 51 - Accrued unbilled revenues 37 45 Materials and supplies (at average cost) 26 30 Fuel stock (at average cost) 9 5 Prepayments 32 24 Regulatory assets 56 9 Total current assets 653 1,522 INVESTMENTS 159 176 PROPERTY, PLANT AND EQUIPMENT: Utility plant in service 2,990 2,800 Accumulated provision for depreciation (1,220) (1,143) Utility plant in service - net 1,770 1,657 Construction work in progress 96 136 Utility plant held for future use 2 2 Other property, net of accumulated depreciation 18 9 Property, plant and equipment - net 1,886 1,804 OTHER ASSETS: American Falls and Milner water rights 31 31 Company-owned life insurance 40 40 Energy marketing assets - long-term 204 44 Regulatory assets 544 370 Long-term receivables 74 - Other 51 53 Total other assets 944 538 TOTAL $ 3,642 $ 4,040 The accompanying notes are an integral part of these statements. IDACORP, Inc Consolidated Balance Sheets December 31, 2001 2000 (millions of dollars) LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of long-term debt $ 36 $ 40 Notes payable 363 121 Accounts payable 248 272 Energy marketing liabilities 125 1,060 Derivative liabilities 41 - Taxes accrued - 16 Interest accrued 15 17 Deferred income taxes 24 9 Other 55 28 Total current liabilities 907 1,563 OTHER LIABILITIES: Deferred income taxes 590 461 Energy marketing liabilities - long- term 135 47 Derivative liabilities - long-term 7 - Regulatory liabilities 114 111 Other 71 68 Total other liabilities 917 687 LONG-TERM DEBT 843 864 COMMITMENTS AND CONTINGENT LIABILITIES PREFERRED STOCK OF IDAHO POWER COMPANY 104 105 SHAREHOLDERS' EQUITY: Common stock, no par value (shares authorized 120,000,000; 37,628,919 and 37,612,351 shares issued, respectively) 454 453 Retained earnings 424 370 Accumulated other comprehensive income (loss) (4) (1) Treasury stock (66,188 and 44,425 shares at cost, respectively) (3) (1) Total shareholders' equity 871 821 TOTAL $ 3,642 $ 4,040 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Cash Flows Year Ended December 31, 2001 2000 1999 (millions of dollars) OPERATING ACTIVITIES: Net income $ 125 $ 140 $ 91 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Allowance for uncollectible accounts 20 22 - Unrealized (gains) losses from energy marketing activities (93) 35 (4) Gain on sales of assets (2) (14) - Depreciation and amortization 111 104 95 Deferred taxes and investment tax credits 150 47 (2) Accrued PCA costs (185) (122) (1) Change in: Receivables and prepayments 33 (179) 3 Accrued unbilled revenues 8 (13) 3 Materials and supplies and fuel stock - 4 (2) Accounts payable 4 126 44 Taxes (receivable) accrued (67) (6) (3) Other current assets and liabilities (50) (2) 5 Long-term receivable (74) - - Other - net 12 (8) 1 Net cash provided by (used in) operating activities (8) 134 230 INVESTING ACTIVITIES: Additions to property, plant and equipment (180) (140) (111) Investments in affordable housing projects - (29) (19) Proceeds from sales of assets 12 17 - Other - net (3) (1) (11) Net cash used in investing activities (171) (153) (141) FINANCING ACTIVITIES: Proceeds from issuance of: First mortgage bonds 120 80 80 Other long-term debt - 14 19 Retirement of: First mortgage bonds (130) (80) - Other long-term debt (14) (22) (10) Dividends on common stock (70) (70) (70) Increase (decrease) in short- term borrowings 242 101 (19) Common stock issued 1 - - Distributions of treasury stock 3 - - Acquisition of treasury stock (8) (8) - Other - net (5) - (1) Net cash provided by (used in) financing activities 139 15 (1) Net increase (decrease) in cash and cash equivalents (40) (4) 88 Cash and cash equivalents beginning of period 107 111 23 Cash and cash equivalents at end of period $ 67 $ 107 $ 111 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid (received) during the year for: Income taxes $ (18) $ 30 $ 52 Interest (net of amount capitalized) $ 70 $ 62 $ 56 Distributions of treasury stock for acquisition $ 8 $ 2 $ - The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Shareholders' Equity Accumulated Other Common Stock Retained Comprehenisve Treasury Stock Total Shares Amount Earnings Income (Loss) Share Amount Amount (millions of dollars except share amounts which are in thousands) Balance at January 1, 1998 37,612 $452 $ 279 $ - - $ - $731 Net income - - 91 - - - 91 Common stock dividends - - (70) - - - (70) Unrealized gain on securities (net of tax) - - - 1 - - 1 Balance at December 31, 1999 37,612 452 300 1 - - 753 Net income - - 140 - - - 140 Common stock dividends - - (70) - - - (70) Issued - - - - (155) 7 7 Acquired - - - - 199 (8) (8) Other - 1 - - - - 1 Unrealized loss on securities (net of tax) - - - (2) - - (2) Balance at December 31, 2000 37,612 453 370 (1) 44 (1) 821 Net income - - 125 - - - 125 Common stock dividends - - (70) - - - (70) Issued 17 1 - - (292) 11 12 Acquired - - - - 314 (13) (13) Other - - (1) - - - (1) Unrealized loss on securities (net of tax) - - - (2) - - (2) Minimum pension liability adjustment (net of tax) - - - (1) - - (1) Balance at December 31, 2001 37,629 $454 $ 424 $ (4) 66 $ (3) $871 The accompanying notes are an integral part of these statements. IDACORP, Inc. Consolidated Statements of Comprehensive Income Year Ended December 31, 2001 2000 1999 (millions of dollars) NET INCOME $ 125 $ 140 $ 91 OTHER COMPREHENSIVE INCOME (LOSS): Unrealized gains (losses) on securities (net of tax of ($1), ($2) and $1) (2) (2) 1 Minimum pension liability adjustment (net of tax of ($1)) (1) - - TOTAL COMPREHENSIVE INCOME $ 122 $ 138 $ 92 The accompanying notes are an integral part of these statements IDACORP, Inc. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Nature of Business IDACORP, Inc. (IDACORP or the Company) is a holding company whose principal operating subsidiaries are Idaho Power Company (IPC) and IDACORP Energy (IE). IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho, Oregon, Nevada and Wyoming, and is engaged in the generation, transmission, distribution, sale and purchase of electric energy. 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. IE markets electricity and natural gas, and offers risk management and asset optimization services, to wholesale customers in 31 states and two Canadian provinces. IDACORP's other subsidiaries include: Ida-West Energy - independent power projects development and management; IdaTech - developer of integrated fuel cell systems; IDACORP Financial Services (IFS) - affordable housing and other real estate investments; Velocitus - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Principles of Consolidation The consolidated financial statements include the accounts of the Company and wholly-owned or controlled subsidiaries. All significant intercompany balances have been eliminated in consolidation. Investments in business entities in which the Company and its subsidiaries do not have control, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. System of Accounts The accounting records of IPC conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon, Nevada and Wyoming. 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. The Company records repair and maintenance costs associated with planned major maintenance as these costs are incurred. At IPC 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. IPC's total reductions to interest expense for AFDC were $4 million, $2 million and $1 million, and other income included $1 million, $3 million and $2 million for 2001, 2000 and 1999, 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. IE reports marketing and trading revenues and expenses on a gross basis. The Company has reclassified revenues and expenses for prior years to conform to the current presentation. Within revenues there are three classifications. The first is the mark-to-market, or unrealized, gains or losses recorded as a result of reporting forward contracts at fair value. The change in the fair value of all forward energy transactions (purchases and sales) are netted and reported as one revenue amount. This revenue item may be positive or negative in any given reporting period. The second classification is settled financial transactions. Financial transactions, on settlement, are valued as either "in" or "out" of the money (positive or negative value) and the net cash is either received from or paid to the corresponding counterparty. These transactions also are netted within revenue and can be either positive or negative in any reporting period. The third classification is settled physical deals. Settled physical sales transactions are reported as revenue and settled physical purchases are reported as operating expenses. Other cost of sales items such as transmission and broker fees are reported as operating expenses. Derivative Financial Instruments The Company uses financial instruments such as commodity futures, forwards, options and swaps to manage exposure to commodity price risk in the electricity and natural gas markets. The objective of the Company's risk management program is to mitigate the risk associated with the purchase and sale of electricity and natural gas as well as to optimize its energy marketing portfolio. The accounting for derivative financial instruments that are used to manage risk is in accordance with the concepts established in Emerging Issue Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy Trading Activities," and Statement of Financial Accounting Standard (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 The Company follows the liability method of computing deferred taxes on all temporary differences between the book and tax basis of assets and liabilities and adjusts deferred tax assets and liabilities for enacted changes in tax laws or rates. Consistent with orders and directives of the 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). 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. Earnings Per Share (EPS) The computation of diluted EPS differs from basic EPS only due to including potentially dilutive shares related to stock-based compensation awards. The diluted EPS calculation includes immaterial amounts of potentially dilutive shares for the periods presented. The diluted EPS computation for 2001 excluded 274,000 common stock options because the options' exercise price was greater than the average market price of the common stock. The options, which expire in 2011, were still outstanding at the end of 2001. There were no such options excluded from the diluted EPS calculation in 2000 and 1999. 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, the Company adopted the 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. Investments IFS invests in affordable housing projects that are accounted for in accordance with EITF 94-1 "Accounting for Tax Benefits Resulting from Investments in Affordable Housing Projects" and shown in the caption "Investments" on the balance sheet. IFS accounts for these investments using the equity method. All projects are reviewed periodically for impairment. At December 31, 2001 and 2000 the net affordable housing projects included in investments were $95 and $102 million. 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 the Company's comprehensive income include net income, unrealized holding gains (losses) on marketable securities, the Company'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 the Company'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. The Company 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 Company has a $13 million goodwill balance (net of amortization) at December 31, 2001 and recorded amortization expense of approximately $3 million in 2001. The Company will be performing transitional impairment tests of its goodwill balances in the first half of 2002. 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. The Company 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." The Company 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 shareholders' equity were not affected by these reclassifications. 2. INCOME TAXES: The Company 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 (millions of dollars) Computed income taxes based on statutory federal income tax rate $ 67 $ 74 $ 48 Change in taxes resulting from: AFDC (2) (2) (1) Investment tax credits (3) (3) (3) Repair allowance (3) (4) (3) Settlement of prior years tax returns (1) - - State income taxes (net of federal reduction) 8 9 6 Depreciation 10 8 7 Affordable housing and historic tax credits (net of related deferred taxes) (13) (13) (9) Preferred dividends of IPC 2 2 2 Other - - (1) Total provision for federal and state income taxes $ 65 $ 71 $ 46 Effective tax rate 34.2% 33.6% 33.6% The provision for income taxes consists of the following: 2001 2000 1999 (millions of dollars) Income taxes currently (receivable) payable: Federal $ (67) $ 19 $ 38 State (18) 5 10 Total (85) 24 48 Income taxes deferred - net of amortization: Federal 122 41 2 State 26 7 (2) Total 148 48 - Investment tax credits: Deferred 5 2 1 Restored (3) (3) (3) Total 2 (1) (2) Total provision for income taxes $ 65 $ 71 $ 46 The tax effects of significant items comprising the Company's net deferred tax liability are as follows: 2001 2000 (millions of dollars) Deferred tax assets: Regulatory liabilities $ 41 $ 40 Advances for construction 4 9 Other 17 24 Total 62 73 Deferred tax liabilities: Utility plant 250 250 Regulatory assets 210 214 Conservation programs 11 14 PCA 119 47 Net energy trading assets 72 1 Other 14 17 Total 676 543 Net deferred tax liabilities $614 $470 3. COMMON STOCK: As of December 31, 2001 there were 4,274,753 shares of authorized but unissued shares of IDACORP common stock reserved for future issuance under the Company's Dividend Reinvestment and Stock Purchase Plan and IPC's Employee Savings Plan. In addition, 314,114 shares are reserved for the Restricted Stock Plan and 2,050,000 shares for the Long-Term Incentive and Compensation Plan (LTICP) (see Note 9). In 2001 the Company acquired 198,200 shares of outstanding common stock, at a cost of $8 million, for potential distribution to shareholders of an acquired entity as partial payment for the acquisition. In 2000 the Company acquired 156,300 shares at a cost of $7 million for the same purpose. The Company has issued 226,684 shares to the shareholders of the acquired entity. An additional 65,416 shares are contingently issuable over the next three years. Of the remaining acquired shares, 61,628 were issued in connection with our dividend reinvestment program. The Company issued 16,568 original issue shares in 2001 for the Employee Savings Plan (see Note 10). The Company has a Shareholder Rights Plan (Plan) designed to ensure that all shareholders receive fair and equal treatment in the event of any proposal to acquire control of the Company. Under the Plan, the Company declared a distribution of one Preferred Share Purchase Right (Right) for each of the Company's outstanding Common Shares held on October 1, 1998 or issued thereafter. The Rights are currently not exercisable and will be exercisable only if a person or group (Acquiring Person) either acquires ownership of 20 percent or more of the Company's Voting Stock or commences a tender offer that would result in ownership of 20 percent or more of such stock. The Company may redeem all but not less than all of the Rights at a price of $0.01 per Right or exchange the Rights for cash, securities (including Common Shares of the Company) or other assets at any time prior to the close of business on the 10th day after acquisition by an Acquiring Person of a 20 percent or greater position. Additionally, the IDACORP Board created the A Series Preferred Stock, without par value, and reserved 1,200,000 shares for issuance upon exercise of the Rights. Following the acquisition of a 20 percent or greater position, each Right will entitle its holder to purchase for $95 that number of shares of Common Stock or Preferred Stock having a market value of $190. If after the Rights become exercisable, the Company is acquired in a merger or other business combination, 50 percent or more of its consolidated assets or earnings power are sold, or the Acquiring Person engages in certain acts of self-dealing, each Right entitles the holder to purchase for $95, shares of the acquiring company's common stock having a market value of $190. Any Rights that are or were held by an Acquiring Person become void if any of these events occurs. The Rights expire on September 30, 2008. The Rights themselves do not give any voting or other rights as shareholders to their holders. The terms of the Rights may be amended without the approval of any holders of the Rights until an Acquiring Person obtains a 20 percent or greater position, and then may be amended as long as the amendment is not adverse to the interests of the holders of the Rights. 4. PREFERRED STOCK OF IDAHO POWER COMPANY: The number of shares of IPC preferred stock outstanding at December 31, 2001 and 2000 were as follows: Shares Outstanding at December 31, Call Price 2001 2000 Per Share 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 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. 5. LONG-TERM DEBT: The following table summarizes long-term debt at December 31: 2001 2000 (millions of dollars) First mortgage bonds: 6.93% Series due 2001 $ - $ 30 6.85% Series due 2002 27 27 6.40% Series due 2003 80 80 8 % Series due 2004 50 50 5.83% Series due 2005 60 60 7.38% Series due 2007 80 80 7.20% Series due 2009 80 80 6.60% Series due 2011 120 - Maturing 2021 through 2027 with rates ranging from 7.5% to 8.75% 130 230 Total first mortgage bonds 627 637 Pollution control revenue bonds: 8.30% Series 1984 due 2014 50 50 6.05% Series 1996A due 2026 68 68 Variable Rate Series 1996B due 2026 24 24 Variable Rate Series 1996C due 2026 24 24 Variable Rate Series 2000 due 2027 4 4 Total pollution control revenue bonds 170 170 REA notes 1 1 American Falls bond guarantee 20 20 Milner Dam note guarantee 12 12 Unamortized premium/discount - net (1) (1) Debt related to investments in affordable housing 50 64 Other subsidiary debt - 1 Total 879 904 Less current maturities of long- term debt (36) (40) Total long-term debt $ 843 $ 864 At December 31, 2001, the maturities for the aggregate amount of long-term debt outstanding were (in millions of dollars): Unregulated Utility Business 2002 $ 27 $ 9 2003 80 9 2004 50 9 2005 60 8 2006 - 6 Thereafter 612 9 Total $829 $ 50 The Company currently has a $300 million shelf registration statement that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At December 31, 2001, none had been issued. 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. At December 31, 2001, IFS has $50 million of debt with interest rates ranging from 6.03 percent to 8.59 percent due 2002 to 2011. This debt is collateralized by investments in affordable housing projects with a book value of $95 million at December 31, 2001. 6. FAIR VALUE OF FINANCIAL INSTRUMENTS: The estimated fair value of the Company's financial instruments has been determined by the Company using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for 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 the Company's debt was approximately $920 million in 2001 and $934 million in 2000. Included in receivables were notes totaling $16 million in 2001 and $12 million in 2000. Estimated fair value of these instruments was $17 million in 2001 and $13 million in 2000. Included in investments and other property were financial instruments totaling $34 million in 2001 and $35 million in 2000. Estimated fair value of these instruments was $34 million in 2001 and $40 million in 2000. 7. NOTES PAYABLE: At December 31, 2001, IDACORP has a $375 million facility that expires April 15, 2002, and a $50 million facility that expires April 20, 2002. Under these facilities the Company pays a facility fee on the commitment, quarterly in arrears, based on IDACORP's senior unsecured long-term debt rating. Commercial paper may be issued up to the amounts supported by the bank credit facilities. 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. IPC's commercial paper may be issued up to the amounts supported by the bank credit facilities. At December 31, 2001, IPC also 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 millions of dollars): 2001 2000 IDACORP balance at end of year $ 81 $ 61 IPC balance at end of year $ 282 $ 60 Combined effective annual interest rate at end of year 2.18% 6.74% 8. COMMITMENTS AND CONTINGENT LIABILITIES: Commitments under contracts and purchase orders relating to IPC's and Ida-West's program for construction and operation of facilities amounted to approximately $9 million and $30 million, respectively, at December 31, 2001. The commitments are generally revocable by the Company 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 year ended December 31, 2001, IPC purchased 728,155 MWh at a cost of $45 million. Legal Proceedings IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5 (Overton), a Nevada Electric Improvement District, for failure to meet payment obligations under a power contract. The contract provided for Overton to purchase 40 megawatts of electrical energy per hour from IE at $88.50 per megawatt hour, from July 1, 2001 through June 30, 2011. In the contract, Overton agreed to raise its rates to its customers to the extent necessary to make its payment obligations to IE under the contract. IE has asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as agreed. On December 14, 2001, IE notified Overton that the contract was terminated due to their failure to meet payment obligations. IE believes that Overton's breach of contract is completely without basis and intends to vigorously prosecute this lawsuit. While the outcome of litigation is never certain, IE believes it should prevail on the merits. At December 31, 2001, the Company had a $74 million long-term asset related to the Overton claim. IE will review the recoverability of the asset on an ongoing basis. From time to time the Company is party to various legal claims, actions, and complaints, certain of which may involve material amounts. Although the Company is unable to predict with certainty whether or not it will ultimately be successful in these legal proceedings, or, if not, what the impact might be, based upon the advice of legal counsel, management presently believes that disposition of these matters will not have a material adverse effect on the Company's financial position, results of operation, or cash flows. California Energy Situation As a component of IPC's non-utility energy trading in the state of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation. The CalPX, at this time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold. Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation agreement, if a participant in the CalPX exchange defaults on a payment to the exchange, the other participants are required to pay their allocated share of the default amount to the exchange. The allocated shares are based upon the level of trading activity, which includes both power sales and purchases, of each participant during the preceding three-month period. On January 18, 2001, the CalPX sent IPC an invoice for $2.2 million - a "default share invoice" - as a result of an alleged Southern California Edison (SCE) payment default of $214.5 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5.2 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E), and others. However, because the CalPX owed IPC $11.3 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. IPC essentially discontinued energy trading with California entities in December 2000. IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with FERC to intervene in a proceeding which requested the FERC to suspend the use of the CalPX charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures. A preliminary injunction was granted by a Federal Judge in the Federal District Court for the Central District of California enjoining the CalPX from declaring any CalPX participant in default under the terms of the CalPX Tariff. On March 9, 2001, the CalPX filed for Chapter 11 protection with the U.S. Bankruptcy Court, Central District of California. In April 2001, PG&E filed for bankruptcy. The CalPX and the California Independent System Operator (Cal ISO) were among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and Cal ISO the receivables from these entities are at greater risk. Also in April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity market. Subsequently, in its June 19, 2001 Order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to refund portions of their sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act. The June 19th Order also required all buyers and sellers in the Cal ISO market during the subject time-frame to participate in settlement discussions to explore the potential for resolution of these issues without further FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC Chief Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology. The Judge recommended that the methodology should be applied to all sellers except those who at the evidentiary hearing are able to demonstrate that their costs exceed the results of the recommended methodology. On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001. As to potential refunds, if any, the Company believes that its exposure will be more than offset by amounts due it from California entities. In addition, the July 25, 2001 FERC order established another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC Administrative Law Judge (ALJ) submitted recommendations and findings to the FERC on September 24, 2001. The ALJ found that the prices were just and reasonable and therefore no refunds should be allowed. Procedurally, the ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have filed requests for rehearing and petitions for review. The ALJ has re-established a procedural schedule which would result in findings of fact and recommended conclusions during August 2002; such schedule is subject to Commission review. Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with the June 11 transfer, the outstanding receivables and payables with the CalPX and Cal ISO were assigned from IPC to IE. At December 31, 2001, the CalPX and Cal ISO owed $13 million and $31 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $41 million against these receivables. These reserves were calculated taking into account the uncertaintity of collection, given the current California energy situation. Based on the reserves recorded as of December 31, 2001, the Company believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a significant impact on the Company's financial position, results of operations or cash flows. 9. STOCK-BASED COMPENSATION: The Company has two stock-based compensation plans that are intended to align employee and shareholder objectives related to the long- term growth of the Company. The Company adopted the 2000 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. The maximum number of shares available under the LTICP is 2,050,000. In 2000 and 2001, the Company issued a total of 494,000 stock options with an exercise price equal to the market price of the Company's stock on the date of grant. The maximum term of the options is ten years, and they vest ratably over a five-year period. In accordance with APB 25, no compensation costs have been recognized for the option awards. Stock option transactions are summarized as follows: 2001 2000 Weighted Weighted Number average Number average of exercise of exercise shares price shares price Outstanding beginning of year 220,000 $ 35.81 - $ - Granted 274,000 39.37 220,000 35.81 Exercised - - - - Cancelled - - - - Outstanding end of year 494,000 $ 37.79 220,000 $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 8.9 years. The Company 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 245,989 remaining shares available under this plan. Restricted stock awards are compensatory awards and the Company accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 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 53,555 43,615 43,063 Shares granted 23,529 34,649 23,497 Shares forfeited (474) - (9,585) Shares issued (19,918) (24,709) (13,360) Shares outstanding - end of year 56,692 53,555 43,615 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 and earnings per share would have been as follows (in millions of dollars except for per share amounts): 2001 2000 1999 Net income As reported $ 125 $ 140 $ 91 Pro forma 124 140 91 Basic and diluted earnings per share As reported $ 3.35 $ 3.72 $ 2.43 Pro forma 3.33 3.73 2.43 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 4.72% 5.19% Expected stock price volatility 29% 27% Risk-free interest rate 5.18% 6.15% Expected option lives 7 years 7 years Weighted average fair value of options granted $9.86 $8.42 10. BENEFIT PLANS: Pension Plans The Company has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee's final average earnings. The Company's policy is to fund with an independent corporate trustee at least the minimum required under the Employee Retirement Income Security Act of 1974 but not more than the maximum amount deductible for income tax purposes. The Company was not required to contribute to the plan in 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. The Company has a nonqualified, deferred compensation plan for certain senior management employees and directors. The Company financed this plan by purchasing life insurance policies and investments in marketable securities, all of which are held by a trustee. The cash value of the policies and investments exceed the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the funded status. The following table shows the components of net periodic benefit cost for these plans: Deferred Pension Plan Compensation Plan 2001 2000 1999 2001 2000 1999 (in millions of dollars) Service cost $ 8 $ 7 $ 8 $ - $ - $ - Interest cost 18 17 16 2 2 2 Expected return on assets (30) (30) (25) - - - Recognized net actuarial (gain) loss (3) (4) - - - - Amortization of prior service cost - - 1 - - - Amortization of transition asset - - - 1 1 1 Net periodic pension (benefit) cost $ (7) $ (10) $ - $ 3 $ 3 $ 3 The following table summarizes the changes in benefit obligation and plan assets of these plans (in millions of dollars): Deferred Pension Plan Compensation Plan 2001 2000 2001 2000 Change in projected benefit obligation: Benefit obligation at January 1 $ 241 $ 229 $ 28 $ 27 Service cost 8 7 - - Interest cost 18 17 2 2 Actuarial loss (gain) 19 - - 1 Benefits paid (13) (12) (2) (2) Plan amendments - - 2 - Benefit obligation at December 31 273 241 30 28 Change in plan assets: Fair value at January 1 341 340 - - Actual return on plan assets (2) 13 - - Employer contributions - - - - Benefit payments (13) (12) - - Fair value at December 31 326 341 - - Funded status 53 100 (30) (28) Unrecognized actuarial loss (gain) (32) (86) 8 7 Unrecognized prior service cost 8 8 - - Unrecognized net transition liability (1) (1) 2 2 Net amount recognized $ 28 $ 21 $ (20) $ (19) Amounts recognized in the statement of financial position consist of: Prepaid (accrued) pension cost $ 28 $ 21 $ (29) $ (26) Intangible asset - - 2 2 Accumulated other comprehensive income - - 7 5 Net amount recognized $ 28 $ 21 $ (20) $ (19) The following table sets forth the assumptions used at the end of each year for all IPC-sponsored pension and postretirement benefit plans: Pension Postretirement Benefits Benefits 2001 2000 2001 2000 Discount rate 7.0% 7.5% 7.0% 7.5% Expected long-term rate of return on assets 9.0 9.0 9.0 9.0 Annual salary increases 4.5 4.5 - - Employee Savings Plan The Company has an Employee Savings Plan which complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. The Company matches specified percentages of employee contributions to the plan. Matching contributions amounted to $4 million in 2001 and $3 million in 2000 and 1999. Postretirement Benefits The Company maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement, their spouses and qualifying dependents. The net periodic postretirement benefit cost was as follows (in millions of dollars): 2001 2000 1999 Service cost $ 1 $ 1 $ 1 Interest cost 3 3 3 Expected return on plan assets (2) (2) (2) Amortization of unrecognized transition obligation 2 2 2 Amortization of prior service cost (1) (1) (1) Amortization of unrecognized net gains - - - Net periodic post-retirement benefit cost $ 3 $ 3 $ 3 The following table summarizes the changes in benefit obligation and plan assets (in millions of dollars): 2001 2000 Change in accumulated benefit obligation: Benefit obligation at January 1 $ 49 $ 41 Service cost 1 1 Interest cost 3 3 Plan amendments 1 1 Actuarial loss 3 6 Benefits paid (3) (3) Benefit obligation at December 31 54 49 Change in plan assets: Fair value of plan assets at January 1 26 27 Actual (loss) return on plan assets (2) (1) Employer contributions 4 3 Benefits paid (3) (3) Fair value of plan assets at December 31 25 26 Funded status (29) (23) Unrecognized prior service cost (6) (7) Unrecognized actuarial loss (gain) 11 3 Unrecognized transition obligation 23 25 Accrued benefit obligations included with other deferred credits $ (1) $ (2) The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan is 6.75%. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in millions of dollars): 1-Percentage- 1-Percentage- Point Point increase decrease Effect on total of service and interest cost components $ - $ - Effect on accumulated postretirement benefit obligation $ 3 $ (3) Postemployment Benefits The Company provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under our disability plans, and health care for surviving spouses and dependents. The Company accrues a liability for such benefits. In accordance with an IPUC order, the portion of the liability attributable to regulated activities in Idaho as of December 31, 1993, was deferred as a regulatory asset, and is being amortized over ten years. The following table summarizes postemployment benefit amounts included in the Company's consolidated balance sheet at December 31 (in millions of dollars): 2001 2000 Included with regulatory assets $ 1 $ 2 Included with other deferred credits $(3) $(3) 11. 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 (in millions of dollars): 2001 2000 Balance Avg Balance Avg Rate Rate Production $ 1,425 2.58% $ 1,360 2.60% Transmission 460 2.30 410 2.30 Distribution 854 3.34 812 3.34 General and Other 251 6.12 218 5.42 Total in service 2,990 2.98% 2,800 2.94% Accumulated provision for depreciation (1,220) (1,143) In service - net $ 1,770 $ 1,657 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 are as follows: Company Ownership Accumulated Utility Provision Plant In for Name of Plant Location Service Depreciation % MW (millions of dollars) Jim Bridger Units 1-4 Rock Springs, WY $ 404 $ 222 33 707 Boardman Boardman, OR 65 38 10 55 Valmy Units 1 and 2 Winnemucca, NV 304 157 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. Power purchased from these facilities amounted to $6 million in 2001, $8 million in 2000 and $9 million in 1999. 12. INDUSTRY SEGMENT INFORMATION: The Company has identified two reportable operating segments, Utility Operations and Energy Marketing. The Utility Operations segment has two primary sources of revenue: the regulated operations of IPC and income from Bridger Coal Company, an unconsolidated joint venture also subject to regulation. IPC's regulated operations include the generation, transmission, distribution, purchase and sale of electricity. The Energy Marketing segment reflects the results of the operations of IE. IE markets electricity and natural gas and offers risk management and asset optimization services, to wholesale customers in 31 states and two Canadian provinces. IDACORP's other operations include: Ida-West - independent power projects development and management; IdaTech - developer of integrated fuel cell systems; IDACORP Financial Services (IFS) - affordable housing and other real estate investments; Velocitus - commercial and residential Internet service provider; IDACOMM - provider of telecommunications services. The following table summarizes the segment information for the Company's utility operations and energy marketing segments and the total of all other segments, and reconciles this information to total enterprise amounts. Utility Energy Consolidated Operations Marketing Other Eliminations Total (millions of dollars) 2001 Revenues from external customers $ 821 $4,721 $ 13 $ - $5,555 Intersegment revenues 93 172 - (172) 93 Operating income 90 177 (24) - 243 Other income 20 1 9 (7) 23 Interest expense 68 - 15 (7) 76 Income before income taxes 42 178 (30) - 190 Income taxes 20 71 (26) - 65 Net income 22 107 (4) - 125 Total assets 2,860 718 205 (141) 3,642 Expenditures for long- lived assets 163 7 9 - 179 2000 Revenues from external customers $ 650 $2,136 $ 23 $ - $2,809 Intersegment revenues 187 326 - (326) 187 Operating income 169 95 (16) - 248 Other income 17 3 15 (5) 30 Interest expense 64 - 8 (5) 67 Income before income taxes 122 98 (9) - 211 Income taxes 48 38 (15) - 71 Net income 74 60 6 - 140 Total assets 2,530 1,312 198 - 4,040 Expenditures for long- lived assets 126 7 38 - 171 1999 Revenues from external customers $ 496 $ 746 $ 27 $ - $1,269 Intersegment revenues 164 126 - (126) 164 Operating income 172 22 (7) - 187 Other income 15 - 3 (1) 17 Interest expense 62 1 5 (1) 67 Income before income taxes 125 21 (9) - 137 Income taxes 50 8 (12) - 46 Net income 75 13 3 - 91 Total assets 2,379 128 133 - 2,640 Expenditures for long- lived assets 113 - 27 - 140 The intersegment revenues from Utility Operation to Energy Marketing are not eliminated because they are included in the regulatory cost mechanism for IPC. 13. 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 (millions of dollars) Income taxes $ 210 $ 41 $ 214 $ 40 Conservation 28 4 32 4 Employee benefits 3 - 4 - PCA deferral and amortization 290 - 120 - Oregon deferral and amortization 15 - - - Derivatives 48 - - - Other 6 1 9 1 Deferred investment tax credits - 68 - 66 Total $ 600 $ 114 $ 379 $ 111 At December 31, 2001, IPC had $4 million of regulatory assets, primarily SFAS 112 benefits and reorganization 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 the Company were to discontinue application of SFAS 71 for some or all of IPC's operations, then these items may represent stranded investments. If the Company is not allowed recovery of these investments, it would be required to write off the applicable portion of regulatory assets and the financial effects could be significant. 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 beensignificantly greater than forecast due to purchased power volumes and prices being greaterthan originally forecasted and the implementation of the voluntary load reductionprograms 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 regulatoryassets of $290 million as of December 31, 2001. The May 2000 rate adjustment increasedIdaho 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 the Company'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. 14. DERIVATIVE FINANCIAL INSTRUMENTS: Energy Trading Contracts The commodity transactions entered into by IE are classified as energy trading contracts, or derivatives. Under SFAS 133 and EITF 98-10, these contracts are recorded on the balance sheet at fair market value. This accounting treatment is also referred to as mark-to-market accounting. Mark-to-market accounting treatment can create a disconnect between recorded earnings and realized cash flow. Marking a contract to market consists of reevaluating the market value of the entire term of the contract at each reporting period and reflecting the resulting gain or loss in earnings for the period. This change in value represents the difference between the contract price and the current market value of the contract. The change in market value of the contract could result in large gains or losses recorded in earnings at each subsequent reporting period unless there are offsetting changes in value of hedge contracts. The gain or loss generated from the change in market value of the energy trading contracts is a non-cash event. If these contracts are held to maturity, the cash flow from the contracts, and their hedges, are realized over the life of the contract. When determining the fair value of our marketing and trading contracts, we use actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities. To determine fair value of contracts with terms that are not consistent with actively quoted prices we use, when available, prices provided by other external sources. When prices from external sources are not available, we determine prices by using internal pricing models that incorporate available current and historical pricing information. Finally, we adjust the fair market value of our contracts for the impact of market depth and liquidity, potential model error, and expected credit losses at the counterparty level. The following table details the gross margin for the energy marketing operations (in millions of dollars): 2001 2000 1999 Gross Margin: Realized or otherwise settled $ 150 $ 181 $ 28 Unrealized 93 (35) 4 Total $ 243 $ 146 $ 32 Risk Management: When buying and selling energy, the high volatility of energy prices can have significant negative impact on profitability if not appropriately managed. Also, counterparty creditworthiness is key to ensuring that transactions entered into can withstand potentially dramatic market fluctuations. To manage the risks inherent in the energy commodity industry while implementing the Company's business strategy, Risk Management Committee (RMC), comprised of Company officers, oversees the Company's risk management program as defined in the risk management policy. The program is intended to manage the impact to earnings caused by the volatility of energy prices by mitigating commodity price risk, credit risk, and other risks related to the energy commodity business. To manage the risks inherent in its portfolio, the Company has established risk limits. Market and credit risk is measured and reported daily to the members of the RMC. Other tools used to manage credit risk are the holding of collateral in the form of cash or letters of credit and the use of margining agreements with counterparties when credit risk exceeds certain pre-determined thresholds. Because of the volatile nature of energy market prices, margining agreements can require the posting of large amounts of cash between counterparties to hold as collateral against the value of the energy contracts. This practice mitigates credit risk but increases the need for cash or other liquid securities to ensure the ability to meet all margin requirements when the markets are most volatile. Derivative Assets and Liabilities The Company 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 the Company's contracts that meet the derivative definition are the energy trading contracts that were already recorded at fair value under EITF 98-10 as discussed above. 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 Derivatives Implementation Group (DIG) of the FASB initially interpreted that book outs did not qualify for the normal purchase and sales exception. The Company has recorded the fair market value of the booked out system electricity contracts within the financial statements as "Derivative liabilities." Such assets and liabilities are as follows: January 1, 2001 December 31, 2001 (millions of dollars) Assets $ 109 $ - Liabilities (207) (48) Net $ (98) $ (48) The electricity contracts identified above are subject to IPC 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 and expects that some contracts previously classified as derivatives will be exempt when C-15 becomes effective for IPC 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, the Company'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 Shareholders of IDACORP, Inc. Boise, Idaho We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, shareholders' equity and cash flows 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 satement 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 IDACORP, Inc. 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 millions of dollars except for per share amounts). In the opinion of the Company, all adjustments necessary for a fair statement of such amounts for such periods have been included. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full year. Accordingly, earnings information for any three-month period should not be considered as a basis for estimating operating results for a full fiscal year. Amounts are based upon quarterly statements and the sum of the quarters may not equal the annual amount reported. Quarter Ended March 31 June 30 September 30 December 31 2001 Revenues $1,133 $1,578 $2,115 $ 821 Income from operations 65 73 66 38 Income taxes 17 22 17 8 Net income 35 36 34 20 Earnings per share of common stock 0.93 0.96 0.91 0.55 2000 Revenues $ 352 $ 552 $1,039 $1,053 Income from operations 62 61 79 46 Income taxes 24 16 22 9 Net income 42 32 41 24 Earnings per share of common stock 1.12 0.86 1.11 0.63 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 SCHEDULES AND REPORTS ON FORM 8-K (a) Please refer to Item 8, "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules. (b) Reports on SEC Form 8-K. The following Report on Form 8-K was filed for the three months ended December 31, 2001. Items Reported Date of Report Item 5 - Other Events December 4, 2001 (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) 33-56071 3(d) Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998. *3(b) 333-64737 3.1 Articles of Incorporation of IDACORP, Inc. *3(b)(i) 333-64737 3.2 Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998. *3(b)(ii) 333-00139 3(b) Articles of Amendment to Articles of Incorporation of IDACORP, Inc. creating A Series Preferred Stock, without par value, as filed with the Secretary of State of Idaho on September 17, 1998. *3(c) 1-14465 3(c) Amended Bylaws of IDACORP, Inc. as Form 10-Q of July 8, 1999. for 6/30/99 *4(a) 1-14465 4 Rights Agreement, dated as of Form 8-K September 10, 1998, between IDACORP, dated Inc. and Wells Fargo Bank as September 15, successor to The Bank of New York, 1998 as Rights Agent. *4(b) 1-14465 4.1 Indenture for Senior Debt Securities Form 8-K dated as of February 1, 2001, dated February between IDACORP, Inc. and Bankers 28, 2001 Trust Company, as Trustee. *4(c) 1-14465 4.2 First Supplemental Indenture dated Form 8-K as of February 1, 2001, to Indenture dated February for Senior Debt Securities dated as 28, 2001 of February 1, 2001 between IDACORP, Inc. and Bankers Trust Company, as Trustee. *10(a) 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(b) 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(c) 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(d) 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(e) 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(f) 1-3198 10(y) Executive Employment Agreement dated Form 10-K November 20, 1996 between IPC and for 1997 Richard R. Riazzi. *10(g) 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) 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(i) 1-14465 10(h)(ix) IDACORP, Inc. 2000 Long-Term Form 10-K Incentive and Compensation Plan. for 1999 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 IDACORP, Inc. 23 Independent Auditors' Consent. IDACORP, Inc. 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 Charged Balance At Charged (Credited) Balance Beginning to to Other Deductions At End Of Classification Of Period Income Accounts (1) Period (Millions of dollars) 2001: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $ 23 $ 28 $ - $ 8 $ 43 Other Reserves: Rate refunds $ - $ - $ - $ - $ - Injuries and damages reserve $ 2 $ - $ - $ - $ 2 Miscellaneous operating reserves $ 5 $ - $ - $ 1 $ 4 2000: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $ 1 $ 23 $ - $ 1 $ 23 Other Reserves: Rate refunds $ 9 $ 3 $ - $ 12 $ - Injuries and damages reserve $ 2 $ - $ - $ - $ 2 Miscellaneous operating reserves $ 9 $ - $ - $ 4 $ 5 1999: Reserves Deducted From Applicable Assets: Reserve for uncollectible accounts $ 1 $ 2 $ - $ 2 $ 1 Other Reserves: Rate refunds $ 5 $ 11 $ - $ 7 $ 9 Injuries and damages reserve $ 2 $ - $ - $ - $ 2 Miscellaneous operating reserves $ 7 $ 3 $ - $ 2 $ 8 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. IDACORP, Inc. (Registrant) March 22, 2002 By: /s/Jan B.Packwood Jan B. Packwood President and Chief Executive 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 President and Chief " Jan B. Packwood Executive Officer and Director 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 IDACORP, Inc. 23 Independent Auditors' Consent.