IDAHO POWER CO - 10-K Annual Report

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 (MD&A) - 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 - IDACORP, Inc. and Idaho Power Company

ITEM 1. BUSINESS

OVERVIEW:

IDACORP, Inc. (IDACORP) is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power Company (IPC). IDACORP is exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company.

IPC is an electric utility engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operating subsidiaries include:

IDACORP Financial Services, Inc. (IFS) - holder of affordable housing and other real estate investments;

IdaTech - - developer of integrated fuel cell systems;

IDACOMM - - provider of telecommunications services and commercial and residential Internet services; and

Ida-West Energy (Ida-West) - operator of independent power projects.

IDACORP continues to focus on a strategy called "Electricity Plus," a back-to-basics strategy that emphasizes IPC as IDACORP's core business. IPC continues to experience strong growth in its service area, and this corporate strategy recognizes that IPC must make substantial investments in infrastructure to ensure adequate supply and reliable service. The "Plus" recognizes that through modest investments in IdaTech and IDACOMM, IDACORP can preserve the potential for additional growth in shareowner value. IFS, with its affordable housing and historic rehabilitation portfolio, remains a key component of the revised corporate strategy.

At December 31, 2004, IDACORP had 1,940 full-time employees. Of these employees, 1,757 were employed by IPC.

IDACORP's two reportable business segments are IPC and IFS. IPC and IFS contributed $66 million and $13 million, respectively, to consolidated net income in 2004. Financial information relating to IDACORP's reportable segments is presented in Note 12 to IDACORP's Consolidated Financial Statements and below in "Utility Operations" and "IFS."

Due to its wind down in 2003-2004, IE did not have any significant business activity in 2004. As a result, the energy marketing operations of IE are no longer a reportable business segment. See Note 15 to IDACORP's Consolidated Financial Statements for further discussion of the wind down.

IDACORP and IPC make available free of charge their Annual Report on Form 10-K, Quarterly Reports on Forms 10-Q, Current Reports on Forms 8-K and all amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the Securities and Exchange Commission, through their websites at www.idacorpinc.com and www.idahopower.com.

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 24,000 square mile area in southern Idaho and eastern Oregon, with an estimated population of 895,000. The measurement of IPC's service area increased by approximately 4,000 square miles over 2003 due to the conversion from a manual mapping system to global information system technology. IPC holds franchises in 71 cities in Idaho and nine cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 24 counties in Idaho and three counties in Oregon. As of December 31, 2004, IPC supplied electric energy to approximately 440,000 general business customers.

IPC owns and operates 17 hydroelectric power plants and one natural gas-fired plant and shares ownership in three coal-fired generating plants. A second gas-fired plant, Bennett Mountain Power Plant, is currently under construction and due on-line in 2005. 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 hydroelectric generation, IPC's generation operations can be significantly affected by the weather. The availability of hydroelectric power depends on snow pack in the mountains upstream of IPC's hydroelectric facilities, precipitation and other weather and stream flow management considerations. When hydroelectric generation decreases below load requirements and/or customer demand increases beyond hydroelectric capacity, IPC increases its use of more expensive thermal generation and purchased power.

The primary influences on electricity sales are weather, customer growth and economic conditions. 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, forest product production, 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) and the Oregon Public Utility Commission (OPUC). IPC is also under the regulatory jurisdiction of the IPUC, the OPUC and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. IPC is subject to the provisions of the Federal Power Act as a "public utility" as therein defined. IPC's retail rates are established under the jurisdiction of the state regulatory commissions and its wholesale and transmission rates are regulated by the FERC (see "Rates" below). Pursuant to the requirements of Section 210 of the Public Utilities Regulatory Policy Act of 1978 (PURPA), the state regulatory commissions have each issued orders and rules regulating IPC's purchase of power from cogeneration and small power production (CSPP) facilities.

IPC is subject to the provisions of the Federal Power Act as a "licensee" as therein defined. As a licensee under the Federal Power Act, IPC and its licensed hydroelectric projects are subject to the provisions of Part I of the Federal Power Act. All licenses are subject to conditions set forth in the Federal Power Act and related FERC regulations. These conditions and regulations include provisions relating to condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment, severance damages and other matters.

The State of Oregon has a Hydroelectric Act providing for licensing of hydroelectric projects in that state. IPC's Brownlee, Oxbow and Hells Canyon facilities are on the Snake River where it forms the boundary between Idaho and Oregon and occupy land located in both states. With respect to project property located in Oregon, these facilities are subject to the Oregon Hydroelectric Act. IPC has obtained Oregon licenses for these facilities and these licenses are not in conflict with the Federal Power Act or IPC's FERC licenses (see Part II, Item 7 - "MD&A - REGULATORY ISSUES - Relicensing of Hydroelectric Projects").

Rates
The rates IPC charges to its general business customers are determined by the IPUC and the OPUC. Approximately 96 percent of IPC's general business revenue comes from customers in Idaho. IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the true-up of the true-up for the prior years' unrecovered portion, is then included in the calculation of the next year's PCA.

For further discussion see Part II, Item 7 - "MD&A - REGULATORY ISSUES - General Rate Case," "MD&A REGULATORY ISSUES - Deferred Power Supply Costs" and Note 13 to IDACORP's Consolidated Financial Statements.

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 all-time system peak demand was 2,963 megawatts (MW), set on July 12, 2002. Peak summer demand in 2004 was 2,843 MW, set on June 24 and peak winter demand for the year was 2,196 MW on January 5. IPC expects total system energy requirements to grow 2.5 percent annually over the next three years.

The following table presents IPC's system generation for the last three years:

		MWh			Percent of total generation
		2004	2003	2002	2004	2003	2002
		(thousands of MWhs)
Hydroelectric		6,041	6,149	6,069	45%	47%	45%
Thermal		7,303	6,914	7,286	55%	53%	55%
	Total system generation	13,344	13,063	13,355	100%	100%	100%

The amount of electricity IPC is able to generate from its hydroelectric plants depends on a number of factors, primarily snow pack in the mountains upstream of its hydroelectric facilities, reservoir storage and stream flow conditions. 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 generation and purchased power.

Continued below normal stream flow conditions in 2004 yielded a system generation mix of 45 percent hydroelectric and 55 percent thermal. Under normal stream flow conditions, IPC's system generation mix is approximately 55 percent hydroelectric and 45 percent thermal.

Below average stream flow conditions are continuing for a sixth consecutive year in 2005. The forecast released on March 8, 2005 by the Northwest River Forecast Center indicates Brownlee inflow for April through July 2005 is expected to total 1.74 million acre-feet, or 28 percent of average. Snow pack accumulation was 60 percent of average on March 8, 2005. Storage in selected federal reservoirs upstream of Brownlee at the end of December 2004 was 60 percent of average. October 1, 2004 storage in these reservoirs, which is considered carryover storage into water year 2005, was only 41 percent of average. The flows in the Snake River at several measurement locations are at or near record lows.

IPC's generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum load-carrying capability and reliability. IPC's transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration, Avista Corporation, PacifiCorp, NorthWestern Energy and Sierra Pacific Power Company. Such interconnections, coupled with transmission line capacity made available under agreements with some of the above entities, permit the interchange, purchase and sale of power among all major electric systems in the west. IPC is a member of the Western Electricity Coordinating Council, the Western Systems Power Pool, the Northwest Power Pool and the Northwest Regional Transmission Association. These groups have been formed to more efficiently coordinate transmission reliability and planning throughout the western grid. See "Competition - Wholesale" below.

Integrated Resource Plan: IPC filed its 2004 Integrated Resource Plan (IRP) with the IPUC and the OPUC in August 2004. The 2004 IRP reviews IPC's load and resource situation for the next ten years, analyzes potential supply-side and demand-side options and identifies near-term and long-term actions. The two primary goals of the 2004 IRP are to (1) identify sufficient resources to reliably serve the growing demand for energy service within IPC's service area throughout the 10-year planning period and (2) ensure that the portfolio of resources selected balances cost, risk and environmental concerns. In addition, there are two secondary goals: (1) to give equal and balanced treatment to both supply-side resources and demand-side measures and (2) to involve the public in the planning process in a meaningful way.

See further discussion in Part II - Item 7 - "MD&A - REGULATORY ISSUES - Integrated Resource Plan."

CSPP Purchases: As mandated by the enactment of PURPA and the adoption of avoided cost standards by the IPUC and the OPUC, IPC has entered into contracts for the purchase of energy from a number of private developers. Under these contracts, IPC is required to purchase all of the output from the facilities located inside the IPC service territory. For projects located outside the IPC service territory, IPC is required to purchase the output that IPC has the ability to receive at the facility's requested point of delivery on the IPC system. The costs associated with these Idaho jurisdictional contracts are fully recovered through the PCA. For IPUC jurisdictional projects, projects up to ten MW are eligible for IPUC Published Avoided Costs for up to a 20-year contract term. The Published Avoided Cost is a price established by the IPUC and the OPUC to estimate IPC's cost of developing additional generation resources. For OPUC jurisdictional projects, projects up to one MW are eligible for OPUC Published Avoided Costs for up to a five-year contract term (automatically renewable at the end of five years). The costs associated with these Oregon jurisdictional contracts are recovered through general rate case filings. The Oregon provisions are currently being reviewed in an OPUC proceeding, as discussed in Part II, Item 7 - "MD&A - REGULATORY ISSUES - Public Utilities Regulatory Policy Act of 1978 - Oregon." If a PURPA project does not qualify for Published Avoided Costs, then IPC is required to negotiate the terms, prices and conditions with the developer of that project. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the IPC system and must be consistent with other similar energy alternatives.

As of December 31, 2004, IPC had signed agreements to purchase energy from 72 CSPP facilities with contracts ranging from one to 30 years. Of these facilities, 68 were on-line at the end of 2004; the other four facilities under contract are due to come on-line in 2005 and 2006. During 2004, IPC purchased 677,868 megawatt hours (MWh) from these projects at a cost of $40 million, resulting in a blended price of 5.9 cents per kilowatt hour.

Wholesale Energy Market Activities: Guided by a Risk Management Policy and frequently updated operating plans, IPC participates in the wholesale energy market by buying power to meet load demands and selling power that is in excess of load demands. IPC's market activities are influenced by its generating resources and how they are dispatched. Hydroelectric generation facilities enable IPC to optimize the water that is available by choosing when to run generation units and when to store water in reservoirs. These decisions may result in increased volumes of market purchases and market sales. Even in below normal water years, there are opportunities to vary water usage to maximize generation unit efficiency, capture marketplace economic benefits and meet load demand. Compliance factors, such as allowable river stage elevation changes and flood control requirements, and wholesale energy market prices influence these dispatch decisions.

IPC has three firm wholesale power sales contracts and one wholesale contract for load following services. The three power sales contracts range between three MW and fifteen MW. The three MW contract expires in 2005 and will not be renewed. When the two other contracts expire in 2006, IPC will either renew, negotiate an extension or use this power to meet its own system requirements. The load following contract with NorthWestern Energy provides the ability to increase or decrease IPC generation by 30 MW to react to NorthWestern's system load changes. So long as IPC retains its Hells Canyon Complex operating flexibility, the load following contract is anticipated to be renewed into the foreseeable future.

IPC has one firm wholesale purchased power contract. This contract is with PPL Montana, LLC for 83 MW per hour to address increased demand during June, July and August. The term of this contract began in June 2004 and runs through August 2009.

Transmission Services: IPC has a long history of providing wholesale transmission service and provides 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. IPC holds rights-of-way from Midpoint substation in south-central Idaho through eastern Nevada to the Crystal switchyard north of Las Vegas, Nevada, known as the Southwest Intertie Project. IPC obtained the rights-of-way to construct a transmission line along this corridor, but no longer plans to build the line. IPC is currently in discussions regarding the sale of these rights-of-way.

In December 1999, the FERC issued Order No. 2000 encouraging companies with transmission assets to form Regional Transmission Organizations. See "Competition - Wholesale" below.

Fuel
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-third interest in 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 for the term of the sales agreement. IPC also has a coal supply contract providing for annual deliveries of coal through 2009 from the Black Butte Coal Company's Black Butte and Leucite Hills mines located near the Jim Bridger plant. 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, the coal car unloading point and unit coal train allow the plant to take advantage of potentially lower-cost coal from outside mines for tonnage requirements above established contract minimums.

In an effort to lower costs and access better quality coal, the Jim Bridger Mine is converting from a surface operation to a primarily underground operation. Underground mine development and limited coal production began in 2004, and full operation is expected by 2007. A number of factors were considered in this decision including the increasing cost of the surface mine operation as well as the additional capital required to develop the underground mine. This conversion is expected to result in a reduction of the cost of mining coal over the life of the Jim Bridger Mine.

Sierra Pacific Power Company, as operator of the North Valmy Steam Electric Generating Plant, has an agreement with Arch Coal Sales Company, Inc. to supply coal to the plant from 2002 through 2006. IPC is obligated to purchase one-half of the coal, ranging from approximately 515,000 tons to 762,500 tons annually. Sierra Pacific Power Company also has a coal supply contract with Black Butte Coal Company's Black Butte Mine for deliveries in 2005. See also Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Utility Operations - Fuel Expense."

The Boardman plant receives coal from the Powder River Basin through annual contracts. Portland General Electric, as operator of the Boardman Plant, has an agreement with Triton Coal Company to supply all of Boardman's 2005 coal requirements.

IPC's Danskin and Bennett Mountain (due on-line in 2005) combustion turbines receive gas through the Williams Northwest Pipeline. All gas is purchased as needs are identified for summer peaks or to meet system requirements. The gas is transported under a long-term capacity contract with the Williams Northwest Pipeline and an arrangement with IGI Resources, Inc. The Williams Northwest Pipeline contract, which extends through February 28, 2007, with annual extensions at IPC's sole discretion, is for 24,523 million British thermal units per day from the Sumas, Washington metering point to the Elmore, Idaho metering point.

Water Rights
Except as discussed below, IPC has acquired 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 generating 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 a 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 the relationship established by the agreement would not be considered by the FERC as being inconsistent with the terms of IPC's project licenses or imprudent for the purposes of determining rates under Section 205 of the Federal Power Act. The FERC entered an order implementing the legislation on March 25, 1988.

In addition to providing for the protection of IPC's hydroelectric 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. The court signed a commencement order initiating the Snake River Basin Adjudication 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 several 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.

Please also see Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Idaho Water Management Issues" and "MD&A - REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

Environmental Regulation
Environmental regulation at the federal, state, regional and local levels continues to impact 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 regulations.

Based upon present environmental laws and regulations, IPC estimates its 2005 capital expenditures for environmental matters, excluding Allowance for Funds Used During Construction (AFDC), will total $18 million. Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $12 million, and investments in environmental equipment and facilities at the thermal plants account for $6 million. From 2006 through 2007, environmental-related capital expenditures, excluding AFDC, are estimated to be $40 million. Anticipated expenses related to IPC's hydroelectric facilities account for $30 million, and thermal plant expenses are expected to total $10 million.

IPC anticipates $16 million in annual operating costs for environmental facilities during 2005. Hydroelectric facility expenses account for $11 million of this total, and $5 million is related to thermal plant operating expenses. From 2006 through 2007, total environmental related operating costs are estimated to be $33 million. Expenses related to the hydroelectric facilities are expected to be $23 million, and thermal plant expenses are expected to be $10 million during this period.

Clean Air: IPC has analyzed the Clean Air Act legislation and its effects upon IPC and its customers. IPC's coal-fired plants meet federal and state emission rate standards for sulfur dioxide (SO₂) and nitrogen oxides (NO_x). The Jim Bridger plant is in the process of installing newer technology low-NO_x burners that will reduce NO_x emissions further than currently required. Mercury emission is an active coal-fired plant environmental issue with no regulation currently in force. None of IPC's plants have continuous mercury emission monitoring or control equipment installed. IPC is actively observing developments on this issue, such as proposed legislation and control equipment technology advances.

The Environmental Protection Agency issued SO₂allowances, as defined in the Clean Air Act Amendments, based on coal consumption during established baseline years. IPC has more than a sufficient amount of SO₂ allowances to provide compliance for all three coal-fired facilities, its Danskin natural gas-fired facility and its Bennett Mountain gas-fired facility (due on-line in 2005). Through 2005, IPC has 108,771 allowances in excess of the amount needed for Clean Air Act compliance. IPC has been granted annual allotments of allowances ranging from 15,524 to 28,622 through 2034. Allowances necessary for IPC's compliance requirements are up to 14,500 annually. Excess allowances owned by IPC may be held for future use, as they do not expire. There is an active marketplace for buying and selling allowances, so allowances determined to be excess can be sold to other companies. Accordingly, IPC does not foresee any adverse effects upon its operations with regard to SO₂ emissions at this time.

In January of 2005, the Chairman of the Senate Environment and Public Works Committee reintroduced the Clear Skies Act. This bill would further restrict SO₂and NO_x emissions, and add mercury emission restrictions. It may also include language addressing greenhouse gases. The bill, if passed, would require additional emission controls and expenses at the thermal facilities, although impacts on future plant operations, operating costs and generating capacity are not known at this time.

The Danskin gas turbine plant in Idaho is operating in compliance with a "permit to construct" issued by the Idaho Department of Environmental Quality. IPC has applied for a Title V Operating Permit from the Idaho Department of Environmental Quality, which is expected during 2005. The plant meets SO₂ regulations and the units are fitted with dry-low-NO_x burners and a continuous emissions monitoring system. This equipment should ensure that the facility operates within the permitted federal and state NO_x and carbon monoxide limits.

In July 1997, the Environmental Protection Agency announced the National Ambient Air Quality Standards for Ozone and Particulate Matter and in July 1999, the Environmental Protection Agency 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. In November 2000, the Environmental Protection Agency appealed to the U.S. Supreme Court to reconsider that decision. The Supreme Court has ruled in favor of the Environmental Protection Agency. The Environmental Protection Agency has not yet implemented tighter regulations on particulate matter, regional haze or ozone. Although the impacts of these regulations on IPC's thermal operations are not known at this time, the future costs of compliance with these regulations could be substantial and will be dependent on if and how the regulations are ultimately implemented.

Global Climate Change: The United States is currently not a party to the Kyoto Protocol to the United Nations Framework Convention on Climate Change (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas emissions at certain levels during the 2008 through 2012 time period. Although it has not ratified the Protocol, the United States may adopt a national, mandatory greenhouse gas program at some point in the future. At this time, IPC is unable to predict the potential impacts of any future mandatory governmental greenhouse gas legislative or regulatory requirements.

Greenhouse gas emissions result from the combustion of fossil fuels to generate electricity, with carbon dioxide representing the largest quantity of greenhouse gases emitted, from IPC's coal and gas generation units. Under normal water conditions, the majority of IPC's generation is comprised of hydroelectric assets that have negligible greenhouse gas emissions compared to fossil-based generation.

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 agreed, in March 1976, 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 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 its 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 its Milner, Shoshone Falls, Twin Falls, Upper Salmon, Lower Salmon, Bliss and CJ Strike 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, 2004, the investment in these facilities was $11 million and the annual cost of operation pursuant to FERC License 1971 was $3 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 governmental agencies to resolve issues related to these species. See Part II, Item 7 - "MD&A - REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

Hazardous/Toxic Wastes and Substances: Under the Toxic Substances Control Act, the Environmental Protection Agency has adopted regulations governing the use, storage, inspection and disposal of electrical equipment that contains polychlorinated biphenyls (PCBs). The regulations permit the continued use and servicing of certain equipment (including transformers and capacitors) that contain PCBs. IPC continues to meet all federal requirements of the Toxic Substances Control Act for the continued use of equipment containing PCBs. IPC continues to eliminate PCBs as part of its long-term strategy. This program will reduce costs associated with the long-term monitoring of PCB-containing equipment, responding to spills and reporting to the Environmental Protection Agency. In 2004, IPC spent approximately $1 million identifying and eliminating PCBs.

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. The committee has not recommended any restructuring legislation and is not expected to in the foreseeable future. The committee's focus has since shifted from restructuring to general energy issues. In 1999, the Oregon Legislature passed legislation restructuring the electric utility industry, but exempted IPC's service territory.

Wholesale: The 1992 National Energy Policy 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.

For more information, see Part II, Item 7 - "MD&A - REGULATORY ISSUES - Regional Transmission Organizations."

Utility Operating Statistics
The following table presents IPC's revenues and energy use by customer type for the last three years, which is further discussed in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Utility Operations:"

			Years Ended December 31,
			2004		2003		2002
Revenues (thousands of dollars)
	Residential		$	274,313	$	275,920	$	305,827
	Commercial			164,053		173,820		196,454
	Industrial			111,797		128,620		176,648
	Irrigation			85,672		92,609		93,106
		Total general business		635,835		670,969		772,035
	Off-system sales			121,148		71,573		55,031
	Other			62,526		37,840		39,981
		Total	$	819,509	$	780,382	$	867,047

Energy use (thousands of MWh)
	Residential			4,580		4,427		4,387
	Commercial			3,561		3,511		3,460
	Industrial			3,335		3,206		3,226
	Irrigation			1,763		1,836		1,821
		Total general business		13,239		12,980		12,894
	Off-system sales			2,885		1,830		2,069
		Total		16,124		14,810		14,963

IFS:

IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS generated tax credits of $22 million, $20 million and $21 million in 2004, 2003 and 2002, respectively. IFS's portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS made $8 million in new investments during 2004.

IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk. Over 90 percent of IFS's investments have been made through syndicated transactions. At December 31, 2004, the gross amount of IFS's portfolio exceeded $165 million in tax credit investments. These investments cover 49 states, Puerto Rico and the U.S. Virgin Islands. The underlying investments include over 700 individual properties, of which all but three are administered through syndicated funds.

IDA-WEST:

Ida-West operates and has a 50 percent interest in nine hydroelectric plants with a total generating capacity of 45 MW. In 2003, Ida-West discontinued its project development activities. See further discussion in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Ida-West." IPC purchased all of the power generated by Ida-West's four Idaho hydroelectric projects, at a cost of $7 million per year, in 2004, 2003 and 2002.

IDATECH:

IdaTech was originally founded in 1996 as Northwest Power Systems, LLC to develop and bring fuel cell technology to market. In April 1999, IDACORP purchased a majority interest in IdaTech.

IdaTech is a global fuel cell provider focused on the commercialization of fuel processor technology and integrated proton exchange membrane (PEM) fuel cell systems. IdaTech's products under development include:

Complete systems such as its five kilowatt electrical emergency back up power fuel cell unit ElectraGen™ that is targeted to replace valve regulated lead acid batteries in applications such as cellular telecommunications towers and portable power systems.

On-board reforming capability, which provides auxiliary power to high-end consumer applications such as marine and recreational vehicles and premium power for special military operations.

Components such as multi-fuel fuel processors, fuel cell stack technology and automated fuel cell systems, which target longer-term commercial applications in vehicular auxiliary power units and Combined Heat and Power units. For these longer-term market opportunities, IdaTech has joined with Volkswagen, RWE Fuel Cells and Bosch Buderus in product development. IdaTech's fuel processors are capable of operating on alcohols and liquid and gaseous hydrocarbon fuels including natural gas, liquefied petroleum gas, diesel and kerosene.

IdaTech has integrated its multi-fuel fuel processors with a number of PEM fuel cell stacks into one to ten kilowatt fuel cell systems for stationary and portable electric power generation.

Currently, these systems are being field-tested and evaluated with European utilities, the Propane Education and Research Council, the U.S. Army Communications Electronics Command and a number of other customers in North America, Europe and Asia.

In July 2004, IdaTech and Buderus Heiztechnik GmbH of the Bosch group, a heating equipment manufacturer located in Germany, joined RWE Fuel Cells in its program with IdaTech for the development of a five kilowatt combined heat and power fuel cell system for multi-dwelling and light commercial use. Under this partnership, IdaTech will develop and manufacture the fuel cell systems. RWE Fuel Cells and Bosch Buderus will integrate the fuel cells with heating systems to create a complete heat and power solution. RWE Fuel Cells and Bosch Buderus will test the fuel cell systems in the laboratory and in the field. Several IdaTech fuel cell systems are in service and being tested by RWE Fuel Cells. The first field trials with fully integrated fuel cell and heating systems are planned for installation in 2005.

In September 2004, IdaTech was selected by automobile manufacturer Volkswagen to design and manufacture an integrated fuel processor system operating on diesel fuel to be used in an automotive application. The agreement is part of a vehicle demonstration project at Volkswagen.

On November 19, 2004, IdaTech was awarded a $1.4 million development program from the U.S. Department of Energy to conduct a three-year program of fuel cell system research targeting off-road vehicle applications. Under this award, IdaTech will identify and recommend fuel cell designs to overcome environmental conditions faced by off-road vehicles such as turf and grounds maintenance vehicles and construction and farm equipment.

IDACOMM:
In August 2000, IDACORP formed IDACOMM, Inc. and acquired Velocitus, Inc., a Boise, Idaho-based Internet service provider founded in 1992. IDACOMM provides a wide range of integrated communication services to business and residential customers in 22 markets across eight western states, Virginia and New York. In 2004, IDACORP transferred its ownership of Velocitus to IDACOMM. Velocitus was merged into IDACOMM in January 2005.

IDACOMM's fiber optic networks provide high-speed connectivity in its local market, Boise, Idaho, as well as recently added market networks in Las Vegas, Nevada and Reno, Nevada, acquired in June 2004 from Sierra Pacific Communications, Inc. IDACOMM's Internet services unit enables high-speed voice, Internet and data communications, including video conferencing, voice-over Internet protocol, off-site training, gigabit Ethernet service, virtual private networks, firewalls and web hosting. The Internet unit serves residential, consumer and small to medium size business clients with high-speed connectivity and security solutions, including fixed wireless technology, with 20,000 customers at December 31, 2004.

During 2004, IDACOMM formed a new unit for the testing and commercial deployment of broadband-over-powerline technology, staging a multi-location equipment trial in Boise, Idaho during the year. Broadband-over-powerline provides broadband Internet access to power outlets in homes and businesses by transporting data over medium-voltage and low-voltage power lines directly to the end-user's computer.

IDACOMM's customers include companies in industries such as manufacturing, health care, food processing and retail as well as government entities, schools and universities and national telecommunication carriers.

RESEARCH AND DEVELOPMENT:

IdaTech:
In 2004, IdaTech spent approximately $5 million for research and development of fuel cell technology. IdaTech's research and development program is focused on the adaptation of its fuel processor technology to operate on all commercially important fuels, as well as the development of fully integrated fuel cell systems. Highest priority is given to natural gas, liquefied petroleum gas, kerosene and diesel fuels.

IdaTech continues to pursue patent protection of its technology in North America, Europe, South America, Asia and Australia. The patents issued to IdaTech address the design and operation of fuel reformers; the design and materials of construction used in IdaTech's two stage hydrogen purification devices based on the HyPurium™ membranes used to filter out impurities in the product hydrogen; fuel cell system automated control and operation; integrated heat recovery from fuel cell systems; and automated control of integrated pressure-swing absorption for efficient and reliable operation. During 2004, IdaTech received its first three Japanese patents (related to the composition of the IdaTech HyPurium™ membranes as well as the design and materials used to construct membrane modules), and IdaTech received its first European patent related to the HyPurium™ membrane composition and module design and construction. Currently, 35 U.S. patents lasting 20 years have been issued or allowed to IdaTech. These patents expire from 2016 to 2025. IdaTech also has approximately 150 pending domestic and foreign patent applications addressing various aspects of (1) fuel processor system design, operation, materials and integration; (2) membrane purification, materials and design; and (3) fuel cell system operation, thermal recovery, design, remote control and diagnostics. These patents will help IdaTech bring its technology to commercialization. The patents also provide the potential for licensing of IdaTech's technology in the future.

IPC:
In 2004, IPC spent over $4 million to promote energy efficiency and summer peak reduction. Approximately $1 million of those expenditures went to fund the Northwest Energy Efficiency Alliance, which strives to transform the regional marketplace through demonstration of innovative technologies, collaboration with firms that market energy-saving products and services and training and information services. IPC's other energy efficiency programs target efficiencies in the areas of new residential construction, manufactured homes, industrial and irrigation efficiency and duct sealing. Low-income weatherization assistance and Oregon residential weatherization efforts were also funded in 2004. In addition to IPC's on going programs, funding was also allocated to the research and development of new energy efficiency and summer peak reduction options in the irrigation and residential sectors. Most of the funding for these programs and program development comes from the Idaho tariff rider for demand-side management programs and from the Conservation and Renewable Discount Program of the Bonneville Power Administration.

ITEM 2. PROPERTIES

IPC's system includes 13 hydroelectric projects made up of 17 generating plants located in southern Idaho and eastern Oregon, one natural gas-fired plant located in southern Idaho and interests in three coal-fired steam electric generating plants. A second gas-fired plant, Bennett Mountain Power Plant, is currently under construction and due on-line later in 2005. The system also includes approximately 4,671 miles of high voltage transmission lines, 23 step-up transmission substations located at power plants, 19 transmission substations, seven transmission switching stations and 212 energized distribution substations (excluding mobile substations and dispatch centers).

IPC holds FERC licenses for all 13 of its hydroelectric projects. These projects and the other generating stations and their capacities are listed below:

					Estimated
					Non-
					Coincident
					Maximum		Nameplate
					Operating		Capacity		License
Project					Capacity (kW)		(kW)		Expiration
Hydroelectric:
	Properties subject to federal licenses:
			Lower Salmon			70,000		60,000		2034
			Bliss			80,000		75,000		2034
			Upper Salmon			39,000		34,500		2034
			Shoshone Falls			12,500		12,500		2034
			CJ Strike			89,000		82,800		2034
			Upper Malad			9,000		8,270		2004	(a)
			Lower Malad			15,000		13,500		2004	(a)
			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
	Other Hydroelectric					10,400		11,300
			Total Hydroelectric					1,706,715
Steam and Other Generating Plants:
			Jim Bridger (coal-fired) (b)			706,667		770,501
			Valmy (coal-fired) (b)			260,650		283,500
			Boardman (coal-fired) (b)			55,200		56,050
			Danskin (gas-fired)			100,000		90,000
			Salmon (diesel-internal combustion)			5,500		5,000
			Bennett Mountain (gas-fired)(c)			163,980		172,800
				Total Steam and other				1,377,851
				Total Generation				3,084,566

(a) Licensed on an annual basis while application for new multi-year license is pending.
(b) IPC's ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman. Amounts
		shown represent IPC's share only.
(c) Due on-line later in 2005.

See discussion of relicensing in Part II, Item 7 - "MD&A - REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

At December 31, 2004, the composite average ages of the principal parts of IPC's system, based on dollar investment, were production plant, 24 years; transmission system and substations, 22 years; and distribution lines and substations, 18 years. IPC considers its properties to be well-maintained and in good operating condition.

IPC owns in fee all of its principal plants and other important units of real property, except for portions of certain projects licensed under the Federal Power Act and reservoirs and other easements. IPC's property is also subject to the lien of its Mortgage and Deed of Trust and the provisions of its project licenses. In addition, IPC's property is subject to minor defects common to properties of such size and character that do not materially impair the value to, or the use by, IPC of such properties.

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. These plants are located in Idaho and California.

See Note 1 to IDACORP's Consolidated Financial Statements for a discussion of the property of IDACORP's consolidated Variable Interest Entities.

ITEM 3. LEGAL PROCEEDINGS

Reference is made to Note 8 of IDACORP's Consolidated Financial Statements.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

EXECUTIVE OFFICERS OF THE REGISTRANT

The names, ages and positions of all of the executive officers of IDACORP, Inc. are listed below along with their business experience during the past five years. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was elected.

JAN B. PACKWOOD President and Chief Executive Officer, appointed May 30, 1999. Mr. Packwood also serves as Chief Executive Officer of Idaho Power Company, appointed March 1, 2002. Mr. Packwood was President and Chief Executive Officer of Idaho Power Company from May 30, 1999 to March 1, 2002. Age 61

J. LAMONT KEEN Executive Vice President, appointed March 1, 2002. Mr. Keen was Senior Vice President - Administration and Chief Financial Officer from May 5, 1999 to March 1, 2002. Mr. Keen also serves as President and Chief Operating Officer of Idaho Power Company, appointed March 1, 2002. Mr. Keen was Senior Vice President - Administration and Chief Financial Officer of Idaho Power Company from May 5, 1999 to March 1, 2002. Age 52

DARREL T. ANDERSON Senior Vice President - Administrative Services and Chief Financial Officer, appointed July 1, 2004. Mr. Anderson was Vice President, Chief Financial Officer and Treasurer from March 1, 2002 to July 1, 2004 and Vice President - Finance and Treasurer from May 5, 1999 to March 1, 2002. Mr. Anderson serves in the same position at Idaho Power Company. Age 46

THOMAS R. SALDIN Senior Vice President, General Counsel and Secretary, appointed October 1, 2004. Mr. Saldin was Executive Vice President and General Counsel of Albertson's Inc., a supermarket chain, from January 29, 1999 to his retirement on August 31, 2001. Mr. Saldin serves in the same position at Idaho Power Company. Age 58

DENNIS C. GRIBBLE Vice President and Treasurer, appointed July 15, 2004. Mr. Gribble was Finance Controller of Idaho Power Company from January 1, 1997 to July 15, 2004. Mr. Gribble serves in the same position at Idaho Power Company. Age 52

A. BRYAN KEARNEY Vice President and Chief Information Officer, appointed March 15, 2001. Mr. Kearney has been the Vice President and Chief Information Officer of Idaho Power Company since November 18, 1999. Age 42

LUCI K. MCDONALD Vice President - Human Resources, appointed December 6, 2004. Ms. McDonald was Corporate Staff Director of Human Resources of Boise Cascade Corporation, a forest products company, from September 16, 1999 to November 19, 2004. Ms. McDonald serves in the same position at Idaho Power Company. Age 47

GREGORY W. PANTER Vice President - Public Affairs, appointed April 1, 2001. Mr. Panter was self-employed with Greg Panter Consulting, a lobbying/government affairs business, from July 1, 1999 to April 1, 2001. Mr. Panter serves in the same position at Idaho Power Company. Age 56

LORI D. SMITH Vice President - Finance and Chief Risk Officer, appointed July 15, 2004. Ms. Smith was Director of Strategic Analysis of Idaho Power Company from January 1, 2000 to July 15, 2004. Ms. Smith serves in the same position at Idaho Power Company. Age 44

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

IDACORP, Inc.'s (IDACORP) common stock (without par value) is traded on the New York Stock Exchange and the Pacific Exchange. On December 31, 2004, there were 18,037 holders of record and the stock price was $30.57 per share.

The outstanding shares of Idaho Power Company's (IPC) common stock ($2.50 par value) are held by IDACORP and are not traded. IDACORP became the holding company of IPC on October 1, 1998.

The amount and timing of dividends payable on IDACORP's common stock are within the sole discretion of IDACORP's Board of Directors. The Board of Directors reviews the dividend rate quarterly to determine its appropriateness in light of IDACORP's current and long-term financial position and results of operations, capital requirements, rating agency requirements, legislative and regulatory developments affecting the electric utility industry in general and IPC in particular, competitive conditions and any other factors the Board of Directors deems relevant. In September 2003, IDACORP announced a decrease in the annual dividend from $1.86 to $1.20 per share. See further discussion of the dividend reduction in Part II, Item 7 - "MD&A - LIQUIDITY AND CAPITAL RESOURCES - Dividend Reduction." The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily IPC.

IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. IPC paid dividends toIDACORP of $46 million, $65 million and $70 million in 2004, 2003 and 2002, respectively. On September 20, 2004, IPC redeemed all of its outstanding preferred stock for $54 million using proceeds from the issuance of first mortgage bonds.

The following table shows the reported high and low sales price of IDACORP's common stock and dividends paid for 2004 and 2003 as reported in the consolidated transaction reporting system.

		2004 Quarters
Common Stock, without par value:		1^st	2^nd	3^rd	4^th
	High	$32.05	$30.66	$29.95	$32.95
	Low	29.32	25.30	26.05	29.05
	Dividends paid per share -cents	30.0	30.0	30.0	30.0

		2003 Quarters
Common Stock, without par value:		1^st	2^nd	3^rd	4^th
	High	$26.35	$27.92	$27.25	$30.19
	Low	20.60	22.65	23.15	25.42
	Dividends paid per share -cents	46.5	46.5	46.5	30.0

ITEM 6. SELECTED FINANCIAL DATA

IDACORP, Inc.
SUMMARY OF OPERATIONS
(thousands of dollars except per share amounts)
		2004		2003		2002		2001		2000
Operating Revenues		$	844,491	$	823,002	$	928,800	$	1,275,312	$	1,049,785
Operating income			93,251		84,062		75,640		242,289		247,310
Net income			72,983		46,578		61,672		125,214		139,883
Earnings per share			1.90		1.22		1.63		3.35		3.72
Dividends declared per share			1.20		1.70		1.86		1.86		1.86

Financial Condition:
Total assets		$	3,234,172	$	3,106,108	$	3,387,168	$	3,769,992	$	4,159,177
Long-term debt			1,058,152		1,013,757		988,268		879,048		903,888

Financial Statistics:
Times interest charges earned:
	Before tax		1.83		1.37		1.16		3.52		4.33
	After tax		2.25		1.68		1.93		2.66		3.21
Market-to-book ratio			128%		132%		108%		175%		225%
Payout ratio			63%		139%		114%		56%		50%
Return on year-end common equity			7.2%		5.4%		7.1%		14.4%		17.0%
Book value per share		$	23.88	$	22.61	$	22.98	$	23.21	$	21.85

See Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS" for a discussion of the factors that affect comparability.

The above data should be read in conjunction with IDACORP's Consolidated Financial Statements including the
Notes to the Consolidated Financial Statements.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollar amounts are in thousands unless otherwise indicated. Megawatt hours (MWh) are in thousands.)

INTRODUCTION:

In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, IPC) are discussed. IDACORP is a holding company formed in 1998 whose principal operating subsidiary is IPC. IDACORP is exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company.

IPC is an electric utility with a service territory covering approximately 24,000 square miles, primarily in southern Idaho and eastern Oregon. The measurement of IPC's service area increased by approximately 4,000 square miles over 2003 due to the conversion from a manual mapping system to global information system technology. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operating subsidiaries include:

IDACORP Financial Services, Inc. (IFS) - holder of affordable housing and other real estate investments;

IdaTech - developer of integrated fuel cell systems;

IDACOMM - provider of telecommunications services and commercial and residential Internet services; and

Ida-West Energy (Ida-West) - operator of independent power projects.

IDACORP Energy (IE), a marketer of electricity and natural gas, wound down its operations during 2003. Also in 2003, Ida-West discontinued its project development operations and is managing its independent power projects with a reduced workforce. See further discussions in "RESULTS OF OPERATIONS - Energy Marketing" and "RESULTS OF OPERATIONS - Ida-West" later in the MD&A.

In 2004, IDACORP transferred its ownership of RMC Holdings, Inc. and its subsidiary Velocitus to IDACOMM. In January 2005, RMC Holdings, Inc. and Velocitus were merged into IDACOMM.

While reading the MD&A, please refer to the Consolidated Financial Statements of IDACORP and IPC, which present the financial position at December 31, 2004 and 2003, and the results of operations and cash flows for each company for the years ended December 31, 2004, 2003 and 2002.

FORWARD-LOOKING INFORMATION:

In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), IDACORP and IPC are hereby filing cautionary statements identifying important factors that could cause 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 IDACORP or IPC in this Annual Report on Form 10-K, any Quarterly Report on Form 10-Q, any current Report on Form 8-K, 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 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:

Changes in governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, relicensing of hydroelectric projects, recovery of purchased power expenses, recovery of other capital investments, present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs) and other refund proceedings;

Litigation and regulatory proceedings, including those resulting from the energy situation in the western United States, and settlements that influence business and profitability;

Changes in and compliance with environmental, endangered species and safety laws and policies;

Weather variations affecting hydroelectric generating conditions and customer energy usage;

Over-appropriation of surface and groundwater in the Snake River Basin resulting in reduced generation at hydroelectric facilities;

Construction of power generating facilities including inability to obtain required governmental permits and approvals, and risks related to contracting, construction and start-up;

Operation of power generating facilities including breakdown or failure of equipment, performance below expected levels, competition, fuel supply, including availability, transportation and prices, and transmission;

Impacts from the potential formation of a regional transmission organization (RTO);

Population growth rates and demographic patterns;

Market demand and prices for energy, including structural market changes;

Changes in operating expenses and capital expenditures and fluctuations in sources and uses of cash;

Results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by factors such as credit ratings and general economic conditions;

Homeland security, natural disasters, acts of war or terrorism;

Technological developments that could affect the operations and prospects of IDACORP's subsidiaries or their competitors;

Increasing health care costs and the resulting effect on health insurance premiums paid for employees;

Performance of the stock market and the changing interest rate environment, which affect the amount of required contributions to pension plans, as well as the reported costs of providing pension and other postretirement benefits;

Increasing costs of insurance, changes in coverage terms and the ability to obtain insurance;

Changes in tax rates or policies, interest rates or rates of inflation;

Adoption of or changes in critical accounting policies or estimates; and

New accounting or Securities and Exchange Commission requirements, or new interpretation or application of existing requirements.

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.

RISK FACTORS:

The following are factors that could have a significant impact on the operations and financial results of IDACORP, Inc. and Idaho Power Company and could cause actual results or outcomes to differ materially from those discussed in any forward-looking statements:

Reduced hydroelectric generation can reduce revenues and increase costs. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company's heavy reliance on hydroelectric generation, the weather can significantly affect its operations. Idaho Power Company is experiencing its sixth consecutive year of below normal water conditions in 2005. When hydroelectric generation is reduced, Idaho Power Company must increase its use of more expensive thermal generating resources and purchased power. Through its power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately 90 percent of the increase in its Idaho jurisdictional net power supply costs, which are fuel and purchased power less off-system sales, above the level included in its base rates. The power cost adjustment recovery includes both a forecast and deferrals that are subject to the regulatory process. The non-Idaho net power supply costs are subject to periodic recovery from its Oregon and Federal Energy Regulatory Commission jurisdictional customers.

Continuing declines in stream flows and over-appropriation of water in Idaho will reduce hydroelectric generation and revenues and increase costs. The combination of declining Snake River base flows, over-appropriation of water and continuing drought conditions have led to disputes among certain surface water and ground water irrigators, and the State of Idaho. Recharging the Eastern Snake River Aquifer, which contributes to Snake River flows, by diverting surface water to porous locations and permitting it to sink into the Aquifer is one proposed solution to the dispute. Idaho Power Company believes aquifer recharge would further reduce Snake River base flows available for hydroelectric generation, reduce Idaho Power Company revenues and increase costs.

Changes in temperature can reduce power sales and revenues. Warmer than normal winters or cooler than normal summers will reduce retail revenues from power sales.

The Idaho Public Utilities Commission's grant of less rate relief than requested will reduce Idaho Power Company's projected earnings and cash flows. Because Idaho Power Company did not receive the full amount of rate relief requested, its projected earnings and cash flows have been reduced and IDACORP, Inc.'s and Idaho Power Company's credit ratings have been downgraded. If the Idaho Public Utilities Commission were to grant less rate relief than Idaho Power Company requests in the future, it could have a negative effect on earnings and cash flow and result in future downgrades of IDACORP, Inc.'s and Idaho Power Company's credit ratings.

A downgrade in IDACORP, Inc.'s and Idaho Power Company's credit ratings could negatively affect the companies' ability to access capital. On November 29, 2004, Standard & Poor's Ratings Services, on December 3, 2004, Moody's Investors Service, and on January 24, 2005, Fitch, Inc. each downgraded IDACORP, Inc.'s and Idaho Power Company's credit ratings. These downgrades and any future downgrades of IDACORP, Inc.'s or Idaho Power Company's credit ratings could limit the companies' ability to access the capital markets, including the commercial paper markets. In addition, IDACORP, Inc. and Idaho Power Company would likely be required to pay a higher interest rate on existing variable rate debt and in future financings.

Conditions that may be imposed in connection with hydroelectric license renewals may require large capital expenditures and reduce earnings and cash flows. Idaho Power Company is currently involved in renewing federal licenses for several of its hydroelectric projects. Conditions with respect to environmental, operating and other matters that the Federal Energy Regulatory Commission may impose in connection with the renewal of Idaho Power Company's licenses could have a negative effect on Idaho Power Company's operations, require large capital expenditures and reduce earnings and cash flows.

The cost of complying with environmental regulations can harm cash flows and earnings. IDACORP, Inc. and Idaho Power Company are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, natural resources and health and safety. Compliance with these environmental statutes, rules and regulations involves significant capital, operating and other costs, and those costs could be even more significant in the future as a result of changes in legislation and enforcement policies. For instance, considerable attention has been focused on carbon dioxide emissions from coal-fired generating plants and their potential role in contributing to global warming and mercury emissions from coal-fired plants. The adoption of new laws and regulations to implement carbon dioxide, mercury or other emission controls could adversely affect operations and increase the cost of operating coal-fired generating plants.

Terrorist threats and activities could result in reduced revenues and increased costs. IDACORP, Inc. and Idaho Power Company are subject to direct and indirect effects of terrorist threats and activities. Potential targets include generation and transmission facilities. The effects of terrorist threats and activities could prevent Idaho Power Company from purchasing, generating or transmitting power and result in reduced revenues and increased costs.

IDACORP, Inc., IDACORP Energy and Idaho Power Company are subject to costs and other effects of legal and regulatory proceedings, settlements, investigations and claims, including those that have arisen out of the western energy situation. IDACORP, Inc., IDACORP Energy and Idaho Power Company are involved in a number of proceedings including a complaint filed against sellers of power in California, based on California's unfair competition law, a cross-action wholesale electric antitrust case against various sellers and generators of power in California and the California refund proceeding at the Federal Energy Regulatory Commission. Other cases that are the direct or indirect result of the western energy situation include a refund proceeding affecting sellers of wholesale power in the spot market in the Pacific Northwest, in which the Federal Energy Regulatory Commission directed that no refunds be paid, but which is now pending on appeal before the United States Court of Appeals for the Ninth Circuit; efforts by certain parties to reform or terminate contracts for the purchase of power from IDACORP Energy or claiming violations of state and federal antitrust acts and dysfunctional energy markets as the result of market manipulation; show cause proceedings at the Federal Energy Regulatory Commission, which have been settled but are the subject of motions for rehearing or have been appealed and the reversal by the United States Court of Appeals for the Ninth Circuit of Federal Energy Regulatory Commission rulings that market-based sellers' transactional reports satisfy the Federal Energy Regulatory Commission's filed-rate doctrine requirements as a means of expanding refunds from all sellers of wholesale power, which rulings remain pending before the United States Court of Appeals for the Ninth Circuit on rehearing. To the extent the companies are required to make payments, earnings will be negatively affected. It is possible that additional proceedings related to the western energy situation may be filed in the future against IDACORP, Inc., IDACORP Energy or Idaho Power Company.

Pending shareholder litigation could be costly, time consuming and, if adversely decided, result in substantial liabilities. Two securities shareholder lawsuits consolidated by order dated August 31, 2004 have been filed against IDACORP, Inc. and certain of its officers and directors. Securities litigation can be costly, time-consuming and disruptive to normal business operations. Certain costs below a self-insured retention are not covered by insurance policies. While IDACORP, Inc. cannot predict the outcome of these matters and these matters will take time to resolve, damages arising from these lawsuits if resolved against IDACORP, Inc. or in connection with any settlement, absent insurance coverage or damages in excess of insurance coverage, could have a material adverse effect on the financial position, results of operations or cash flows of IDACORP, Inc.

Litigation relating to stray voltage, if adversely decided, could result in liabilities, reducing earnings, and encourage the commencement of additional lawsuits. In three instances, dairy farmers have brought actions against Idaho Power Company claiming loss of milk production and other damages to livestock due to stray voltage from Idaho Power Company's electrical system. In the first proceeding, the jury ruled in Idaho Power Company's favor. In the second proceeding, a jury verdict was entered in favor of the plaintiffs. A third is in the discovery stage. Adverse court rulings in such proceedings could increase the number of future claims. The costs of defending these lawsuits could be significant, and certain costs, such as those below a deductible amount, are not covered by insurance policies.

Increased capital expenditures can significantly affect liquidity. Increases in both the number of customers and the demand for energy require expansion and reinforcement of transmission, distribution and generating systems. Because Idaho Power Company did not receive the full amount of rate relief requested, Idaho Power Company will have to rely more on external financing for its planned utility construction expenditures in the 2005 through 2007 period; these large planned expenditures may weaken the consolidated financial profile of Idaho Power Company and IDACORP, Inc. Additionally, a significant portion of Idaho Power Company's facilities were constructed many years ago. Aging equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures. Failure of equipment or facilities used in Idaho Power Company's systems could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures.

If IDACORP, Inc. and Idaho Power Company are unable to complete future assessments as to the adequacy of their internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, or if the companies complete the future assessments and identify and report material weaknesses, investors could lose confidence in the reliability of the companies' financial statements, which could decrease the value of IDACORP, Inc.'s common stock. As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the Securities and Exchange Commission has adopted rules requiring public companies to include a report of management on the company's internal control over financial reporting in their annual reports on Form 10-K. This report is required to contain management's assessment of the effectiveness of the company's internal control over financial reporting as of the end of the most recent fiscal year. In addition, the independent registered public accounting firm auditing a public company's financial statements must also attest to and report on management's assessment of the effectiveness of the company's internal control over financial reporting. Effective internal controls are necessary for the companies to provide reliable financial reports and to prevent and detect fraud. If the companies should fail to have an effectively designed and operating system of internal control over financial reporting, this could result in decreased confidence in the reliability of the companies' financial statements, which could cause the market price of IDACORP, Inc.'s common stock to decline.

BUSINESS STRATEGY, OVERVIEW OF 2004 AND OUTLOOK FOR 2005:

This section presents an overview of what management believes are the most critical issues that IDACORP and IPC are facing and the significant items that affected IDACORP's and IPC's 2004 operating results. These items will be discussed in more detail within various sections of the MD&A.

Business Strategy
IDACORP continues to focus on a strategy called "Electricity Plus," a back-to-basics strategy that emphasizes IPC as IDACORP's core business. IPC continues to experience strong customer growth in its service area, and this corporate strategy recognizes that IPC must make substantial investments in infrastructure to ensure adequate supply and reliable service. The "Plus" recognizes that through modest investments in IdaTech and IDACOMM, IDACORP can preserve the potential for additional growth in shareowner value. IFS, with its affordable housing and historic rehabilitation portfolio, remains a key component of the revised corporate strategy.

The Electricity Plus strategy includes seeking timely rate relief in both the Idaho and Oregon jurisdictions. IPC plans to file in Idaho and Oregon for either asset-specific or general rate relief regularly in upcoming years. The first of these filings was on March 2, 2005 for the Bennett Mountain Power Plant. IPC also plans to file an Idaho general rate case in the fall of 2005.

Water Conditions and Weather
As IPC's service territory enters the sixth consecutive year of below normal water conditions, IPC expects to rely more on higher-cost thermal generation and wholesale power purchases. Historically, hydroelectric generation has provided approximately 55 percent of IPC's total system generation. In 2004, IPC produced 45 percent of its power at its hydroelectric facilities. IPC has already incurred higher purchased power expenses in January 2005, compared to 2004, and expects power supply costs to remain high as long as below normal water conditions persist. Generation at IPC's hydroelectric facilities is currently expected to be 5.5 million MWh in 2005 compared to normal generation of 9.2 million MWh. Also, temperatures through February 2005, as measured by heating degree days in Boise, Idaho, were approximately seven percent warmer than normal and eleven percent warmer than 2004. If winter temperatures remain at or above last year's levels, IDACORP's and IPC's earnings could be negatively impacted by reduced electric usage.

The continuing below normal water conditions have exacerbated a developing water shortage in Idaho. The state has been observing declining Snake River base flows since the early 1960s. This water shortage has led to conflicts between ground water and surface water irrigators. At times during the year, flows into the Snake River are dependent upon spring flows fed by the Eastern Snake Plain Aquifer. One proposed solution is aquifer recharge - diverting surface water to porous surface locations and permitting it to sink into the aquifer. IPC believes aquifer recharge is inconsistent with state law and would adversely impact generation at its hydroelectric plants. Efforts have been underway since 2001 to find a solution to this conflict. A March 2004 interim agreement stayed all administrative and legal proceedings to give the parties one year to develop a solution. In January 2005, surface irrigators not a party to the interim agreement submitted a delivery call letter and filed a petition with the Idaho Department of Water Resources requesting delivery of their senior natural flow and storage rights and for the designation of the Eastern Snake Plain Aquifer as a ground water management area. IPC has sought intervention in these matters, which has been opposed by the Idaho Ground Water Appropriators, Inc.

Capital Requirements and Cash Flows
IDACORP expects internal cash generation after dividends will provide less than the full amount of total capital requirements for 2005 through 2007. The contribution for internal cash generation is dependent primarily upon IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions and IPC's ability to obtain rate relief to cover its operating costs. Current forecasts indicate total utility construction expenditures to be $672 million, excluding Allowance for Funds Used During Construction (AFDC), over the next three years. This amount reflects the need for additional resources in order for IPC to supply power to a growing number of customers while considering the maintenance of corporate credit ratings. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and with increased reliance on externally financed capital. In December 2004, IDACORP issued approximately 4 million shares of common stock and received net proceeds of $116 million. IDACORP used $30 million of these proceeds to reduce short-term borrowings and contributed $86 million to IPC. IPC used a portion of the proceeds to pay down short-term borrowings.

2004 Financial Results
IDACORP's basic and diluted earnings per share (EPS) for the year of $1.90 was a $0.68 per share increase over 2003's results of $1.22 per share. The increase is primarily due to improved results at IPC, a gain on the sale of an investment at IFS and the negative impacts of exiting energy trading at IE and asset impairments at Ida-West in 2003.

IPC's earnings of $1.71 per share for 2004 are a $0.27 per share increase over last year. This increase was driven by the settlement of the irrigation lost revenue case allowing IPC to recover approximately $12 million that was written-off in 2002 plus $2 million in related interest. The $12 million is included in other operating revenue and the interest is included in other income. IPC's other operating revenue also increased $7 million primarily as a result of Settlement No. 1 with the IPUC discussed later, regarding the calculation of IPC's income taxes. Additionally, the portion of net power supply costs absorbed by IPC and not recovered under the Idaho Power Cost Adjustment (PCA) and Oregon Excess Power Cost mechanisms decreased by $10 million. IPC's income tax expense decreased $15 million largely due to the reversal of a $16 million regulatory liability that was established in 2002 and reversed as part of Settlement No. 2 with the IPUC discussed later. These increases to net income were partially offset by a $35 million rise in other operations and maintenance expense mainly due to higher payroll expenses associated with an employee incentive program and a write-off of approximately $9 million of disallowed costs related to the Idaho general rate case.

IFS contributed $0.35 per share, principally from the generation of federal income tax credits and tax depreciation benefits. These results also include a $2 million gain on the sale of IFS's investment in the El Cortez Hotel in San Diego, California.

Ida-West's earnings of $0.08 per share are a $0.21 per share increase over last year's loss of $0.13 per share. During 2004, Ida-West recorded a gain on extinguishment of debt by purchasing $18 million of debt issued by Marysville Hydro Partners, a 50 percent owned, consolidated joint venture. Ida-West's gain, net of minority interest, was approximately $3.5 million. In 2003, Ida-West wrote down its remaining investment in the Garnet project and two joint ventures and recorded a reserve on a note receivable.

IE earned $0.06 per share for 2004 primarily from gains on settlements of legal disputes, which are included as offsets to energy marketing operating expenses. In 2003, IE posted a net loss of $0.25 per share due to losses on legal settlements and continued wind down costs, partially offset by a gain on the sale of its forward book of electricity trading contracts.

Regulatory Matters
Irrigation Lost Revenues: On December 29, 2004, the IPUC issued Order No. 29669 allowing IPC to recover $12 million in revenues and $2 million of interest resulting from IPC's Irrigation Load Reduction Program. The recovery will be included as part of IPC's annual PCA beginning June 1, 2005.

General Rate Case: IPC filed its Idaho general rate case with the IPUC on October 16, 2003. The IPUC approved an increase of $25 million in IPC's electric rates, an average of 5.2 percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004. The IPUC also approved a return on equity of 10.25 percent.

The IPUC disallowed several costs in the order, including $12 million annually related to the determination of IPC's income tax expense, $8 million of incentive payments capitalized in prior years and $1 million of capitalized pension expense. On June 15, 2004, IPC filed with the IPUC a petition for reconsideration of these and other items. On July 13, 2004, the IPUC granted this petition in part, agreeing to reconsider the issue relating to the determination of IPC's income tax expense and, in light of the IPUC Staff's computational errors, ordering rates increased by approximately $3 million on or before August 1, 2004. IPC recorded an impairment of assets in the second quarter of 2004 related to the disallowed incentive payments and the disallowed capitalized pension expenses.

The final result of IPC's Idaho general rate case was a $40 million increase to the base Idaho jurisdictional revenue requirement, comprised of $25 million in the initial order, $3 million related to computational errors and $12 million in the order approving Settlement No. 1 discussed below.

IPC filed an Oregon general rate case with the OPUC on September 21, 2004 requesting an increase of $4 million annually.

Settlement Agreements: On September 28, 2004, the IPUC issued separate orders approving two Settlement Agreements entered into on August 16, 2004 between IPC and the IPUC Staff. Settlement No. 1 relates to the calculation of IPC's taxes for purposes of test year income tax expense. As a result of Settlement No. 1, IPC will compute and record over the 12-month period June 1, 2004 through May 31, 2005 a regulatory asset of approximately $12 million. Approximately $7 million of this amount was recognized as other operating revenue as of December 31, 2004.

Settlement No. 2 resolved outstanding issues related to an unplanned outage at one of the two units of the North Valmy Steam Electric Generating Plant (Valmy) in the summer of 2003, a matter relating to the expense adjustment rate for growth component of the PCA and regulatory accounting issues related to a tax accounting method change in 2002. As a result of Settlement No. 2, IPC established a regulatory liability of $19 million with a charge to PCA expense. Also, IPC reversed a $16 million regulatory tax liability by reducing income tax expense.

Relicensing
For several years, IPC has been actively pursuing the relicensing of some of its hydroelectric projects. The following is a summary of the status of relicensing activity:

Middle Snake River Projects: On August 4, 2004, IPC received the FERC license orders for each of its five middle Snake River projects. IPC is now in the process of developing protection, mitigation and enhancement (PM&E) plans to ensure compliance with the various license articles. Two environmental organizations have filed petitions for rehearing of the orders issuing the licenses for the middle Snake River projects. The FERC has yet to issue orders on these petitions.

Malad Project: IPC filed a new license application for the Malad project in July 2002 and the license expired on August 1, 2004. The FERC has issued a Final Environmental Assessment under the National Environmental Policy Act of 1996 (NEPA) and IPC expects a new license to be issued in 2005.

Hells Canyon Complex: This represents IPC's most significant relicensing effort. IPC filed its license application in July 2003 and the current license will expire in July 2005. IPC's current application, including water quality measures as part of the state's process under section 401 of the Clean Water Act, identifies proposed PM&E measures totaling approximately $386 million. IPC's preliminary estimate of the cost of all the proposed PM&E measures submitted by other parties participating in the Hells Canyon relicensing process is approximately $2.5 billion over up to a 50-year period.

IPC is engaged in discussions with the FERC and relevant federal and state agencies on the effects, if any, of the relicensing of the Hells Canyon Complex on species listed as threatened or endangered under the Endangered Species Act (ESA). These discussions are generally referred to as the Hells Canyon ESA Consultation/Settlement Process. On January 7, 2005, IPC filed an agreement on interim operations with the FERC. The interim agreement is intended to address issues relating to operations of the Hells Canyon Complex and ESA-listed species in advance of the issuance of a new license while the parties continue discussions in an effort to negotiate a comprehensive relicensing settlement agreement.

Pursuant to the requirements of NEPA, the FERC is independently evaluating the environmental effects of relicensing the Hells Canyon Complex. IPC and a number of participants in the settlement discussions have requested that the FERC defer its NEPA schedule to enable the parties to pursue a comprehensive relicensing settlement in the Hells Canyon ESA Consultation/Settlement Process discussions. The FERC granted IPC's request for deferral.

The relicensing process permits intervenors to submit additional study requests to the FERC. The FERC received a total of 123 additional study requests and the FERC has issued to IPC a total of 14 Additional Information Requests. IPC and those participating in the relicensing process have objected to the FERC's decision and the FERC has made a number of rulings on the objections. Meanwhile, IPC is proceeding with the studies and analysis relevant to the 14 Additional Information Requests.

Legal Issues

IDACORP, IPC and IE have been named as defendants in a number of legal cases. Major developments include:

On September 17, 2004, the Idaho Supreme Court dismissed IPC's appeal of a verdict awarding Vierstra Dairy approximately $17 million. The dismissal was incident to a settlement of the matter among IPC, IPC's insurance carrier and the plaintiffs. The settlement, less a deductible, was covered by insurance and did not have a material effect on IPC;

On May 18, 2004, Herculano and Frances Alves brought an action against IPC seeking unspecified monetary damages alleging that IPC allowed electrical current to flow in the earth injuring their right to use and enjoy their property and adversely affecting their dairy herd;

On October 12, 2004, the Ninth Circuit Court of Appeals unanimously affirmed a District Court's dismissal of the California Attorney General's action against IPC and twelve other defendants claiming violations of the Federal Power Act;

Three similar cases in U.S. District Court arising out of the western energy situation alleging anti-trust violations and market manipulation against IDACORP, IPC and IE were dismissed. The action by the Port of Seattle against IDACORP and IPC was dismissed on May 28, 2004 and is on appeal to the Ninth Circuit Court of Appeals. The actions by the City of Tacoma and Wah Chang against IDACORP, IPC and IE were both dismissed on February 11, 2005;

On August 10, 2004, the Ninth Circuit Court of Appeals affirmed a U.S. District Court dismissal of a complaint filed by the Public Utility District No. 1 of Grays Harbor County, Washington against IDACORP and IE claiming an electric purchase contract was void and unenforceable and seeking restitution but permitted Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation;

Two shareholder lawsuits against IDACORP and certain of its directors and officers alleging materially false and misleading statements or omissions about IDACORP's financial outlook and seeking unspecified monetary damages were consolidated and the defendants filed a consolidated motion to dismiss on February 9, 2005, which is now pending;

Powerex Corp. filed suit against IDACORP and IE alleging breach of an oral and written contract and seeking unspecified general damages;

In the market manipulation proceeding, on January 23, 2004, the FERC approved the FERC Staff's motion to dismiss the "partnership" proceeding against IPC and no rehearing was sought. On March 3, 2004, the FERC approved IPC's settlement in the "gaming" proceeding and eight parties sought rehearing; and

On May 12, 2004, the FERC Office of Market Oversight and Investigations issued a letter advising IPC that it was terminating its investigation of IPC in its "bidding" investigation.

CRITICAL ACCOUNTING POLICIES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates, including those related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, restructuring costs and bad debt. These estimates are based on historical experience and on various other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. IDACORP and IPC, based on their ongoing reviews, will make adjustments when facts and circumstances dictate.

IDACORP and IPC believe the following critical accounting policies are important to the portrayal of their financial condition and results of operations and require management's most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.

Accounting for Rate Regulation
A regulated company must satisfy the following conditions in order to apply the accounting policies and practices of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation:" an independent regulator must set rates; the regulator must set the rates to cover specific costs of delivering service; and the service territory must lack competitive pressures to reduce rates below the rates set by the regulator. SFAS 71 requires companies that meet the above conditions to reflect the impact of regulatory decisions in their consolidated financial statements and requires that certain costs be deferred as regulatory assets until matching revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities and amortized to the income statement as rates to customers are reduced.

IPC follows SFAS 71, and its financial statements reflect the effects of the different rate making principles followed by the various jurisdictions regulating IPC. The primary effect of this policy is that IPC has recorded $439 million of regulatory assets and $276 million of regulatory liabilities at December 31, 2004. While IPC expects to fully recover these regulatory assets and return these regulatory liabilities, such recovery is subject to final review by the regulatory entities.

If IPC should determine in the future that it no longer meets the criteria for continued application of SFAS 71, it would be required to write off its regulatory assets and liabilities unless regulators specify some other means of recovery or refund. IPC intends to seek recovery of all of its prudent costs, including stranded costs, in the event of deregulation. However, due to the current lack of definitive legislation, IPC cannot predict whether recovery would be successful. If IPC has to write off a material amount of the regulatory assets, it will have a material adverse effect on IPC's results of operations and financial position.

Pension Expense
IPC maintains a qualified defined benefit pension plan covering most employees and an unfunded nonqualified deferred compensation plan for certain senior management employees and directors.

IDACORP's and IPC's recorded pension expense for these plans is dependent on a number of factors, including the provisions of the plans, changing employee demographics, actual returns on plan assets and several actuarial assumptions used in the valuations upon which pension expense is based. The key actuarial assumptions that affect expense are the long-term return on plan assets and the discount rate used in determining future benefit obligations. Management reviews these assumptions on an annual basis, taking into account changes in market conditions, trends and future expectations. Estimates of future stock market performance, changes in interest rates and other factors used to develop these assumptions are extremely uncertain, and actual results could vary significantly from the estimates.

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Based on recent market trends, the discount rate used to calculate the 2005 pension expense will be reduced to 5.75 percent from the 6.15 percent used in 2004.

Rate-of-return projections for plan assets are based on historical real returns (after inflation) for each asset class, based on a recognized index established for the asset class being measured (S&P 500 Index for large-cap core stocks, Russell 1000 Growth for large-cap growth stocks, etc.). Historical real returns are then adjusted to include an inflation premium based on the current inflation environment. Currently a three percent inflation assumption is used in the asset modeling process. The assumed rate of return on plan assets will be 8.5 percent in 2005, the same as in 2004.

Pension expense for these plans totaled $10 million, $12 million and $4 million for the three years ended December 31, 2004, 2003 and 2002, respectively, including amounts allocated to capitalized labor costs. For 2005, pension expense is expected to total approximately $10 million, which takes into account the reduction of the discount rate noted above and returns on plan assets in 2004 that exceeded actuarial estimates. No changes were made to the other key assumptions used in the actuarial calculation.

Had different actuarial assumptions been used, pension expense could have varied significantly. The following table reflects the sensitivities associated with changes in certain actuarial assumptions on historical and future pension expense:

	Discount rate				Rate of return
	2005		2004		2005		2004
	(millions of dollars)
Effect of 0.5% increase	$	(1.2)	$	(1.6)	$	(1.7)	$	(1.6)
Effect of 0.5% decrease		2.7		1.7		1.7		1.6

No cash contributions were made to the qualified plan in 2002 through 2004, and none are expected in 2005. Under the non-qualified plan, IPC makes payments directly to participants in the plan. Payments averaged approximately $3 million per year in 2002 through 2004, and a similar amount is anticipated in 2005.

Please refer to Note 10 of IDACORP's Consolidated Financial Statements, which contains additional information about pension expense, including results of the actuarial valuations, actuarial assumptions used to measure pension expense and information about plan assets.

Contingent Liabilities
There are a number of unresolved issues related to regulatory, legal and tax matters. Contingent liabilities are provided for in accordance with SFAS 5, "Accounting for Contingencies." According to SFAS 5, an estimated loss from a loss contingency shall be charged to income if (a) it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. Disclosure in the notes to the financial statements is required for loss contingencies not meeting both conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until realized.

The companies have made estimates of the ultimate resolution of all such matters, based on the facts and circumstances, opinions of legal counsel and other factors. If the recognition criteria of SFAS 5 have been met, liabilities have been recorded. Estimates of this nature are highly subjective, and the final outcome of these matters could vary significantly from the amounts that have been included in the current financial statements.

Asset Impairment
IDACORP has several assets that are tested for impairment in accordance with various accounting pronouncements. Those assets that were tested in 2004 include the following:

Goodwill: IDACORP has $14 million of goodwill related to its investments in IDACOMM and IdaTech. IDACORP conducts its impairment tests under the provisions of SFAS 142, "Goodwill and Other Intangible Assets." According to SFAS 142, goodwill is tested for impairment at least annually, and more frequently when events occur or circumstances change that more likely than not would reduce the fair value of a reporting unit below its carrying amount. SFAS 142 requires that if the fair value of a reporting unit is less than its carrying value including goodwill, the implied fair value of the reporting unit goodwill must be compared with its carrying value to determine the amount of the impairment.

IDACORP's recorded goodwill amounts were tested for impairment as required, and no impairment was noted. The fair value calculations used for these tests require IDACORP to make assumptions about items that are inherently uncertain. Assumptions related to future market demand, market prices and product costs could vary from actual results, and the impact of such variations could be material. Factors that could affect the assumptions include changes in economic conditions, success in developing marketable products and services and competitive conditions in the telecommunications and fuel cell industries.

Long-lived Assets: Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under SFAS 144, "Accounting for the Impairment or Disposal of Long-lived Assets." SFAS 144 requires that if the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements.

Southwest Intertie Project: IPC began developing the Southwest Intertie Project (SWIP) in 1988. IPC's investment consists predominantly of rights-of-way over public lands in Idaho and Nevada. The SWIP rights-of-way extend from Midpoint substation in south-central Idaho through eastern Nevada to the Crystal switchyard north of Las Vegas, Nevada. IPC does not currently anticipate constructing this transmission line itself and is in discussions regarding the sale of the rights-of-way. The Bureau of Land Management recently granted a five-year extension to begin construction of a proposed 500kV transmission line within the rights-of-way before December 2009. Based on these discussions and management expectations regarding the ultimate development of SWIP, no impairment has been identified. These expectations are based on assumptions that are inherently uncertain. Actual results could vary significantly from the assumptions used, and the impact of such variations could be material.

Investments:IFS has affordable housing and other investments with a net book value of $109 million at December 31, 2004, and Ida-West has investments in four joint ventures that own electric power generation facilities. Except for two investments now consolidated under the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) 46R, "Consolidation of Variable Interest Entities - an interpretation of ARB 51," these investments are accounted for under the equity method of accounting as described in Accounting Principles Board Opinion No. (APB) 18, "The Equity Method of Accounting for Investments in Common Stock." The standard for determining whether impairment must be recorded under APB 18 is whether the investment has experienced a loss in value that is considered an other-than-temporary decline in value.

Prior to the decision to discontinue Ida-West's project development activities, Ida-West had the intent and ability to hold the investments for a period sufficient to recover the recorded value. Based upon the change in management's intent, these investments were tested for impairment, and two of the investments were determined to be impaired, resulting in a write down of $2 million in 2003. The impairment amounts are based on the estimated fair value of the investments. Impairment tests on these investments were performed in 2004 and no impairment was noted.

These estimates required IDACORP to make assumptions about future stream flows, revenues, cash flows and other items that are inherently uncertain. Actual results could vary significantly from the assumptions used, and the impact of such variations could be material.

RESULTS OF OPERATIONS:

This section of the MD&A takes a closer look at the significant factors that affected IDACORP's and IPC's earnings over the last three years. In this analysis, the results of 2004 are compared to 2003 and the results of 2003 are compared to 2002. The analysis is organized by IDACORP's reportable segments, which are Utility Operations and IFS. The following table presents EPS for both reportable segments as well as for the holding company and its other subsidiaries combined:

EPS of common stock
		2004		2003		2002
Utility operations*		$	1.71	$	1.44	$	2.24
IFS*			0.35		0.27		0.23
Other*			(0.16)		(0.49)		(0.84)
Total EPS		$	1.90	$	1.22	$	1.63

*	The EPS of any one segment does not represent a direct legal interest in the assets and liabilities allocated to
	any one segment but rather represents a direct equity interest in IDACORP's assets and liabilities as a whole.

Return on year-end common equity			7.2%		5.4%		7.1%

Utility Operations
This section discusses IPC's utility operations, which are subject to regulation by, among others, the state public utility commissions of Idaho and Oregon and by the FERC.

Generation: IPC relies on its hydroelectric plants for a significant portion of its power supply. The availability of hydroelectric generation can significantly affect the amount of net power supply costs, which are fuel and purchased power less off-system sales, that IPC incurs. Most, but not all, of the net power supply costs are recovered through the rates charged to customers. Lower hydroelectric generation increases net power supply costs, thereby increasing the amount of these costs that IPC must absorb.

IPC's system is dual peaking, with the larger peak demand usually occurring in the summer. IPC's record system peak of 2,963 MW occurred on July 12, 2002. Peak summer demand in 2004 was 2,843 MW on June 24 and peak winter demand for the year was 2,196 MW on January 5. IPC was able to meet system load requirements and off-system sales requirements and had sufficient system reserves in place. IPC's 2004 Integrated Resource Plan (IRP) reports that customers' use of electricity continues to grow especially during the summer months. IPC projects that summer peaks could grow by an average of 2.5 percent per year over the ten-year IRP planning period.

In 2004, IPC experienced its fifth consecutive year of below normal hydroelectric generating conditions. The National Weather Service Northwest River Forecast Center reports April through July inflow to Brownlee Reservoir for 2004 totaled 3.19 million acre-feet (maf), which is 51 percent of the 30-year average. The total annual Brownlee inflow for 2004 was 8.99 maf, which the River Forecast Center reports is 59 percent of average.

Below average stream flow conditions are continuing for a sixth consecutive year in 2005. The River Forecast Center forecast released on March 8, 2005 indicates Brownlee inflow for April through July 2005 is expected to total 1.74 maf, or 28 percent of average. Snow pack accumulation was 60 percent of average on March 8, 2005. Storage in selected federal reservoirs upstream of Brownlee at the end of December 2004 was 60 percent of average. October 1, 2004 storage in these reservoirs, which is considered carryover storage into water year 2005, was only 41 percent of average. The flows in the Snake River at several measurement locations are at or near record lows.

The continuing below average hydrologic conditions will reduce IPC's hydroelectric generation, and require it to use wholesale purchases from the energy markets and higher-cost thermal generation when necessary to meet its energy needs in 2005. Generation from IPC's hydroelectric facilities is expected to be 5.5 million MWh in 2005, compared to 6.0 million MWh in 2004 and normal generation of 9.2 million MWh. The following table presents IPC's system generation:

		MWh			% of total generation
				Total			Total
				system			system
		Hydroelectric	Thermal	generation	Hydroelectric	Thermal	generation
2004		6,041	7,303	13,344	45%	55%	100%
2003		6,149	6,914	13,063	47%	53%	100%
2002		6,069	7,286	13,355	45%	55%	100%
Normal^(a)		9,172	7,365	16,537	55%	45%	100%

^(a)Normal hydroelectric generation represents the annual average based on median conditions, using 1928 - 2002 stream flows, adjusted to
	the 1992 level of depletion, and observed generation for 2003-2004. Normal thermal represents average generation for the past five years.

General Business Revenue: The following table presents IPC's general business revenues and MWh sales for the last three years:

		Revenue						MWh
		2004		2003		2002		2004	2003	2002
Residential		$	274,313	$	275,920	$	305,827	4,580	4,427	4,387
Commercial			164,053		173,820		196,454	3,561	3,511	3,460
Industrial			111,797		128,620		176,648	3,335	3,206	3,226
Irrigation			85,672		92,609		93,106	1,763	1,836	1,821
	Total	$	635,835	$	670,969	$	772,035	13,239	12,980	12,894

2004 vs. 2003:

Rates: Lower average rates, resulting from the PCA, decreased general business revenue $40 million. The decrease in PCA revenues was approximately $68 million. This was partially offset by a $28 million increase due to new base rates beginning on June 1, 2004. The general rate case and the PCA are discussed in more detail below in "REGULATORY ISSUES - - General Rate Case" and "REGULATORY ISSUES - Deferred Power Supply Costs - Idaho;"

Customers: An increase in general business customers improved revenue $19 million during 2004. IPC is experiencing strong customer growth in its service territory, adding nearly 14,000 general business customers in the last 12 months, a 3.2 percent increase. Similar growth is expected to continue in 2005 and beyond;

Contract Expiration: The expiration in March 2003 of a take-or-pay contract with FMC/Astaris caused a $9 million decrease in revenues for 2004. FMC/Astaris, formerly IPC's largest volume customer, closed its plants late in 2001 but was required under the contract to pay IPC for generation capacity regardless of delivery; and

Usage: Revenues decreased approximately $6 million during 2004 mainly due to cooler summer weather. Cooling degree-days for this year were 24 percent less than 2003, which had unusually hot summer temperatures. Cooling degree-days are a common measure used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for air conditioning.

2003 vs. 2002:

Rates: Decreased average rates, resulting from the PCA, reduced revenue $79 million;

Contract Expiration: Revenues decreased $28 million due to the expiration in March 2003 of the take-or-pay contract with FMC/Astaris;

Customers: A 2.7 percent increase in general business customers increased revenue $16 million; and

Usage: Milder fall and winter weather and other usage factors reduced revenues by approximately $10 million.

Off-system sales: Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy.

	2004		2003		2002

Revenue	$	121,148	$	71,573	$	55,031
MWh sold		2,885		1,830		2,069
Revenue per MWh	$	41.99	$	39.11	$	26.60

2004 vs. 2003: Revenues from off-system sales grew significantly over 2003 due mainly to increased volumes sold. The increased volumes sold are largely a result of power supply hedge activity in late spring based on temporarily improved hydroelectric generation. Although overall hydroelectric generating conditions were below normal, May 2004 precipitation was above normal and reservoir storage space was limited. Consequently, IPC generated more hydroelectric power than previously planned for May and June 2004. Earlier hedge purchase activity combined with increased hydroelectric generation resulted in surplus energy.

2003 vs. 2002: Revenues from off-system sales increased due principally to higher average prices in the wholesale electricity markets.

Other revenues:

2004 vs. 2003: Other revenues increased $25 million over 2003 due mainly to the following:

In December 2004, IPC recorded approximately $12 million related to the recovery of lost revenue resulting from IPC's Irrigation Load Reduction Program. The recovery will be included as part of IPC's annual PCA beginning on June 1, 2005. This matter is discussed further in "REGULATORY ISSUES - Deferred Power Supply Costs - Idaho;"

IPC recognized approximately $7 million of revenue due to the IPUC order approving Settlement No. 1, which relates to the calculation of IPC's taxes for purposes of test year income tax expense in the Idaho general rate case. As a result of this settlement, IPC is recording a regulatory asset of approximately $12 million from June 1, 2004 through May 31, 2005. IPC will begin collecting this amount beginning in June 2005 with an adjustment to rates; and

In July 2004, IPC recognized $4 million of revenue from an agreement with the Bonneville Power Administration for the release of 100,000 acre-feet of storage water from Brownlee Reservoir. This amount has been included in the PCA and will result in a benefit to IPC's Idaho customers in the next PCA year.

2003 vs. 2002: Other revenues did not change materially from 2002 to 2003.

Purchased power:

		2004		2003		2002
Purchased power:
	Purchases	$	195,642	$	147,850	$	91,312
	Load reduction costs	$	-	$	3,130	$	50,790

MWh purchased			4,274		3,383		2,918
Cost per MWh purchased		$	45.77	$	43.70	$	31.29

2004 vs. 2003: The 2004 increase in purchased power expense is mostly due to a 26 percent increase in volumes purchased. The increased volumes purchased are a result of power supply hedge activity based on expectations of reduced hydroelectric generation due to continued below normal water conditions. Load reduction costs decreased from $3 million to zero due to the expiration in March 2003 of the FMC/Astaris Voluntary Load Reduction Program, which is discussed further in "REGULATORY ISSUES - FMC/Astaris Settlement Agreement."

2003 vs. 2002: Volumes purchased increased due principally to two factors: unplanned outages at IPC's thermal plants and increased sales to general business customers. Load reduction costs decreased $48 million due to the expiration of the FMC/Astaris Voluntary Load Reduction Program in March 2003.

Fuel expense: The following table presents IPC's fuel expenses and generation at its thermal generating plants:

	2004		2003		2002
Fuel expense	$	103,261	$	99,898	$	102,871
Thermal MWh generated		7,303		6,914		7,286
Cost per MWh	$	14.14	$	14.45	$	14.12

2004 vs. 2003: Fuel expenses increased in 2004 mainly due to a six percent rise in generation. The increase in generation resulted from a return to normal operations at Valmy, which produced 23 percent more in 2004 than in 2003. See discussion of the outage at the Valmy plant below. This increase was partially offset by a 17 percent reduction in generation from the Boardman plant, which was offline for a longer period in 2004 in order to perform an upgrade to the turbine-generator.

2003 vs. 2002: Fuel expense decreased in 2003 due primarily to increased unplanned outages. The most significant outage involved one of the two units of the Valmy plant. As the unit was being returned to service after an unplanned outage, a breakdown occurred, unrelated to the completed maintenance, forcing the unit out of service from late June to early September in 2003. The unit was repaired and modernized controls and protection systems are in place. Additional maintenance was completed during the outage that minimized the 2004 planned maintenance outage period for the unit. IPC owns 50 percent of the Valmy plant and is not the plant operator.

Coal Supply: The Valmy plant has experienced problems with its coal supply, delivery and resulting coal inventory level. During 2004, delivery service from the coal mines to Valmy was unpredictable. In addition, there have been several mine production and quality issues that have reduced coal availability. These factors have negatively impacted the plant's coal inventory level and IPC and Sierra Pacific Power Company, Valmy's co-owner and operator, continue to address the problem. IPC expects these problems to continue during 2005.

The preferred Valmy coal inventory level is 45 days at full load; the current coal inventory level is 24 days at full load. To date, generation has not been negatively impacted by the coal inventory level. IPC and Sierra Pacific Power Company have an agreement in place to modify plant operations if inventory drops below 10 days at full load.

PCA: PCA expense represents the effect of IPC's PCA regulatory mechanism, which is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs - Idaho." In 2004, 2003 and 2002, actual net power supply costs, which are fuel and purchased power less off-system sales, exceeded those anticipated in the annual PCA forecast, resulting in the deferral of a portion of those costs to subsequent years when they are to be recovered in rates. As the revenues are being recovered, the deferred balances are amortized.

The following table presents the components of PCA expense:

		2004		2003		2002
Current year net power supply cost deferral		$	(29,306)	$	(44,320)	$	(4,178)
FMC/Astaris and irrigation program cost deferral			-		(2,245)		(39,854)
Amortization of prior year authorized balances			49,190		117,279		200,941
Write-offs of disallowed costs			-		48		13,580
Settlement agreement			19,300		-		-
	Total power cost adjustment	$	39,184	$	70,762	$	170,489

Other Operations and Maintenance Expenses:
2004 vs. 2003: Other operations and maintenance expenses increased $35 million due mainly to the following:

An increase in payroll expense of $13 million for an employee incentive program, which was partially triggered by the settlement relating to the irrigation load reduction program;

A write-off of $9 million related to disallowed items in the Idaho general rate case; and

Increases in transmission expense of $4 million primarily due to the increase in purchased power.

2003 vs. 2002: Other operations and maintenance expenses increased $14 million due principally to thefollowing:

Qualified pension plan expenses increased $5 million;

Maintenance of thermal plants rose $4 million due to increased unplanned outages, primarily at the Valmy plant; and

Transmission maintenance increased $3 million, predominantly from an increase in tree-trimming and pole maintenance costs of $1 million, and because of insurance proceeds of $1 million received in 2002 related to a 2001 outage.

IFS
IFS contributed $0.35, $0.27 and $0.23 per share for 2004, 2003 and 2002, respectively, principally from the generation of federal income tax credits and tax depreciation benefits. The 2004 results include a gain on the sale of its investment in the El Cortez Hotel in San Diego, California. In June 2000, IFS invested $4 million to assist in the renovation of the historic El Cortez into upscale apartment units. Upon exiting the investment on April 22, 2004, IFS recognized a gain on the sale of $5 million, income taxes of $3 million and a net gain of $2 million. The gain is included in other income on IDACORP's Consolidated Statements of Income.

IFS generates federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. IFS made $8 million in new investments during 2004 and generated tax credits of $22 million, $20 million and $21 million during 2004, 2003 and 2002, respectively. IFS is expected to continue generating tax benefits near current levels.

Energy Marketing
IE wound down its power marketing operations, closed its business locations and sold its forward book of electricity trading contracts to Sempra Energy Trading in 2003. As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with Sempra Energy Trading, guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The Indemnity Agreement has been accounted for in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" and did not have a material effect on IDACORP's financial statements.

For 2004, IE reported $2 million of operating income due to gains on the settlements of legal disputes.

IE reported an $18 million operating loss in 2003 compared to a $26 million operating loss in 2002. IE realized a $17 million gain from the sale of its forward book of electricity trading contracts in August 2003. This gain was offset by a loss on legal disputes of $12 million, legal expenses of $6 million, acceleration of depreciation expense of $6 million, restructuring expenses of $5 million and general and administrative costs of $6 million. See also Note 15 of IDACORP's Consolidated Financial Statements for information related to restructuring costs of IE.

On December 29, 2003, IE received a $45 million cash payment from Overton Power District No. 5 for final settlement. Overton had a $46.1 million long-term receivable with IE, and this payment resulted in a $1.1 million expense to IE in December 2003. In addition, IE recorded a write-down of $21.5 million related to this receivable in the second quarter of 2003. These write-downs are included in energy marketing operating expenses on IDACORP's Consolidated Statement of Income.

Ida-West
In 2003, Ida-West discontinued its project development operations. This decision resulted from the implementation of IDACORP's new corporate strategy. This strategy does not include the development or acquisition of merchant generation, which was Ida-West's focus. Currently, Ida-West continues to manage its independent power projects with a reduced workforce.

Impairment charges, as discussed below, negatively affected Ida-West's earnings in both 2003 and 2002.

Garnet impairment: In 2001, Garnet, a wholly owned subsidiary of Ida-West, entered into a purchased power agreement with IPC to provide energy to be produced by Garnet's proposed natural gas-fired plant. Due to changes in the electricity industry, financing of the project on acceptable terms under the purchased power agreement became impracticable. In 2002, Ida-West wrote down $8.6 million of its investment in equipment related to Garnet. At that time, the site remained viable for future generation development. In 2003, the original purchased power agreement was mutually terminated. Also in 2003, IPC issued a formal request for proposal (RFP) seeking bids for the construction of up to 200 megawatts (MW) of additional generation. The RFP specifically prohibited affiliates of IPC, including Ida-West, from bidding. While one bid proposed acquisition and use of the Garnet site, a different bid was selected. Based on the termination of the purchased power agreement, the results of the RFP process and the decision to discontinue project development operations, Ida-West determined that recovery of its remaining $3.6 million investment in the Garnet site development costs was uncertain and an impairment charge for the entire amount was recorded. Each of these impairments is presented on the Consolidated Statement of Income as other operating expenses.

Joint ventures: Based on management's new corporate strategy, Ida-West's investments in four joint ventures were evaluated for impairment in 2003. As a result, $2.4 million in impairment charges were recorded in the fourth quarter of 2003 to partially impair two of the joint ventures. This impairment is presented on the Consolidated Statement of Income as other expense. There was no impairment identified for 2004.

In addition, a $2.6 million bad debt reserve was established in 2003 on a note receivable from a partner in one of the joint ventures. This reserve is presented on the Consolidated Statement of Income as other operating expenses. No further reserve was necessary for 2004.

Income Taxes
Status of Audit Proceedings: In 2004, IDACORP settled all issues related to the Internal Revenue Service's examination of its federal income tax returns for the years 1998 through 2000. Applicable state tax return amendments were completed in 2004 and settled. The settlement resulted in a benefit of $2 million in 2004 and $9 million in 2003, as the deficiencies assessed were less than previously accrued.

In 2004, IPC settled federal income tax deficiencies for the years 1999 and 2000 related to its partnership investment in the Bridger Coal Company. IPC had previously accrued sufficient amounts to satisfy the 1999 and 2000 deficiencies. In 2002, IPC settled the years 1991 through 1998. The 2002 settlement resulted in deficiencies that were less than previously accrued, enabling IPC to decrease income tax expense by approximately $3 million.

During 2005, the Internal Revenue Service will begin its examination of IDACORP's 2001 through 2003 tax years. Management believes that an adequate provision for income taxes and related interest charges has been made for the open years 2001 and after. The accrued amounts are classified as a current liability in taxes accrued.

Management cannot predict with certainty which financial accounts or tax adjustments will be chosen by the IRS for examination. IDACORP intends to vigorously defend its tax positions. It is possible that material differences in actual outcomes, costs and exposures relative to current estimates, or material changes in such estimates, could have a material adverse effect on IDACORP's consolidated financial positions, results of operations or cash flows.

Regulatory Settlement: In 2004, IPC and the IPUC finalized an income tax issue from IPC's 2003 Idaho general rate case. The issue concerned the regulatory accounting treatment for the capitalized overhead cost tax method IPC adopted in the 2001 IDACORP federal income tax return. As a result of the settlement, a $16 million regulatory tax liability was reversed, creating a tax benefit.

Tax Accounting Method Change: In 2002, IDACORP filed its 2001 federal income tax return and adopted a change to IPC's tax accounting method for capitalized overhead costs. The former method allocated such costs primarily to the construction of plant, while the new method allocates such costs to both construction of plant and the production of electricity.

The tax accounting method change decreased 2002 income tax expense by $35 million, of which $31 million was attributable to 2001 and prior tax years, and $4 million was attributable to the 2002 tax year. The decrease to tax expense was a result of deductions on the applicable tax returns of costs that were capitalized into fixed assets for financial reporting purposes. Deferred income tax expense was not provided because the prescribed regulatory accounting method does not allow for inclusion of such deferred tax expense in current rates. Regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be recovered from customers in future rates.

Tax Credits: IFS generates federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. IFS generated tax credits of $22 million, $20 million and $21 million for the years 2004, 2003 and 2002, respectively.

American Jobs Creation Act of 2004: In October 2004, the president signed into law the American Jobs Creation Act of 2004 (the Act), which may have tax implications for IDACORP and IPC. One provision of the Act with potential implications for the companies relates to manufacturing tax incentives for the production of electricity beginning in 2005. Taxpayers will be able to deduct a percentage (three percent in 2005 and 2006, six percent in 2007 through 2009, and nine percent in 2010 and thereafter) of the lesser of their qualified production activities income or their taxable income. Management is currently reviewing this and other aspects of the Act to determine the impact on the companies.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's and IPC's operating cash flows for 2004 were $195 million and $198 million, respectively.

IDACORP's operating cash flows decreased $118 million in 2004 as a result of reduced receipts from IPC's general business customers of $44 million and an $83 million decrease in net operating cash flows from IE. In 2003, IE received $40 million from the sale of its forward book of electricity trading contracts and collected $45 million on a note receivable from Overton Power District No. 5. These decreases in 2004 were partially offset by a $45 million reduction in income taxes paid.

IPC's operating cash flows have increased $11 million from 2003 as a result of a $61 million decrease in income taxes paid to IDACORP during the year, partially offset by a decrease of $44 million in receipts from general business customers.

In 2005, net cash provided by operating activities will be driven by IPC, where general business revenues and the costs to supply power to general business customers have the greatest impact on operating cash flows. As IPC's service territory enters the sixth consecutive year of below normal water conditions, the company expects to rely more on higher-cost thermal generation and wholesale power purchases to meet its energy needs in 2005. Thus, it is expected that IPC's 2005-2006 PCA will be higher than the 2004-2005 PCA.

Environmental Regulation Costs: IPC anticipates $16 million in annual operating costs for environmental facilities during 2005. Hydroelectric facility expenses account for $11 million of this total and $5 million is related to thermal plant operating expenses. From 2006 through 2007, total environmental related operating costs are estimated to be $33 million. Anticipated expenses related to the hydroelectric facilities account for $23 million and thermal plant expenses are expected to total $10 million during this period.

Working Capital
The changes in working capital are due primarily to an increase in deferred income taxes of $19 million as a result of changes in temporary differences between pre-tax financial income and taxable income, an increase of $11 million in current maturities of long-term debt due to the differences in first mortgage bonds due in 2004 and 2005, a decrease in notes payable of $57 million due to the pay-down of commercial paper and an increase of $18 million in accounts payable due mainly to the accrual of payroll expenses associated with an employee incentive plan.

Pension Expense and Contributions
Total pension expenses in 2004 were $10 million and pension plan contributions were $3 million for the qualified and non-qualified plans. These amounts are not expected to change materially in 2005.

Insurance Expenses
IPC forecasts that its 2005 medical insurance costs will increase to approximately $16 million, approximately $2 million above 2004 actual amounts. Rising health care costs are the principal contributor to this increase.

Dividend Reduction
In September 2003, IDACORP's annual dividend was reduced to $1.20 per share from $1.86 per share. This action was taken in order to strengthen IDACORP's financial position, and its ability to fund IPC's growing capital expenditure needs. The dividend reduction was also made to improve cash flows and help maintain credit ratings.

Contractual Obligations
The following table presents IDACORP's and IPC's contractual cash obligations for the respective periods in which they are due:

			Payment Due by Period
			Total		2005		2006-2007		2008-2009		Thereafter
Long-term debt - IPC (a)			$	987,045	$	60,000	$	81,064	$	82,128	$	763,853
Future interest payments - IPC (b)				774,427		54,102		102,605		90,406		527,314
Long-term debt - Other (a)(i)				74,179		18,603		29,813		16,048		9,715
Future interest payments - Other (b)(i)				15,976		3,761		4,901		2,167		5,147
Capital lease obligations - Other (i)				83		43		40		-		-
Operating leases - IPC (c)				10,119		1,820		1,843		614		5,842
Operating leases - Other (i)				2,889		1,245		1,551		65		28
Purchase obligations - IPC:
	Cogeneration and small power
		production		797,564		43,235		95,331		97,373		561,625
	Fuel swap			1,855		1,855		-		-		-
	Fuel supply agreements			111,309		36,622		40,568		22,053		12,066
	Purchased power & transmission (d)			111,029		79,381		13,230		11,805		6,613
	Maintenance & service agreements (e)			75,835		38,625		18,225		7,379		11,606
	Other (f)			61,576		19,333		9,733		9,919		22,591
		Total IPC purchase obligations		1,159,168		219,051		177,087		148,529		614,501
Purchase obligations - Other (i)				1,759		1,665		64		30		-
Restructuring charges - Other (g)				1,393		338		717		338		-
Other long-term liabilities - IPC (h)				3,958		1,572		1,046		355		985
Total IDACORP			$	3,030,996	$	362,200	$	400,731	$	340,680	$	1,927,385
Total IPC			$	2,934,717	$	336,545	$	363,645	$	322,032	$	1,912,495

(a)		For additional information, see Note 5 to IDACORP's Consolidated Financial Statements.
(b)		Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with variable
		rates, interest is calculated for all future periods using the rates in effect at December 31, 2004.
(c)		Approximately $8 million of the obligations included in the detail of operating leases have contracts that do not specify terms related to
		expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms,
		have been included in the table for presentation purposes.
(d)		Approximately $13 million of the obligations included in the detail of purchased power and transmission have contracts that do not specify
		terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current
		contract terms, have been included in the table for presentation purposes.
(e)		Approximately $24 million of the obligations included in the detail of the maintenance and service agreements can be cancelled without
		penalty. Additionally, approximately $40 million of the contracts do not specify terms related to expiration. As these contracts are presumed
		to continue indefinitely, 10 years of information, estimated based on current contract terms, have been included in the table for presentation
		purposes.
(f)		Approximately $5 million of the obligations included in the detail of other purchase obligations can be cancelled without penalty.
		Additionally, approximately $41 million of the contracts do not specify terms related to expiration. As these contracts are presumed to continue
		indefinitely, 10 years of information, estimated based on current contract terms, have been included in the table for presentation purposes.
(g)		Restructuring charges are related to the wind down of IE; for additional information see Note 15 to IDACORP's Consolidated Financial
		Statements.
(h)		Other long-term liabilities include credit facilities, the human resources information system license fee and lobbying agreements. The
		human resources license fee obligation of approximately $2 million can be cancelled without penalty. Additionally, as the contract does not
		specify terms related to contract expiration, 10 years of information, estimated based on current contract terms, have been included in the table
		for presentation purposes.
(i)		Amounts include the obligations of various subsidiaries with the exception of IPC, which is shown separately.

Off-Balance Sheet Arrangements
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. The mining operations at the Bridger Coal Company are subject to these reclamation and closure requirements.

IPC has guaranteed the performance of reclamation activities of its Bridger Coal Company joint venture. This guarantee, which is renewed each December, was $60 million at December 31, 2004. Bridger Coal has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs and expects that the fund will be sufficient to cover all such costs. Because of the existence of the fund, the estimated fair value as well as the impact on the consolidated financial statements of this guarantee was minimal.

Credit Ratings
S&P: On November 29, 2004, S&P announced that it had lowered the corporate credit ratings and long-term ratings of IDACORP and IPC. The companies' commercial paper rating was affirmed at A-2, and the rating outlooks for both companies are stable.

S&P stated that its decision reflects weakened financial ratios that have resulted from a combination of (1) sustained drought conditions on the Snake River that have depressed IPC's hydro production and increased deferred power costs; (2) a disappointing general rate case ruling by the IPUC, partly mitigated by the approval of a settlement agreement on September 29, 2004, which granted IPC's position on income tax issues; and (3) more than $600 million of expected capital requirements by IPC. S&P stated that these pressures resulted in a financial profile that is weak even for the current BBB+ corporate credit rating. Further, S&P stated that two key issues that would determine future ratings movement were water flows in the Snake River and future rate case rulings by the IPUC.

Moody's: On December 3, 2004, Moody's announced that it had lowered the corporate credit ratings and long-term ratings of IDACORP and the corporate credit ratings and long-term and short-term ratings of IPC. The rating outlooks for both companies are stable.

Moody's stated that the downgrade of IPC's ratings reflected (1) expected weaker cash flow coverage of interest and debt; (2) the likelihood for continued negative free cash flow over the next few years, with internally generated funds falling short of meeting the dividend requirements of IDACORP and significant utility-related capital spending; (3) persistent drought conditions that are likely to result in higher supply costs, not all of which are recoverable under IPC's power cost adjustment mechanism; (4) the final resolution this fall of IPC's rate case, which resulted in a revenue increase of a little more than half of IPC's updated request; and (5) the likely need for additional support from the IPUC in future rate proceedings as IPC adds new generation and transmission infrastructure to help meet customer and load growth and ensure reliability of service.

According to Moody's, the downgrade of IDACORP's ratings reflected the weaker credit profile of IPC, which is by far the largest source of cash flow in the form of dividends to the parent company. Moody's stated that, with the continuing negative free cash flow trend for IPC, IDACORP may need to depend more on dividends from its riskier non-utility subsidiaries to meet its own fixed obligations and common dividend to shareholders, even though management has committed to a "back-to-basics" strategy of focusing on its regulated business.

In addition, Moody's assigned a Baa2 rating to IDACORP's three-year $150 million senior unsecured bank credit facility and a Baa1 rating to IPC's three-year $200 million senior unsecured bank credit facility. Both facilities expire on March 16, 2007.

Moody's stated that the ratings assigned to the bank credit facilities reflected the pari passu ranking of the facilities with each company's other senior unsecured obligations. The facilities serve as part of the alternate liquidity for each company's commercial paper program and contain a maximum 65 percent total debt to total capitalization ratio covenant with a material adverse change clause as part of the representations and warranties relating to each credit extension. In Moody's view, the existence of the material adverse change clause detracts from the quality of the facilities since it could preclude access to funds at the time of greatest need.
Fitch: On January 24, 2005, Fitch announced that it has lowered the long-term ratings of IDACORP and IPC and the short-term debt ratings at IPC. The rating outlooks for both companies are stable.

Fitch stated that the downgrade of IPC's ratings reflected IPC's increased earnings volatility and debt burden relative to cash flows, primarily due to the adverse effect of ongoing drought conditions in southern Idaho and the lower than expected general rate case order issued by the IPUC in 2004. According to Fitch, consolidated leverage has also been adversely affected by higher non-utility debt. Fitch noted that the revised ratings also considered the moderating effect of IPC's PCA mechanism, which has enabled the company to maintain solid interest coverage ratios, the positive impact of a more conservative corporate business profile and ongoing efforts to reduce financial leverage. Fitch stated that the stable rating outlook assumes a return to normal stream flows and hydroelectric generation output in 2006.

Access to capital markets at a reasonable cost is determined in large part by credit quality. These downgrades are expected to increase the cost of new debt and other issued securities going forward. The following outlines the current S&P, Moody's and Fitch ratings of IDACORP's and IPC's securities:

	S&P		Moody's		Fitch
	IPC	IDACORP	IPC	IDACORP	IPC	IDACORP
Corporate Credit Rating	BBB+	BBB+	Baa 1	Baa 2	None	None
Senior Secured Debt	A-	None	A3	None	A-	None
Senior Unsecured Debt	BBB	BBB	Baa 1	Baa 2	BBB+	BBB
	(prelim)	(prelim)
Subordinated Debt	None	BBB-	None	None	None	None
		(prelim)
Preferred Stock	BBB-	None	(P)Baa 3	None	BBB	None
	(prelim)
Trust Preferred Stock	None	BBB-	None	(P)Baa 3	None	None
Short-Term Tax-Exempt Debt	BBB/A-2	None	Baa 1/VMIG-2	None	None	None
Commercial Paper	A-2	A-2	P-2	P-2	F-2	F-2
Credit Facility	None	None	Baa 1	Baa 2	None	None
Rating Outlook	Stable	Stable	Stable	Stable	Stable	Stable

These security ratings reflect the views of the rating agencies. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Capital Requirements
The following table presents IDACORP's and IPC's expected capital requirements from 2005 through 2007:

					2005		2006-2007
					(millions of dollars)
IPC capital expenditures:
	Construction Expenditures (excluding AFDC):
		Generating facilities:
			Hydroelectric		$	15	$	48
			Thermal			41		138
				Total generating facilities		56		186
		Transmission lines and substations				55		115
		Distribution lines and substations				64		118
		General				27		51
			Total construction expenditures (excluding AFDC)			202		470
	Long-term debt maturities					60		81
	Other					5		7
		Total IPC				267		558

IFS investments						31		51
IFS long-term debt maturities						19		30
Other						11		21
	Total IDACORP				$	328	$	660

Variations in the timing and amounts of capital expenditures will result from regulatory and environmental factors, load growth and other resource acquisition needs and the timing of relicensing expenditures.

Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2005 through 2007. The contribution from internal cash generation is dependent primarily upon IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions and IPC's ability to obtain rate relief to cover its operating costs. IDACORP's internally generated cash after dividends is expected to provide 67 percent of 2005 capital requirements, where capital requirements are defined as utility construction expenditures, excluding AFDC, plus other regulated and non-regulated investments. This excludes mandatory or optional principal payments on debt obligations. IPC's construction expenditures represent 81 percent of these capital requirements. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and with increased reliance on externally financed capital.

Utility Construction Program: IPC's construction expenditures were $190 million in 2004, $148 million in 2003 and $128 million in 2002. Aging facilities, relicensing costs and projected load growth are expected to increase construction expenditures over the next three years. IPC's coal-fired plants are approaching their fourth decade of service and plant utilization has increased due to both load growth and reduced hydroelectric generation resulting from below normal water conditions. These factors result in increased upgrade and replacement requirements and plant additions such as the Bennett Mountain Power Plant, which is currently estimated to cost $61 million, $48 million of which had been incurred as of December 31, 2004. This power plant is discussed in more detail later in the MD&A in "Regulatory Issues."

IPC filed its 2004 IRP with the IPUC and the OPUC in August 2004. The 2004 IRP includes several elements requiring significant capital expenditures in the future. Two of these projects are included in the 2005-2007 utility capital expenditure forecast: (1) $79 million of construction costs for a 160 MW combustion turbine peaking resource expected to be operational in mid-2007; and (2) $2 million of planning costs for a $532 million 500 MW coal-fired plant expected to be operational in 2011.

Additional generation needs identified in the 2004 IRP are expected to be met via purchased power agreements. These agreements are projected to be $7 million (19 average MW) in 2006 and $23 million (60 average MW) in 2007. IPC has also issued an RFP for purchased power agreements for 200 MW of wind-powered generation, which is not included in the capital expenditure forecast.

Continuing load growth also requires that IPC add to its transmission system and distribution facilities to provide new service and to maintain reliability. Planned expenditures include distribution lines for new customers and several high-voltage transmission lines.

IPC has no nuclear involvement and its future construction plans do not include development of any nuclear generation.

IPC's aging hydroelectric facilities require continuing upgrades and component replacement. In addition, costs related to relicensing hydroelectric facilities are expected to increase substantially. The three-year construction program anticipates $21 million of upgrades to existing hydroelectric facilities and $42 million of costs associated with relicensing of hydroelectric facilities.

Based upon present environmental laws and regulations, IPC estimates its 2005 capital expenditures for environmental matters, excluding AFDC, will total $18 million. Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $12 million and investments in environmental equipment and facilities at the thermal plants account for $6 million. From 2006 through 2007, environmental-related capital expenditures, excluding AFDC, are estimated to be $40 million. Anticipated expenses related to IPC's hydroelectric facilities account for $30 million and thermal plant expenses are expected to total $10 million.

Other Capital Requirements: Most of IDACORP's non-regulated capital expenditures relate to IFS's investment in affordable housing developments that help lower IDACORP's income tax liability.

Financing Programs
IDACORP's consolidated capital structure consisted of common equity of 48 percent and debt of 52 percent at December 31, 2004.

Credit facilities: On March 17, 2004, IDACORP entered into a $150 million three-year credit agreement with various lenders, Bank One, NA (merged with JPMorgan Chase & Co. on July 1, 2004), as co-lead arranger and administrative agent and Wachovia Bank, National Association, as co-lead arranger and syndication agent (IDACORP Facility). The IDACORP Facility replaced IDACORP's two credit agreements, a $175 million facility that expired on March 17, 2004 and a $140 million facility that was to expire on March 25, 2005. The IDACORP Facility, which will be used for general corporate purposes and commercial paper back-up, will terminate on March 16, 2007. The IDACORP facility provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $150 million, provided that the aggregate amount of the standby letters of credit may not exceed $75 million. At December 31, 2004, no loans were outstanding and $35 million of commercial paper was outstanding.

Under the terms of the IDACORP Facility, IDACORP may borrow floating rate advances and eurodollar rate advances. The floating rate is equal to the higher of (i) the prime rate announced by Bank One or its parent and (ii) the sum of the federal funds effective rate for such day plus 1/2 percent per annum, plus, in each case, an applicable margin. The eurodollar rate is based upon the British Bankers' Association interest settlement rate for deposits in U.S. dollars, as adjusted by the applicable reserve requirement for eurocurrency liabilities imposed under Regulation D of the Board of Governors of the Federal Reserve System, for periods of one, two, three or six months plus the applicable margin. The applicable margin is based on IDACORP's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. The applicable margin for the floating rate advances is zero percent unless IDACORP's rating falls below Baa3 from Moody's or BBB- from S&P, at which time it would equal 0.50 percent. The applicable margin for eurodollar rate advances ranges from 0.54 percent to 1.65 percent depending upon the credit rating. At December 31, 2004, the applicable margin was zero percent for floating rate advances and 1.05 percent for eurodollar rate advances. A facility fee, payable quarterly by IDACORP, is calculated on the average daily aggregate commitment of the lenders under the IDACORP Facility and is also based on IDACORP's rating from Moody's or S&P as indicated above. At December 31, 2004, the facility fee was 0.20 percent.

In connection with the issuance of letters of credit, IDACORP must pay (i) a fee equal to the applicable margin for eurodollar rate advances on the average daily undrawn stated amount under such letters of credit, payable quarterly in arrears, (ii) a fronting fee in an amount agreed upon with the letter of credit issuer, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

A ratings downgrade would result in an increase in the cost of borrowing and of maintaining letters of credit, but would not result in any default or acceleration of the debt under the IDACORP Facility.

The events of default under the IDACORP Facility include (i) nonpayment of principal when due and nonpayment of interest or other fees within five days after becoming due, (ii) materially false representations or warranties made on behalf of IDACORP or any of its subsidiaries on the date as of which made, (iii) breach of covenants, subject in some instances to grace periods, (iv) voluntary and involuntary bankruptcy of IDACORP or any material subsidiary, (v) the non-consensual appointment of a receiver or similar official for IDACORP or any of its material subsidiaries or any substantial portion (as defined in the IDACORP Facility) of its property, (vi) condemnation of all or any substantial portion of the property of IDACORP or its subsidiaries, (vii) default in the payment of indebtedness in excess of $25 million or a default by IDACORP or any of its subsidiaries under any agreement under which such debt was created or governed which will cause or permit the acceleration of such debt or if any of such debt is declared to be due and payable prior to its stated maturity, (viii) IDACORP or any of its subsidiaries not paying, or admitting in writing its inability to pay, its debts as they become due, (ix) the acquisition by any person or two or more persons acting in concert of beneficial ownership (within the meaning of Rule 13d-3 of the Securities Exchange Act of 1934) of 20 percent or more of the outstanding shares of voting stock of IDACORP, (x) the failure of IDACORP to own free and clear of all liens, at least 80 percent of the outstanding shares of voting stock of IPC on a fully diluted basis, (xi) certain liabilities under the Employee Retirement Income Security Act of 1974 exceeding $25 million and (xii) IDACORP or any subsidiary being subject to any proceeding or investigation pertaining to the release of any toxic or hazardous waste or substance into the environment or any violation of any environmental law (as defined in the IDACORP Facility) which could reasonably be expected to have a material adverse effect (as defined in the IDACORP Facility). A default or an acceleration of indebtedness of IPC under the IPC Facility described below will result in a cross default under the IDACORP Facility, provided that such indebtedness is equal to at least $25 million.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or the appointment of a receiver, the obligations of the lenders to make loans under the facility and of the letter of credit issuer to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding 51 percent of the outstanding loans or 51 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and of the letter of credit issuer to issue letters of credit under the facility or declare the obligations to be due and payable. IDACORP will also be required to deposit into a collateral account an amount equal to the aggregate undrawn stated amount under all outstanding letters of credit and the aggregate unpaid reimbursement obligations thereunder.

On March 17, 2004, IPC entered into a $200 million three-year credit agreement with various lenders, Bank One, NA (merged with JPMorgan Chase & Co. on July 1, 2004), as co-lead arranger and administrative agent and Wachovia Bank, National Association, as co-lead arranger and syndication agent (IPC Facility). The IPC Facility replaced IPC's $200 million credit agreement, which expired on March 17, 2004. The IPC Facility, which expires on March 16, 2007, will be used for general corporate purposes and commercial paper back-up. At December 31, 2004, no loans or commercial paper were outstanding. Under the terms of the IPC Facility, IPC may borrow floating rate advances and eurodollar rate advances. The methods of calculating the floating rate and the eurodollar rate are the same as set forth above for the IDACORP Facility. The applicable margin for the IPC Facility is also dependent upon IPC's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. At December 31, 2004, the applicable margin for the IPC Facility was zero percent for floating rate advances and 1.05 percent for eurodollar rate advances. A facility fee, payable quarterly by IPC, is calculated on the average daily aggregate commitment of the lenders under the IPC Facility and is also based on IPC's rating from Moody's or S&P as indicated above. At December 31, 2004, the facility fee was 0.20 percent. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in any default or acceleration of the debt under the IPC Facility.

The events of default under the IPC Facility are the same as under the IDACORP Facility.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IPC or the appointment of a receiver, the obligations of the lenders to make loans under the facility will automatically terminate and all unpaid obligations of IPC will become due and payable. Upon any other event of default, the required lenders (or the administrative agent with the consent of the required lenders) may terminate or suspend the obligation of the lenders to make loans under the IPC Facility or declare IPC's unpaid obligations to be due and payable.

Each credit facility contains a material adverse change clause as part of the representations and warranties relating to each credit extension.

IDACORP and IPC are exploring the option of extending the life of their credit facilities to take advantage of the current favorable bank market conditions.

Debt Covenants: The IPC Facility and the IDACORP Facility each contain a covenant requiring IPC and IDACORP, respectively, to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. At December 31, 2004, the leverage ratios for both IPC and IDACORP were 52 percent.

Other covenants in the IPC Facility include (i) prohibitions against investments and acquisitions by IPC or any subsidiary without the consent of the required lenders, subject to exclusions for investments in cash equivalents or securities of IPC, investments by IPC and its subsidiaries in any business trust controlled, directly or indirectly, by IPC to the extent such business trust purchases securities of IPC, investments and acquisitions related to the energy business of IPC and its subsidiaries not exceeding $500 million in the aggregate at any one time outstanding, investments by IPC or a subsidiary in connection with a permitted receivables securitization (as defined in the IPC Facility), (ii) prohibitions against IPC or any material subsidiary merging or consolidating with any other person or selling or disposing of all or substantially all of its property to another person without the consent of the required lenders, subject to exclusions for mergers into or dispositions to IPC or a wholly owned subsidiary and dispositions in connection with a permitted receivables securitization, (iii) restrictions on the creation of liens by IPC or any material subsidiary and (iv) prohibitions on any material subsidiary entering into any agreement restricting its ability to declare or pay dividends to IPC except pursuant to a permitted receivables securitization. At December 31, 2004, IPC was in compliance with all of the covenants of the facility.

Other covenants in the IDACORP Facility include (i) prohibitions against investments and acquisitions by IDACORP or any subsidiary without the consent of the required lenders subject to exclusions for investments in cash equivalents or securities of IDACORP, investments by IDACORP and its subsidiaries in any business trust controlled, directly or indirectly, by IDACORP to the extent such business trust purchases securities of IDACORP, investments and acquisitions related to the energy business or other business of IDACORP and its subsidiaries not exceeding $500 million in the aggregate at any one time outstanding (provided that investments in non-energy related businesses not exceed $150 million), investments by IDACORP or a subsidiary in connection with a permitted receivables securitization (as defined in the IDACORP Facility), (ii) prohibitions against IDACORP or any material subsidiary merging or consolidating with any other person or selling or disposing of all or substantially all of its property to another person without the consent of the required lenders, subject to exclusions for mergers into or dispositions to IDACORP or a wholly owned subsidiary and dispositions in connection with a permitted receivables securitization, (iii) restrictions on the creation of liens by IDACORP or any material subsidiary and (iv) prohibitions on any material subsidiary entering into any agreement restricting its ability to declare or pay dividends to IDACORP except pursuant to a permitted receivables securitization.

IDACORP is also required to maintain an interest coverage ratio of Credit Agreement EBITDA to consolidated interest charges equal to at least 2.75 to 1.00 as of the end of any fiscal quarter. Credit Agreement EBITDA is a financial measure that is used in the IDACORP Facility and is not a defined term under GAAP. Credit Agreement EBITDA differs from the term "EBITDA" (earnings before interest expense, income tax expense and depreciation and amortization) as it is commonly used. Credit Agreement EBITDA is defined as consolidated net income plus interest charges, income taxes, depreciation and all non-cash items that reduce such consolidated net income minus all non-cash items that increase consolidated net income. At December 31, 2004, IDACORP was in compliance with all of the covenants of the facility.

Long-term financings: On December 15, 2004, IDACORP issued 4,025,000 shares of its common stock at $30 per share. After expenses, IDACORP received approximately $116 million. These proceeds were used to make a capital contribution to IPC and to pay down short-term borrowings at both companies. IDACORP currently has $679 million remaining on two shelf registration statements that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. IPC currently has in place two registration statements that can be used for the issuance of an aggregate principal amount of $300 million of first mortgage bonds (including medium-term notes) and unsecured debt.

See Note 5 to IDACORP's Consolidated Financial Statements for more information regarding long-term financings.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings
Alves Dairy: On May 18, 2004, Herculano and Frances Alves, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs seek unspecified monetary damages for negligence and nuisance (allegedly allowing electrical current to flow in the earth, injuring the plaintiffs' right to use and enjoy their property and adversely affecting their dairy herd). On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves' complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The parties have begun discovery in the case. No trial date has been scheduled. On December 14, 2004, IPC filed a motion with the District Court for permission to appeal the court's denial of IPC's Motion to Disqualify the trial judge, for cause. By order dated January 31, 2005, the District Court granted the motion for permissive appeal. On February 16, 2005, IPC filed a motion for permissive appeal with the Idaho Supreme Court. If granted, the Supreme Court will determine whether the District Court properly refused to disqualify the trial judge for cause.

IPC intends to vigorously defend its position in this proceeding and believes this matter, with insurance coverage, will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Shareholder Lawsuits: On May 26, 2004 and June 22, 2004, respectively, two shareholder lawsuits were filed against IDACORP and certain of its directors and officers. The lawsuits, captioned Powell, et al. v. IDACORP, Inc., et al. and Shorthouse, et al. v. IDACORP, Inc., et al., raise largely similar allegations. The lawsuits are putative class actions brought on behalf of purchasers of IDACORP stock between February 1, 2002 and June 4, 2002, and were filed in the United States District Court for the District of Idaho. The named defendants in each suit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J. LaMont Keen and Darrel T. Anderson.

The complaints alleged that, during the purported class period, IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about the company's financial outlook in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, thereby causing investors to purchase the company's common stock at artificially inflated prices. More specifically, the complaints alleged that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to defendants or recklessly disregarded by them: (1) IDACORP failed to appreciate the negative impact that lower volatility and reduced pricing spreads in the western wholesale energy market would have on its marketing subsidiary, IE; (2) IDACORP would be forced to limit its origination activities to shorter-term transactions due to increasing regulatory uncertainty and continued deterioration of creditworthy counterparties; (3) IDACORP failed to discount for the fact that IPC may not recover from the lingering effects of the prior year's regional drought and (4) as a result of the foregoing, defendants lacked a reasonable basis for their positive statements about IDACORP and their earnings projections. The Powell complaint also alleged that the defendants' conduct artificially inflated the price of the company's common stock. The actions sought an unspecified amount of damages, as well as other forms of relief. By order dated August 31, 2004, the court consolidated the Powell and Shorthouse cases for pretrial purposes, and ordered the plaintiffs to file a consolidated complaint within 60 days. On November 1, 2004, IDACORP and the directors and officers named above were served with a purported consolidated complaint captioned Powell et al. v. IDACORP, Inc. et al., which was filed in the United States District Court for the District of Idaho.

The new complaint alleges that during the class period IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about its business operations, and specifically the IDACORP Energy financial outlook, in violation of Rule 10b-5, thereby causing investors to purchase IDACORP's common stock at artificially inflated prices. The new complaint alleges that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to it or recklessly disregarded by it: (1) IDACORP falsely inflated the value of energy contracts held by IDACORP Energy in order to report higher revenues and profits; (2) IDACORP permitted IPC to inappropriately grant native load priority for certain energy transactions to IDACORP Energy; (3) IDACORP failed to file 13 ancillary service agreements involving the sale of power for resale in interstate commerce that it was required to file under Section 205 of the Federal Power Act; (4) IDACORP failed to file 1,182 contracts that IPC assigned to IDACORP Energy for the sale of power for resale in interstate commerce that IPC was required to file under Section 203 of the Federal Power Act; (5) IDACORP failed to ensure that IDACORP Energy provided appropriate compensation from IDACORP Energy to IPC for certain affiliated energy transactions; and (6) IDACORP permitted inappropriate sharing of certain energy pricing and transmission information between IPC and IDACORP Energy. These activities allegedly allowed IDACORP Energy to maintain a false perception of continued growth that inflated its earnings. In addition, the new complaint alleges that those earnings press releases, earnings release conference calls, analyst reports and revised earnings guidance releases issued during the class period were false and misleading. The action seeks an unspecified amount of damages, as well as other forms of relief. IDACORP and the other defendants filed a consolidated motion to dismiss on February 9, 2005, which is now pending.

IDACORP and the other defendants intend to defend themselves vigorously against the allegations. The company cannot, however, predict the outcome of these matters.

Public Utility District No. 1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC and IE. On March 9, 2001, Grays Harbor entered into a 20 MW purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per MWh. In June 2001, with the consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE. In its lawsuit, Grays Harbor alleged that the assignment was void and unenforceable, and sought restitution from IE and IDACORP, or in the alternative, Grays Harbor alleged that the contract should be rescinded or reformed. Grays Harbor sought as damages an amount equal to the difference between $249 per MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.

IDACORP, IPC and IE had this action removed from the state court to the U.S. District Court for the Western District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor's complaint, asserting that the U.S. District Court lacked jurisdiction because the FERC has exclusive jurisdiction over wholesale power transactions and thus the matter is preempted under the Federal Power Act and barred by the filed-rate doctrine. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January 28, 2003. On February 25, 2003, Grays Harbor filed a Notice of Appeal, appealing the final judgment of dismissal to the U.S. Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed the dismissal of Grays Harbor's complaint, finding that Grays Harbor's claims were preempted by federal law and were barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation, and held that Grays Harbor could seek monetary relief, if at all, only from the FERC, and not from the courts. IDACORP, IPC and IE sought rehearing from the Ninth Circuit arguing that the court erred in granting leave to amend the complaint as such a declaratory relief claim would be preempted and would be barred by the filed-rate doctrine. The Ninth Circuit denied the rehearing request on October 25, 2004 and the decision became final on November 12, 2004. On that same date, the companies took steps to have the case transferred and consolidated with other similar cases arising out the California energy crisis currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. On November 18, 2004, Grays Harbor filed an amended complaint alleging that the contract was formed under circumstances of "mistake" as to an "artificial . . . power shortage." Grays Harbor asks that the contract therefore be declared "unenforceable" and found "unconscionable." On December 23, 2004, the Judicial Panel on Multidistrict Litigation conditionally transferred the case to Judge Whaley. Grays Harbor is opposing transfer, however, and the Judicial Panel on Multidistrict Litigation has yet to finally rule on the transfer. IDACORP, IE and IPC have not responded to the amended complaint as a response is not yet required. The companies plan to file a motion to dismiss the complaint. The companies intend to vigorously defend their position on remand and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Port of Seattle: On May 21, 2003, the Port of Seattle, a Washington municipal corporation, filed a lawsuit against 20 energy firms, including IPC and IDACORP, in the U.S. District Court for the Western District of Washington at Seattle. The Port of Seattle's complaint alleges fraud and violations of state and federal antitrust laws and the Racketeer Influenced and Corrupt Organizations Act. On December 4, 2003, the Judicial Panel on Multidistrict Litigation transferred the case to the Southern District of California for inclusion with several similar multidistrict actions currently pending before the Honorable Robert H. Whaley.

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit. The appeal has been fully briefed, however no date has been set for oral argument. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wah Chang: On May 5, 2004, Wah Chang, a division of TDY Industries, Inc., filed two lawsuits in the United States District Court for the District of Oregon against numerous defendants. IDACORP, IE and IPC are named as defendants in one of the lawsuits. The complaints allege violations of federal antitrust laws, violations of the Racketeer Influenced and Corrupt Organizations Act, violations of Oregon antitrust laws and wrongful interference with contracts. Wah Chang's complaint is based on allegations relating to the western energy situation. These allegations include bid rigging, falsely creating congestion and misrepresenting the source and destination of energy. The plaintiff seeks compensatory damages of $30 million and treble damages.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response is not yet required. The companies, along with the other defendants, subsequently filed a motion to dismiss the complaint, which was heard on January 20, 2005. By order dated February 11, 2005, the court granted the companies' and other defendants' motion to dismiss. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

City of Tacoma: On June 7, 2004, the City of Tacoma, Washington filed a lawsuit in the United States District Court for the Western District of Washington at Tacoma against numerous defendants including IDACORP, IE and IPC. The City of Tacoma's complaint alleges violations of the Sherman Antitrust Act. The claimed antitrust violations are based on allegations of energy market manipulation, false load scheduling and bid rigging and misrepresentation or withholding of energy supply. The plaintiff seeks compensatory damages of not less than $175 million.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response is not yet required. The companies, along with the other defendants, filed a motion to dismiss the complaint which was taken under submission by the court, without oral argument. By order dated February 11, 2005, the court granted the companies' and other defendants' motion to dismiss. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Western Energy Proceedings at the FERC: IE and IPC are involved in a number of FERC proceedings arising out of the western energy situation and claims that dysfunctions in the organized California markets contributed to or caused unjust and unreasonable prices in Pacific Northwest spot markets, and may have been the result of manipulations of gas or electric power markets. They include proceedings involving: (1) the chargeback provisions of the California Power Exchange (CalPX) participation agreement, which was triggered when a participant defaulted on a payment to the CalPX. Upon such a default, other participants were required to pay their allocated share of the default amount to the CalPX. This provision was first triggered by the Southern California Edison default and later by the Pacific Gas and Electric Company default. The FERC ordered the CalPX to rescind all chargeback actions related to the Southern California Edison and Pacific Gas and Electric Company liabilities. The CalPX is awaiting further orders from the FERC and bankruptcy court before distributing the funds it collected under the chargeback mechanism; (2) efforts by the State of California to obtain refunds for a portion of the spot market sales prices from sellers of electricity into California from October 2, 2000 through June 20, 2001. California is claiming that the prices were not just and reasonable and were not in compliance with the Federal Power Act. The FERC issued an order on refund liability on March 26, 2003 which multiple parties, including IE, sought rehearing on. On October 16, 2003, the FERC denied the requests for rehearing and required the California Independent System Operator (Cal ISO) to make a compliance filing regarding refund amounts within five months, which has since been delayed until at least April 2005. On May 12, 2004, the FERC issued an order clarifying its earlier refund orders and denying a request by certain parties to present as evidence an earlier settlement between the California Public Utilities Commission and El Paso related to manipulation of gas pipeline capacity claiming that the settlement dollars California is receiving from El Paso ($1.69 billion) are duplicative of the FERC order changing the gas component of its refund methodology. The FERC denied requests for rehearing on November 23, 2004. On December 2, 2003, IE and others petitioned the United States Court of Appeals for the Ninth Circuit for review of the FERC's orders on California refunds. As additional FERC orders have been issued, further petitions for review have been filed, including by IE, and have been consolidated with the appeals already pending before the Ninth Circuit. On September 21, 2004, the Ninth Circuit convened the first of its case management proceedings, a procedure reserved to help organize complex cases. On October 22, the Ninth Circuit severed several issues related to FERC's refund jurisdiction and established a schedule for briefing and oral argument. At December 31, 2004, with respect to the CalPX chargeback and the California Refund proceedings discussed above, the CalPX and the Cal ISO owed $14 million and $30 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $42 million against these receivables. This reserve was calculated taking into account the uncertainty of collection, given the California energy situation. Based on the reserve recorded as of December 31, 2004, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a material adverse effect on its consolidated financial position, results of operations or cash flows; (3) the Pacific Northwest refund proceedings wherein it was argued that the spot market in the Pacific Northwest was affected by the dysfunction in the California market, warranting refunds. The FERC rejected this claim on June 25, 2003 and denied rehearing on November 11, 2003 and February 9, 2004. The FERC orders were appealed to the Ninth Circuit. On July 21, 2004, the City of Seattle petitioned the Ninth Circuit requesting the court to direct the FERC to permit additional evidence consisting of audiotapes of Enron trader conversations and a delay in the briefing schedule in the Pacific Northwest refund. On August 2, 2004, the Ninth Circuit held the briefing schedule in abeyance pending resolution of the motion to offer additional evidence. On August 2, 2004 and August 3, 2004, respectively, the FERC and a group of parties, including IE, filed their answers in opposition to the motion to offer additional evidence. On September 29, 2004, the Ninth Circuit denied the City of Seattle's motion without prejudice to renew the request in briefing in the Pacific Northwest Refund case and established a briefing schedule with final briefs due in July of 2005. IE and IPC are unable to predict the outcome of these matters; and (4) two FERC show cause orders which resulted from a ruling of the Ninth Circuit that the FERC permit the California parties in the California refund proceeding to submit materials to the FERC demonstrating market manipulation by various sellers of electricity into California. On June 25, 2003, the FERC ordered a large number of parties including IPC to show cause why certain trading practices did not constitute gaming ("gaming") or anomalous market behavior ("partnership") in violation of the Cal ISO and CalPX Tariffs. On October 16, 2003, IPC reached agreement with the FERC Staff on the show cause orders. The "gaming" settlement was approved by the FERC on March 3, 2004. The FERC approved the motion to dismiss the "partnership" proceeding on January 23, 2004. Although the orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit, the order dismissing IPC from the "partnership" proceedings was not the subject of rehearing requests. Eight parties have requested rehearing of the FERC's March 3, 2004 order approving the "gaming" settlement but the FERC has not yet acted on those requests.

On July 21, 2004, Californians for Renewable Energy filed a motion with the FERC in connection with the California refund, the Pacific Northwest refund and the market manipulation cases requesting the FERC to revise its approach to the 2000-2001 western energy situation by (1) revoking market-based rate authority and replacing it with cost-of-service rates and requiring refunds back to the date of the order granting the market-based rate authority, (2) revising long-term contracts entered into during the western energy situation and (3) deferring new and rejecting existing refund settlements. On September 9, 2004, Californians for Renewable Energy filed a motion to withdraw its July 21, 2004 pleading. By operation of law, the withdrawal was effective September 24, 2004.

These matters are discussed in more detail in Note 8 to IDACORP's Consolidated Financial Statements.

Other Legal Proceedings: IDACORP, IPC and/or IE are involved in various lawsuits and legal proceedings, discussed above and in detail in Note 8 to IDACORP's Consolidated Financial Statements. The companies believe they have meritorious defenses to all lawsuits and legal proceedings where they have been named as defendants. Resolution of any of these matters will take time, and the companies cannot predict the outcome of any of these proceedings. The companies believe that their reserves are adequate for these matters.

Other Legal Issues
Idaho Power Company Transmission Line Rights-of-Way Across Fort Hall Indian Reservation: IPC has multiple transmission lines that cross the Shoshone-Bannock Tribes' Fort Hall Indian Reservation near the city of Pocatello in southeastern Idaho. IPC has been working since 1996 to renew four of the right-of-way permits (for five of the transmission lines), which have stated permit expiration dates between 1996 and 2003. IPC filed applications with the U.S. Department of the Interior, Bureau of Indian Affairs, to renew the four rights-of-way for 25 years, including payment of the independently appraised value of the rights-of-way to the tribes (and the tribal allottees who own portions of the rights-of-way). Due to the lack of definitive legal guidelines for valuation of the permit renewals, IPC is in the process of negotiating mutually acceptable renewal terms with the tribes and allottees. The parties are pursuing a possible 23-year renewal of the permits (including all pre-renewal periods) for a total payment of approximately $7 million to the tribes and allottees. IPC, the tribes and the Bureau of Indian Affairs are currently working through the process of finalizing the agreement, including obtaining the requisite consents from the allottees. The parties hope to obtain the required consents early in 2005. On December 27, 2004, IPC filed an application with the IPUC seeking an accounting order regarding the treatment of this transaction. On February 28, 2005, the IPUC issued an order approving IPC's application.

Environmental Issues
Idaho Water Management Issues: IPC holds water rights for generation purposes at each of its hydroelectric projects. The state of Idaho is experiencing its sixth consecutive year of below normal precipitation and stream flows. These conditions have exacerbated a developing water shortage in the state, which is manifested by a number of water issues that are of interest to IPC because of their potential impacts on generation at IPC's hydroelectric projects including - declining Snake River base flows and recharge to the Eastern Snake Plain Aquifer, a large underground aquifer that has been estimated to hold between 200-300 million acre-feet of water. With respect to base flows, observed records suggest that the base flows in the Snake River, particularly between IPC's Twin Falls and Swan Falls projects, have been in decline for several decades. The yearly average flow measured below Swan Falls declined at an average rate of 43 cubic feet per second (cfs) per year during the period 1961-2003, and observed stream flow gains between Twin Falls and Lower Salmon Falls, which are largely attributed to base flow contribution, declined at a rate of 27 cfs/year over the same period. Low flow in the Snake River near Hagerman, Idaho continues to be observed - several river gauges in that area are recording the lowest Snake River flows since the early 1960s. Regarding aquifer recharge, the Snake River, at various places throughout its reach from Rexburg, Idaho to King Hill, Idaho, is connected to the Eastern Snake Plain Aquifer. In certain times of the year, the flows into the Snake River below Milner Dam are heavily dependent on the outflow from springs that are connected to and fed by the Eastern Snake Plain Aquifer in the Thousand Springs reach of the Snake River. The majority of IPC's hydroelectric projects are below Milner Dam.

Ground water irrigators and surface water irrigators in southern Idaho are involved in a conflict regarding shortages of irrigation water. One solution that has been offered is aquifer recharge, or using surface water supplies to increase ground water supplies by allowing the water to sink into the earth in porous locations. IPC believes this solution will impact its senior water rights and therefore conflicts with state law and will likely reduce the amount of water available for generation in IPC's hydroelectric plants.

In August 2001, the Idaho Department of Water Resources designated portions of the Eastern Snake Plain Aquifer that are tributary to the Thousand Springs reach of the Snake River as a Ground Water Management Area due to the effect, exacerbated by several years of drought, of junior priority ground water withdrawals on senior surface water rights. Subsequently, in late 2001 and early 2002, junior ground water interests entered into a stipulated agreement with certain affected senior surface water users in an effort to mitigate the effects of ground water pumping. The Idaho Department of Water Resources established two ground water districts to facilitate the operation of the agreement. However, in 2003, surface water users that were not parties to the stipulated agreement filed delivery calls with the Idaho Department of Water Resources, demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the aquifer and affecting flows to senior surface water rights. These delivery calls resulted in several administrative actions before the Idaho Department of Water Resources and a judicial action before the State District Court in Ada County, Idaho. Because IPC holds water rights in the Thousand Springs area that are dependent on spring flows and the overall condition of the Eastern Snake Plain Aquifer, IPC intervened in these actions to protect its interests and encourage the development of a long-term management plan that will protect the aquifer from further depletion.

In March 2004, the State of Idaho negotiated an interim agreement between various ground and surface water users in an effort to allow the state to develop short and long-term goals and objectives for effectively managing the Eastern Snake Plain Aquifer and ensuring that senior water rights are protected consistent with the prior appropriation doctrine and state law. As part of the interim agreement, the pending administrative and judicial processes are stayed until March 15, 2005 and the Idaho Legislature directed the Natural Resources Interim Committee, a standing committee, to meet and evaluate ways to stabilize and properly manage the aquifer. This Interim Committee has been meeting with interested parties since March of 2004 in an effort to resolve the pending controversies. IPC is participating in that process as necessary to protect its existing hydroelectric generation water rights.

On January 14, 2005, seven surface water irrigation entities from above Milner Dam that are not parties to the March 2004 interim agreement submitted a delivery call letter to the Director of the Idaho Department of Water Resources requesting that the Director administer and deliver their senior natural flow and storage water rights pursuant to Idaho law. The irrigation entities contend that existing data reflects that senior surface water rights above Milner Dam have been reduced by approximately 600,000 acre-feet, a 30 percent reduction, over the past six years due, in part, to junior groundwater pumping from the Eastern Snake Plain Aquifer and that these reductions have resulted in cumulative shortages in natural flow and storage water accrual in American Falls Reservoir, a U.S. Bureau of Reclamation reservoir that supplies a portion of their senior water rights. These same entities also filed a petition with the Idaho Department of Water Resources for water rights administration and designation of the Eastern Snake Plain Aquifer as a Ground Water Management Area. On February 3, 2005, the Idaho Ground Water Appropriators, Inc., an Idaho non-profit corporation organized to promote and represent the interests of groundwater users, petitioned to intervene in the delivery call action.

On February 14, 2005, the Director of the Idaho Department of Water Resources issued an interlocutory order establishing a contested case under the department's procedural rules in response to the delivery call letter. The order granted the Idaho Ground Water Appropriators, Inc.'s petition to intervene and requested that the surface water irrigation entities supply the department with additional information relative to their claim for delivery of water within 30 days of the date of the order.

Similar to the surface water irrigation entities, IPC holds storage rights in American Falls Reservoir. To the extent that groundwater pumping and the reduced surface water flows have impacted American Falls storage water rights, IPC's storage rights have also been impacted. As such, IPC submitted a letter to the Idaho Department of Water Resources in support of the delivery call and asked the department to grant IPC intervenor status in the pending contested case. The Idaho Ground Water Appropriators, Inc. filed a motion opposing IPC's intervention.

REGULATORY ISSUES:

General Rate Case
Idaho: IPC filed its Idaho general rate case with the IPUC on October 16, 2003. IPC originally requested approximately $86 million annually in additional revenue, an average 17.7 percent increase to base rates. On rebuttal, IPC lowered its overall requested increase to $70 million annually, an average of 14.5 percent. The IPUC approved an increase in IPC's electric rates of $25 million, an average of 5.2 percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004.

In the order, the IPUC approved a return on equity of 10.25 percent, compared to the 11.2 percent IPC requested, an overall rate of return of 7.9 percent, compared to the 8.3 percent requested by IPC. The IPUC reduced the $1.55 billion in rate base requested for IPC's Idaho jurisdiction to $1.52 billion.

Additionally, the IPUC approved higher rates for residential and small commercial customers during the summer months to encourage conservation. The 12.6 percent higher summer rate applies to monthly usage over 300 kilowatt-hours. The IPUC also ordered time-of-use rates to be phased in for industrial customers, asked IPC to submit a proposal for a conservation program for industrial customers and ordered increased low-income weatherization funding of $1 million annually.

The IPUC also noted two other issues to be addressed in separate proceedings and potentially handled in workshops instead of formal hearings. These issues are: (1) investigating approaches to removing financial disincentives to IPC for investing in cost effective energy efficiency and clean distributed generation and (2) investigating various cost of service issues raised in the general rate case, including those associated with load growth. During the year, initial workshops were held on both issues.

The IPUC disallowed several costs in the Idaho general rate case order, including $12 million annually related to the determination of IPC's income tax expense, $8 million of incentive payments capitalized in prior years and $1 million of capitalized pension expense. On June 15, 2004, IPC filed with the IPUC a petition for reconsideration of these and other items. On July 13, 2004, the IPUC granted this petition in part, agreeing to reconsider the issue relating to the determination of IPC's income tax expense and, in light of the IPUC Staff's computational errors, ordering rates increased by approximately $3 million on or before August 1, 2004. IPC recorded an impairment of assets of $9 million related to the disallowed incentive payments and the disallowed capitalized pension expenses.

On September 28, 2004, the IPUC issued separate orders approving two Settlement Agreements entered into on August 16, 2004 between IPC and the IPUC Staff.

Settlement No. 1, approved by the IPUC in Order No. 29601, relates to the calculation of IPC's taxes for purposes of test year income tax expense. In the Idaho general rate case order, the IPUC adopted the use of a historic five-year average income tax rate to calculate IPC's income tax expense. Settlement No. 1 approved the modification of the general rate case order to utilize IPC's statutory income tax rates to compute test year income tax expense. As a result, IPC will compute and record monthly during the period June 1, 2004 through May 31, 2005 a regulatory asset (with interest accrued at a rate of one percent per annum) of approximately $12 million. Rates will increase on June 1, 2005 to reflect the ongoing impact of the tax expense. Approximately $7 million of this amount was recorded in 2004 as other operating revenue. Settlement No. 1 allows IPC to continue its compliance with the normalization provisions of the Internal Revenue Code of 1986, as amended, and associated Treasury Regulations, and will allow IPC to continue to receive the benefits of accelerated depreciation.

Settlement No. 2, approved by the IPUC in Order No. 29600, resolved outstanding issues related to: (1) an unplanned outage at one of the two units of the Valmy plant in the summer of 2003, (2) a matter relating to the expense adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002. In Settlement No. 2, IPC and the IPUC Staff agreed that the IPUC will not examine the cost of replacement power and a possible PCA adjustment resulting from the Valmy plant outage, and the expense adjustment rate for growth component of the PCA will continue at its existing value until IPC's next general rate case. In September 2004, as a result of the order, IPC established a regulatory liability of $19 million with a charge to PCA expense. A monthly credit of approximately $804,000 will be included in the PCA through May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing income tax expense. This regulatory tax liability was established in 2002 when IPC changed its tax accounting method for capitalized overhead costs.

The final result of IPC's general rate case was a $40 million increase to the base Idaho jurisdictional revenue requirement, comprised of $25 million in the initial order, $3 million related to computational errors and $12 million in the order approving Settlement No. 1.

IPC plans to file an Idaho general rate case with the IPUC in the fall of 2005, requesting rates to be implemented on June 1, 2006. IPC is unable to predict what rate relief, if any, the IPUC will grant.

Oregon: On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent, approximately $4 million annually. IPC's filing includes a request to introduce summer and non-summer rates similar to proposals that were approved in the Idaho general rate case. IPC has not filed for a change to its overall rates in Oregon since 1995.

On October 19, 2004, the OPUC suspended IPC's request for a period of time not to exceed nine months from October 20, 2004 to investigate the propriety and reasonableness of the request. A pre-hearing conference and public meeting was held on November 18, 2004. The hearing schedule called for a settlement conference, which began on February 14, 2005, and an evidentiary hearing to begin on May 23, 2005. IPC is unable to predict what rate relief, if any, the OPUC will grant.

Deferred Power Supply Costs
IPC's deferred net power supply costs consisted of the following at December 31:

		2004		2003
Oregon deferral		$	12,047	$	13,620
Idaho PCA current year net power supply cost deferrals:
	Deferral for 2004-2005 rate year		-		44,664
	Deferral for 2005-2006 rate year		22,778		-
Irrigation Lost Revenues			13,290		-
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2003		-		13,646
	Remaining true-up authorized May 2004		11,415		-
	Total deferral	$	59,530	$	71,930

Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the true-up of the true-up for the prior years' unrecovered portion, is then included in the calculation of the next year's PCA.

On April 15, 2004, IPC filed its 2004-2005 PCA with the IPUC requesting recovery of $71 million above base rates and a proposed effective date of June 1, 2004. On May 25, 2004, the IPUC issued Order No. 29506 approving IPC's filing with additional instructions for IPC and the IPUC Staff to examine the cost of replacement power attributable to the unplanned outage at the Valmy plant in 2003. Based on the order approving Settlement No. 2, discussed above, the IPUC will not examine the costs related to this outage.

On May 15, 2003, the IPUC issued Order No. 29243 approving IPC's 2003-2004 PCA filing, with a small adjustment to the original filing. As approved, IPC's rates were adjusted to collect $81 million above 1993 base rates.

On April 15, 2002, the IPUC issued Order No. 28992 disallowing recovery of $12 million of lost revenues resulting from the Irrigation Load Reduction Program that was in place in 2001. IPC believed that this IPUC order was inconsistent with Order No. 28699, dated May 25, 2001, that allowed recovery of such costs, and IPC filed a Petition for Reconsideration on May 2, 2002. On August 29, 2002, the IPUC issued Order No. 29103 denying the Petition for Reconsideration. As a result of this order, approximately $12 million was expensed in September 2002. IPC believed it was entitled to recover this amount and argued its position before the Idaho Supreme Court on December 5, 2003. On March 30, 2004, the Idaho Supreme Court set aside the IPUC denial of the recovery of lost revenues and remanded the matter to the IPUC to determine the amount of lost revenues to be recovered. On December 29, 2004, the IPUC issued Order No. 29669 allowing IPC to recover $12 million in lost revenues and $2 million in interest. The recovery will be included as part of IPC's annual PCA beginning June 1, 2005.

Oregon: On March 2, 2005 IPC file for an accounting order to defer net power supply costs for the period of March 1, 2005 through February 28, 2006 in anticipation of the low water conditions IPC is currently experiencing. The net system power supply costs included in this filing was $169 million. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses.

IPC is also recovering calendar year 2001 excess power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC approved rate increases totaling six percent, which was the maximum annual rate of recovery allowed under Oregon state law at that time. These increases were recovering approximately $2 million annually. During the 2003 Oregon legislative session, the maximum annual rate of recovery was raised to ten percent under certain circumstances. IPC requested and received authority to increase the surcharge to ten percent. As a result of the increased recovery rate, which became effective on April 9, 2004, IPC will recover approximately $3 million annually.

Bennett Mountain Power Plant: On February 24, 2003, IPC issued a formal RFP seeking bids for the construction of up to 200 MW of additional generation to support the growing seasonal demand for electricity in IPC's service area. As a result of this process, IPC selected TR2 as the successful bidder for the construction of the Bennett Mountain Power Plant, a 164 MW gas-fired generating plant near Mountain Home, Idaho. TR2 contracted with Siemens Westinghouse Power Corporation to furnish all of the labor, equipment and materials and to perform all of the engineering and construction of the plant. The estimated project cost, including plant construction and associated transmission system upgrades, is $61 million. IPC will take ownership of the plant once it is tested and operational.

In January 2004, the IPUC approved IPC's application for a Certificate of Public Convenience and Necessity, which will allow IPC to place reasonable and prudent capital costs of the Bennett Mountain Power Plant into its Idaho base rates when the plant is operational. IPC made a rate filing with the IPUC on March 2, 2005 to include the investment of approximately $58 million associated with this plant in Idaho retail rates. IPC requested that these costs be included in Idaho retail rates effective June 1, 2005.

Wind Down of Energy Marketing
IDACORP announced in 2002 that IE would wind down its energy marketing operations. In connection with the wind down, certain matters were identified that required resolution with the FERC, the IPUC and the OPUC. These matters were resolved in all three jurisdictions.

Idaho: In an IPUC proceeding that began in May 2001, IPC, the IPUC staff and several interested customer groups worked to determine the appropriate compensation IE should provide to IPC for certain transactions between IPC and IE. The IPUC has issued several orders since then regarding these matters. Order No. 28852 issued on September 28, 2001 covered the time period prior to February 2001. Order No. 29026 covered the time period from March 2001 through March 2002. The IPUC also approved IPC's ongoing hedging and risk management strategies in Order No. 29102 issued on August 28, 2002. This order formalized IPC's agreement to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales. The $5.8 million in benefits related to the FERC settlement were included in the 2003-2004 PCA and credited to Idaho retail customers in accordance with the PCA methodology. The parties to the proceeding executed a settlement agreement providing that an additional $5.5 million be flowed through the PCA mechanism to the Idaho retail customers from April 2003 through December 2005. This agreement was filed with the IPUC on February 17, 2004 and approved on March 15, 2004.

Oregon:Following IPC's settlement with the IPUC on issues related to IPC's past relationship with IE, IPC approached the OPUC to settle the issue of fair compensation to Oregon customers related to the terminated Electricity Supply Management Services Agreement between IPC and IE, as well as any other issues relating to transactions between IPC and IE. On October 4, 2004, IPC filed a petition with the OPUC requesting an accounting order approving a settlement stipulation and authorizing IPC to credit its existing deferral balance of excess power supply costs. In the proposed settlement, IPC agrees to continue the $7,700 monthly credit to customers that began in July 2001 through December 2005, and to reduce the existing excess power supply cost deferral balance by a one time credit of $100,000 on January 1, 2005. The OPUC issued Order No. 04-683 approving this settlement on November 22, 2004.

FMC/Astaris Settlement Agreement
On January 8, 2002, the IPUC initiated an investigation to examine the load-reduction rates contained in the Voluntary Load Reduction Agreement between IPC and FMC/Astaris. This agreement amended the Electric Service Agreement that governed the delivery of electric service to FMC/Astaris' Pocatello, Idaho plant, which ceased operations late in 2001. On June 6, 2002, IPC and FMC/Astaris signed and filed a proposed Stipulation and Settlement Agreement with the IPUC and on June 10, 2002, the IPUC approved the Stipulation and Settlement Agreement in Order No. 29050 which included the following provisions:

The Voluntary Load Reduction payments that IPC would have made to FMC/Astaris through May 2003 were decreased $5 million, reducing IPC's overall payments to $37 million. Approximately 90 percent of this $5 million reduction flowed through the PCA mechanism as a reduction in costs to Idaho retail customers.

FMC/Astaris dismissed, with prejudice, a declaratory judgment action concerning the FMC/Astaris contract that it had previously filed against IPC in the Fourth Judicial District for the State of Idaho.

FMC/Astaris paid IPC approximately $31 million through March 2003 to settle the Electric Service Agreement.

IPC's need to purchase power from the wholesale markets decreased during 2002 due to the ceased operation of FMC/Astaris' Pocatello, Idaho plant and settlement of the above mentioned Electric Service Agreement.

Public Utilities Regulatory Policy Act of 1978
As mandated by the enactment of the Public Utilities Regulatory Policy Act of 1978 (PURPA) and the adoption of avoided costs standards by the IPUC and the OPUC, IPC has entered into contracts for the purchase of energy from a number of private developers. Under these contracts, IPC is required to purchase all of the output from the facilities located inside the IPC service territory. For projects located outside the IPC service territory, IPC is required to purchase the output that IPC has the ability to receive at the facility's requested point of delivery on the IPC system. The costs associated with these Idaho jurisdictional contracts are fully recovered through the PCA. For IPUC jurisdictional projects, projects up to ten MW are eligible for IPUC Published Avoided Costs for up to a 20-year contract term. The Published Avoided Cost is a price established by the IPUC and the OPUC to estimate IPC's cost of developing additional generation resources. For OPUC jurisdictional projects, projects up to one MW are eligible for OPUC Published Avoided Costs for up to a five-year contract term (automatically renewable at the end of five years). The costs associated with these Oregon jurisdictional contracts are recovered through general rate case filings. The Oregon provisions are currently being reviewed in an OPUC proceeding, as discussed below. If a PURPA project does not qualify for the Published Avoided Costs, then IPC is required to negotiate the terms, prices and conditions with the developer of that project. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the IPC system and must be consistent with other similar energy alternatives.

Recent activities, including the extension of the Federal Production Tax Credit and the expansion of the tax credit for eligibility to solar, geothermal and other forms of generation, resolution of IPUC and OPUC PURPA-related hearings and the December 1, 2004 order by the IPUC increasing the Published Avoided Costs, create a favorable climate for PURPA project development during 2005, which may require IPC to enter into additional PURPA agreements. The requirement to enter into additional PURPA agreements may result in IPC acquiring energy at above wholesale market prices, thus increasing costs to its customers. Additionally, it is highly likely that the requirement to enter into additional PURPA agreements will add to IPC's surplus during certain times of the year, potentially during off-peak hours. This could also increase costs to IPC's customers.

Idaho: On June 8, 2004, the IPUC ordered that two separate complaints against IPC be consolidated. The complaints both relate to the contract terms required by IPC for PURPA qualifying facilities. The specific issues to be addressed by the IPUC were: (1) size threshold for standard rates; (2) the distinction between firm and non-firm energy and the appropriateness of performance bands and (3) the ability to terminate contractual obligations should retail deregulation be implemented in Idaho. A public hearing was conducted on September 2, 2004 and September 3, 2004 and post-hearing briefs were filed on September 17, 2004. The IPUC issued Order No. 29632 on November 22, 2004, (1) clarifying the determination of the ten MW size threshold for standard published rates, (2) approving the implementation of performance bands and (3) denying IPC's request for the ability to terminate contractual obligations if retail deregulation were implemented in Idaho. IPC subsequently signed a purchased power agreement with one of the complainants.

Oregon: In January 2004, the OPUC opened a proceeding to review its policies on PURPA matters and issue a comprehensive order to address them. The following issues have been identified for consideration in this proceeding: (1) contract length and price structure; (2) size threshold for standard rates; (3) utility tariff content; (4) avoided cost calculation methods; (5) applicability of Oregon PURPA administrative rules and (6) dispute mediation. A hearing began on October 27, 2004. Briefs on the matter were due January 27, 2005 and oral arguments were held on February 7, 2005. The outcome of these issues is unknown at this time.

Idaho Renewable Energy Legislation
Idaho's interim Legislative Committee on Energy developed a green-power tax incentive bill. The legislation would provide a sales tax exemption on alternative generation equipment used directly in generating electricity using fuel cells, low impact hydro, wind, geothermal resources, cogeneration, sun or landfill gas as the principal source of power. The alternative generation facility would need to be in excess of five MW to be eligible for the sales tax exemption. If enacted, the legislation would expire in July 2011. IPC is unable to predict whether this bill will become law or what effect it would have on its operations.

Integrated Resource Plan
IPC filed its 2004 IRP with the IPUC and the OPUC in August 2004. The 2004 IRP reviews IPC's load and resource situation for the next ten years, analyzes potential supply-side and demand-side options and identifies near-term and long-term actions. The two primary goals of the 2004 IRP are to: (1) identify sufficient resources to reliably serve the growing demand for energy service within IPC's service area throughout the 10-year planning period and (2) ensure that the portfolio of resources selected balances cost, risk and environmental concerns. In addition, there are two secondary goals: (1) to give equal and balanced treatment to both supply-side resources and demand-side measures and (2) to involve the public in the planning process in a meaningful way.

The IRP is filed every two years with both the IPUC and the OPUC. Prior to filing, the IRP requires extensive involvement by IPC, the IPUC Staff and the OPUC Staff, as well as customer, technological and environmental representatives and is the starting point for demonstrating prudence in IPC's resource decisions. Public comments concerning IPC's 2004 IRP were filed with the IPUC by December 3, 2004. On December 23, 2004, IPC filed its response to the filed comments. IPC expects that the commissions will acknowledge the plan in early 2005. The 2004 IRP includes the following elements, which may require significant capital expenditures in the future:

76-MW demand response programs;

48-MW energy efficiency programs;

350-MW wind-powered generation;

100-MW geothermal-powered generation;

48-MW combined heat and power at customer facilities;

88-MW simple-cycle natural gas fired combustion turbine;

62-MW combustion turbine, distributed generation or market purchases; and

500-MW coal-fired generation.

The 2004 IRP identifies specific actions to be taken by IPC prior to the next IRP in 2006. IPC is in the process of implementing these actions. During December of 2004, IPC issued two RFPs associated with an Air Conditioning Cycling Program and on January 13, 2005, IPC issued an RFP for 200 MW of wind-powered generation. During the remainder of 2005, IPC will design demand-side programs in coordination with the Energy Efficiency Advisory Group and both commissions, issue an RFP for a combustion turbine peaking resource, issue an RFP for a 12-MW combined heat and power (co-generation) facility and issue an RFP for 100 MW of geothermal-powered generation.

Advanced Meter Reading
On February 21, 2003, the IPUC issued Order No. 29196, which directed IPC to submit a plan no later than March 20, 2003 to replace its existing meters with advanced meters that are capable of both automated meter reading and time-of-use pricing. On April 15, 2003, the IPUC issued Order No. 29226, which modified and clarified Order No. 29196. The requirement to commence installation in 2003 was removed; however, IPC was expected to implement Advanced Meter Reading as soon as practicable, subject to updated analysis showing Advanced Meter Reading to be cost effective for customers. As ordered by the IPUC, IPC submitted an updated analysis on May 9, 2003. A workshop with the IPUC Staff and other interested parties to discuss the analysis was held on May 19, 2003. The IPUC issued Order No. 29291 on July 14, 2003, providing interested parties the opportunity to submit comments regarding IPC's updated analysis. On October 24, 2003, the IPUC issued Order No. 29362, which directed IPC to collaboratively develop and submit a Phase One Advanced Meter Reading Implementation Plan to replace current residential meters with advanced meters in selected service areas. IPC complied with this order on December 23, 2003 by filing a Phase One Implementation Plan that targeted the Emmett, Idaho and McCall, Idaho areas for 2004 installation and 2005 implementation. Phase One is estimated to cost $6 million and IPC will include these costs in future rate filings. Since April 2004, approximately 24,000 meters have been installed. IPC will submit a report to the IPUC by December 31, 2005, summarizing the Advanced Meter Reading project and associated benefits and costs.

Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric projects on qualified waterways, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size, complexity, and cost of the project. IPC recently received new licenses for five of its middle Snake River projects. The license for IPC's Malad hydroelectric project expired in 2004 and the project will continue to operate under an annual license until the FERC issues a new multi-year license. IPC's hydroelectric project license for the Hells Canyon Complex will expire in 2005 and the Swan Falls project license will expire in 2010. IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years.

Middle Snake River Projects: The middle Snake River projects consist of the Bliss, Upper Salmon Falls, Lower Salmon Falls, Shoshone Falls and CJ Strike projects. On August 4, 2004, IPC received the FERC license orders for each of the middle Snake River projects. Each license is for a 30-year duration effective August 1, 2004. A central component of each license order is a Settlement Agreement between IPC and the U.S. Fish and Wildlife Service regarding five snail species that inhabit the middle Snake River, which are listed as threatened or endangered species under the ESA. As a basis for the settlement, IPC and the U.S. Fish and Wildlife Service agreed that additional studies and analyses are needed in order to accurately assess the effect, if any, that the middle Snake River projects may have on one or more of the listed snail species. The Settlement Agreement provides an operational regime for the five projects that will permit six years of studies and analyses of various project operations on the listed snail species, while providing interim protection of the listed species. After the studies are complete, IPC and the U.S. Fish and Wildlife Service intend to jointly develop a plan that will address project operation and the protection of listed snails for the remainder of the new license terms.

On September 2, 2004, two conservation groups, American Rivers and Idaho Rivers United, filed petitions for rehearing of the orders issuing the licenses for the middle Snake River projects. These petitions ask the FERC to vacate the licensing orders and request a determination from the U.S. Fish and Wildlife Service that the middle Snake River projects jeopardize the listed snail species. On October 4, 2004, the FERC issued an Order Granting Rehearing for Further Consideration to provide additional time to consider the matters raised by the rehearing requests. The order further provided that the FERC anticipated issuing an order on the merits of the rehearing requests on or before November 1, 2004. The FERC has yet to issue an order.

On September 17, 2004, Idaho Rivers United filed a complaint against the U.S. Fish and Wildlife Service in the U.S. District Court for the District of Idaho seeking judicial review of the biological opinion issued by the U.S. Fish and Wildlife Service on May 14, 2004 on the effect of the relicensing of the middle Snake River projects on the listed snail species. The complaint alleges that the U.S. Fish and Wildlife Service action in entering into and relying on the Settlement Agreement as a basis for issuing a no jeopardy determination in the biological opinion was arbitrary, capricious and contrary to law and asks the court to reverse the biological opinion and remand it to the U.S. Fish and Wildlife Service for further consideration. Neither the FERC nor IPC are parties to the action. On November 25, 2004, the U.S. Fish and Wildlife Service filed a motion to dismiss the complaint. On February 4, 2005, the court granted this motion.

Several of the new license articles for the middle Snake River projects require that IPC file additional information with the FERC either upon license issuance or within 30, 45 or 60 days following license issuance. IPC has made these required filings.

Many of the new license articles require IPC to develop comprehensive plans for PM&E measures and submit them to the FERC for approval. The plans are due within six months to one year following license issuance and are required to have detailed costs, schedules and methods for implementing the PM&E measures. IPC is also required to consult with certain parties that participated in the relicensing process including state and federal resource agencies, Native American Indian Tribes and non-governmental organizations (environmental organizations) prior to the completion of development and the filing of some of the plans. The FERC will then review and approve the plans, after which IPC will proceed with implementation of the planned PM&E measures.

Plans to be developed and approved for each license include White Sturgeon Conservation, Recreation Management, Middle Snake River and CJ Strike Wildlife Management Area land management, Minimum and Aesthetic Water Flows, Water Quality Monitoring, Historic Properties Management, Spring Habitat Protection, Fish Stocking and Operational Compliance Monitoring.

Cost estimates for the plans to implement required PM&E measures are $10 million in capital and $2 million in additional annual operation and maintenance expense. Most of the capital expenditures will occur within the first five years of the licenses. Since the plans have not yet been accepted by the FERC, the cost estimates are preliminary. Additionally, cost estimates do not include any PM&E measures that may be required as a result of the Settlement Agreement snail studies and analysis described above.

At December 31, 2004, $10 million of middle Snake River project relicensing and compliance costs were in electric plant in service. The majority of these costs, which were incurred prior to the completion of IPC's recent Idaho general rate case, were approved for recovery in rates. The remaining costs and any future costs will be submitted to regulators for recovery through the rate-making process.

Malad Project: The license for the Malad project expired on August 1, 2004. IPC filed a new license application in July 2002 and will operate the project on an annual license issued under the same terms and conditions of the expired license until the FERC issues a new multi-year license. In September 2004, the FERC issued a Final Environmental Assessment under NEPA for the Malad project concluding that, with appropriate PM&E measures, relicensing the project would not constitute a major federal action significantly affecting the quality of the human environment. The cost estimate of the PM&E measures is less than $1 million annually. In December 2004, the U.S. Fish and Wildlife Service submitted the final, no jeopardy biological opinion to the FERC. The biological opinion is the last piece of information required for the FERC's licensing decision. IPC anticipates a new multi-year license will be issued in 2005.

At December 31, 2004, $3 million of Malad project relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the rate-making process.

Hells Canyon Complex: The most significant ongoing relicensing effort is the Hells Canyon Complex, which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity. IPC developed the license application for the Hells Canyon Complex through a collaborative process involving representatives of state and federal agencies and business, environmental, tribal, customer, local government and local landowner interests. The license application was filed in July 2003 and accepted by the FERC for filing in December of 2003. The current license for the Hells Canyon Complex expires in July 2005. IPC will thereafter operate the project under an annual license issued by the FERC until the new multi-year license is issued. The application includes the continuation of existing, as well as proposed new measures intended to protect, mitigate and enhance fish and wildlife, protect recreational opportunities and preserve other aspects of environmental quality. The costs of these PM&E measures, as estimated in the license application, are approximately $106 million in the first five years of a license and $218 million over the following 25 years, for a total estimated cost of $324 million over a 30-year license. These cost estimates do not include estimated costs of proposed water quality measures included in the license application. These measures are the subject of ongoing state processes under Section 401 of the Clean Water Act. IPC estimates that costs associated with these water quality measures may result in an additional cost of $62 million, for a total estimated cost of $386 million. These estimated costs could increase as a result of the Hells Canyon ESA Consultation/Settlement Process (see discussion below). In response to the filing of the license application in July 2003, various federal and state agencies, Native American Indian Tribes and other participants in the Hells Canyon Complex relicensing process filed initial comments to the license application, some of which contained additional proposed PM&E measures. IPC's preliminary estimate of the potential cost of these additional proposed measures, assuming all of the proposed measures are included as conditions in a final license, which IPC believes is unlikely, is approximately $2.5 billion over up to a 50-year period. This would result in an approximate 28 percent increase to existing base rates. These cost estimates are preliminary as federal, state, tribal and private parties participating in the relicensing proceeding are not required to file their final comments, recommendations, terms, conditions and prescriptions with the FERC until later in the relicensing process. The FERC will then consider these final comments, recommendations, terms, conditions and prescriptions under the Federal Power Act, NEPA and other applicable federal laws, and include those conditions in the final license that the FERC determines are necessary and required to protect, mitigate and enhance those resources affected by the operation and management of the project. As such, the actual costs of the PM&E measures associated with the relicensing of the Hells Canyon Complex will not be known until the new license is issued by the FERC.

At December 31, 2004, $66 million of Hells Canyon Complex relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to a new license, as discussed above, will be submitted to regulators for recovery through the rate-making process.

NEPA Process:
NEPA requires that the FERC independently evaluate the environmental effects of relicensing the Hells Canyon Complex as proposed under the final license application (the proposed action) and also consider reasonable alternatives to the proposed action. Consistent with the requirements of NEPA, the FERC Staff will prepare an environmental impact statement for the Hells Canyon project, which the FERC will use to determine whether, and under what conditions, to issue a new license for the project. The environmental impact statement will describe and evaluate the probable effects, if any, of the proposed action and the other alternatives considered. As part of the NEPA process, the FERC initiated a scoping process to support preparation of the environmental impact statement and help ensure that all pertinent issues are identified and analyzed.

On October 20, 2003, the FERC issued Scoping Document 1 to provide interested parties with information on the relicensing of the project and solicit comments and suggestions for a preliminary list of issues and alternatives that might be addressed in the environmental impact statement. The FERC also held four scoping meetings in the fall and winter of 2003 to offer parties the opportunity for input on the scope of the environmental impact statement. Based upon comments and information received in response to Scoping Document 1, on November 24, 2004, the FERC Staff issued Scoping Document 2, which provides a tentative schedule for the environmental impact statement preparation including the filing of additional information on February 19, 2005; issuance of the Ready for Environmental Analysis Notice in February 2005; and issuance of the draft environmental impact statement in September 2005. Scoping Document 2 notes, however, that the dates for issuance of the Ready for Environmental Analysis Notice and draft environmental impact statement may change as necessary to allow the FERC to consider additional information needed to process the license application. IPC and a number of other parties participating in the Hells Canyon ESA Consultation/Settlement Process (see "Consultation/Settlement Process" discussion below) have requested that the FERC revise the schedule to enable the parties to pursue a comprehensive settlement agreement for the relicensing of the Hells Canyon Complex. IPC is working with the other parties to reach an agreement in principle on the relicensing issues by September 2005, which will inform and focus the FERC in its preparation of the draft environmental impact statement for the NEPA and relicensing process. By order issued on February 8, 2005, the FERC granted IPC's request for a deferral and extended the due date for filing recommendations and conditions until November 2005. The Ready for Environmental Analysis Notice is now scheduled for May 2005 and the draft environmental impact statement is scheduled to be issued in April 2006.

Consultation/Settlement Process:
In an effort to resolve issues associated with the relicensing of the Hells Canyon Complex, IPC has been engaged with the FERC and relevant federal and state agencies on the effects, if any, of the relicensing of the project on species listed as threatened or endangered under the ESA. The National Marine Fisheries Service listed Snake River sockeye as endangered in 1991, Snake River spring, summer and fall chinook as threatened in 1992 and Snake River steelhead as threatened in 1997. In June 1998, the U.S. Fish and Wildlife Service also listed bull trout in the Columbia and Klamath River basins as threatened. Since 1997 IPC has been engaged in informal discussions with the National Marine Fisheries Service and other federal, state and tribal interests on issues associated with the effect of the Hells Canyon Complex operations on ESA-listed species and aquatic resources below the Hells Canyon Complex in the context of the Snake River Basin Adjudication mediation.

With respect to the informal consultations regarding relicensing of the Hells Canyon Complex initiated in the Snake River Basin Adjudication mediation, the FERC has designated IPC as its non-federal representative for purposes of continuing this informal consultation with the National Marine Fisheries Service and the U.S. Fish and Wildlife Service. In July 2004, the FERC requested formal consultation with the National Marine Fisheries Service regarding the effects of interim Hells Canyon Complex operations on ESA-listed species and issued a notice to all interested parties of an ESA consultation meeting on September 9, 2004 to discuss how to proceed with consultation, including how to integrate the ongoing Hells Canyon Complex relicensing settlement discussion into the consultation process.

On September 7, 2004, IPC submitted a letter to the FERC regarding the September 9, 2004 consultation meeting, advising that IPC, the National Marine Fisheries Service and the U.S. Fish and Wildlife Service had explored opportunities to address ESA issues associated with the interim operations and the relicensing of the Hells Canyon Complex through a negotiated settlement process.

At the September 9, 2004 meeting, IPC, the National Marine Fisheries Service and the U.S. Fish and Wildlife Service discussed the proposed settlement process with the FERC Staff and other interested parties in attendance. At the conclusion of that meeting, the parties, with the concurrence of the FERC Staff, expressed an interest in engaging in additional discussions intended to reach agreement on an organizational structure for implementing the Hells Canyon ESA Consultation/Settlement Process.

In late September 2004, IPC, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service and other parties, including the states of Idaho and Oregon, the U.S. Forest Service, several Native American Indian Tribes, American Rivers and Idaho Rivers United, interested in the relicensing of the Hells Canyon Complex met to continue discussions relative to the initiation of the Hells Canyon ESA Consultation/Settlement Process. As a result of that meeting, the parties established a Hells Canyon Complex settlement process in the fall of 2004, which includes a Settlement Working Group, a facilitator and separated FERC Staff. The initial objective of the Settlement Working Group was to address interim operations and anadromous fish species listed under the ESA in an effort to provide agreed upon measures to the FERC by April 2005. The primary objective of the Settlement Working Group, however, is to negotiate and develop a comprehensive settlement agreement to support the relicensing of the project, with a goal of achieving an agreement in principle by September 2005. Parties participating in the Settlement Working Group include IPC, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the U.S. Bureau of Land Management, the U.S. Bureau of Reclamation, the U.S. Department of Agriculture - Forest Service, the State of Oregon, the State of Idaho, the Nez Perce Tribe, the Shoshone-Paiute Tribes, the Shoshone Bannock Tribes, the Burns-Paiute Tribe, American Rivers, Idaho Rivers United, the Idaho Water Users Association, the Payette River Water Users Association, the Pioneer, Settlers and Nampa Meridian irrigation districts, the Committee of Nine, the Idaho Farm Bureau, the Columbia River Inter-Tribal Fish Commission, the Idaho Council on Industry and the Environment, the J. R. Simplot Company and other industrial customers of IPC.

Following expedited negotiations, on January 7, 2005, IPC filed an agreement on interim operations (Interim Agreement) with the FERC. The Interim Agreement has been executed by IPC, American Rivers, Idaho Rivers United, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the U.S. Department of Agriculture - Forest Service, the U.S. Bureau of Land Management, the Oregon Departments of Fish and Wildlife and Environmental Quality, the Nez Perce Tribe, the Shoshone-Bannock Tribes and the Shoshone-Paiute Tribes. The Interim Agreement is intended to address issues relating to operations of the Hells Canyon Complex and ESA-listed species in advance of the issuance of a new license while the parties to the settlement process negotiate a comprehensive settlement agreement. In accordance with the provisions of the Interim Agreement, IPC has agreed to implement certain measures until a new license is issued for the Hells Canyon Complex including monitoring flows above the Hells Canyon Complex to protect existing rights, the leasing and passing of certain U.S. Bureau of Reclamation flow augmentation water, continuing its fall chinook plan from March 1 through May 31 of each year, identifying and monitoring potential stranding sites and continuing to fund its hatchery program. IPC has also agreed to implement certain additional measures on an annual basis, provided that the parties remain engaged in settlement discussions intended to resolve long-term relicensing issues including, subject to certain variables, flow augmentation to aid anadromous fish migration, the shaping of U.S. Bureau of Reclamation storage water, establishing procedures to collect the data and information necessary in the relicensing settlement discussions, identifying, developing and reviewing potential structural modifications regarding dissolved oxygen, total dissolved gas and seasonal water temperatures, providing water quality information to support consultations under Section 401 of the Clean Water Act and sharing information regarding native resident and anadromous fish passage through the Hells Canyon Complex. The signatories agree that the measures in the Interim Agreement are intended to provide reasonable protection for ESA-listed species during the term of the Interim Agreement and also establish a basis for comprehensive settlement discussions to continue. The Settlement Working Group, with the continuing assistance of the facilitator and separated FERC Staff commenced negotiations on the long-term settlement agreement in January 2005. Due to the number and complexity of the issues, it is anticipated that the parties to the settlement process will be required to devote substantial resources and time to the settlement effort in order to achieve the objective of reaching agreement by the fall of 2005.

Additional Information Requests:
The relicensing process permits interveners to submit additional study requests to the FERC. In the Hells Canyon Complex relicensing process, additional study requests were submitted in response to the FERC's Notice of Tendering Application issued on July 31, 2003. The FERC received a total of 123 additional study requests. On May 4, 2004, the FERC Staff responded to the additional study requests issuing to IPC a total of 14 Additional Information Requests.

On June 8, 2004, IPC filed a letter with the FERC objecting to certain of the Additional Information Requests and requesting clarification, modification or extensions of time as to others. IPC objected to some of the Additional Information Requests on the basis that there was no nexus between the Hells Canyon Complex operations and the asserted effects on the resources that were the subject of the Additional Information Requests, submitting that under the Federal Power Act, the FERC's authority to impose terms and conditions in a project license is limited to resources that are affected by the development, operation and management of the project. In the case of several of the Additional Information Requests, IPC contended that the resources at issue were affected by the development and operation of federal hydroelectric projects downstream from the Hells Canyon Complex, not by the Hells Canyon Complex.

IPC objected to other Additional Information Requests relating to various limitations on flow, ramping rates and other operational restrictions intended to benefit recreational navigation below the Hells Canyon Complex on the basis that the Hells Canyon National Recreation Area Act (HCNRAA), enacted by Congress in 1975, grandfathers the Hells Canyon Complex and prohibits flow requirements of any kind on waters of the Snake River below the Hells Canyon Complex.

On June 29, 2004, the FERC Staff denied IPC's objections to the Additional Information Requests, advising that their review of the license application indicates that the Hells Canyon Complex has the potential to affect downstream resources and disagreeing that the HCNRAA places any restriction on requirements that can be included in the license for the Hells Canyon Complex. The FERC Staff also granted extensions of time and provided clarification for certain other Additional Information Requests. On July 29, 2004, IPC filed a Petition for Rehearing with the FERC contesting the FERC Staff's decision denying IPC's objections to the Additional Information Requests.

By letter dated July 30, 2004, IPC requested additional time to complete certain of the Additional Information Requests because relevant studies and model runs could not be completed within the time allowed, and advised the FERC that although IPC had filed a request for rehearing regarding the FERC Staff's denial of IPC's objections, IPC was proceeding with the studies and analysis relevant to the Additional Information Requests pending the FERC's consideration of that request.

On September 13, 2004, IPC filed a request with the FERC requesting that it defer taking action on the pending rehearing request because IPC and other interested parties had commenced the Hells Canyon ESA Consultation/ Settlement Process discussed above. IPC did not request, however, that the FERC defer action on the July 30, 2004 request for additional time. By letter dated October 20, 2004, the FERC Staff denied some of the requests for additional time and provided limited relief as to others.

On June 11, 2004, American Rivers and Idaho Rivers United filed an interlocutory appeal of the FERC Staff's denial of fish passage study requests, one of the Additional Study Requests that the FERC Staff did not adopt in its May 4, 2004 response. IPC filed a response to the interlocutory appeal on June 28, 2004. By order dated July 15, 2004, the FERC dismissed the interlocutory appeal filed by American Rivers and Idaho Rivers United.

Swan Falls Project: The license for the Swan Falls hydroelectric project expires in 2010. IPC is preparing for the first stage of formal consultation for the new license application, which will be filed with the FERC in 2008.

At December 31, 2004, $1 million of Swan Falls project relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to a new license will be submitted to regulators for recovery through the rate-making process.

American Rivers Petition: On May 1, 2003, American Rivers and Idaho Rivers United petitioned the U.S. Court of Appeals for the District of Columbia Circuit requesting that the court issue a Writ of Mandamus compelling the FERC to respond to a petition American Rivers filed with the FERC in 1997 requesting that the FERC initiate formal consultation pursuant to Section 7(a)(2) of the ESA with the National Marine Fisheries Service on the effects of the ongoing operations of IPC's Hells Canyon Complex on four species of Snake River salmon and steelhead trout that are listed as threatened or endangered under the ESA. The case was argued on March 16, 2004. On June 22, 2004, the court issued a decision in the case ordering the FERC to issue a judicially reviewable response to the 1997 petition within 45 days.

On August 6, 2004, the FERC entered an Order on Mandamus and Granting Petition granting the 1997 petition. Consistent with this order, the FERC initiated ESA consultation, setting a meeting on September 9, 2004 with the National Marine Fisheries Service, the U.S. Fish and Wildlife Service and IPC to discuss the interaction of formal consultation on ongoing operations with the anticipated ESA consultation regarding the relicensing of the Hells Canyon Complex, and how any potential settlement discussions could be integrated into the consultation process. The filing of the Interim Agreement with the FERC on January 7, 2005 resolved the issues raised by the court's Order on Mandamus and the FERC's order of August 6, 2004 while the parties to the Hells Canyon ESA Consultation/Settlement Process negotiate a long-term comprehensive agreement for relicensing. See previous discussion in "Hells Canyon Complex."

Regional Transmission Organizations
In December 1999, the FERC, in Order No. 2000, said that all companies with transmission assets must file with the FERC to form RTOs or explain why they cannot do so. Order No. 2000 is a follow up to Order Nos. 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 sought to further facilitate the formation of efficient, competitive wholesale electricity markets.

In July 2002, the FERC issued a notice of proposed rulemaking on Standard Market Design. In this notice, the FERC proposed significant wholesale electricity market design changes in an effort to advance the kinds of markets envisioned in Order Nos. 888 and 2000 but not yet realized. The proposed changes were intended to improve wholesale competition, make more efficient use of transmission systems and generate clear pricing signals for investment in transmission, generation facilities and demand reduction. In April 2003, the FERC issued its "White Paper: Wholesale Market Platform." The White Paper set forth the FERC's then current thinking on issues under consideration in the Standard Market Design proceeding. The FERC committed to consider all comments on the White Paper, as well as pending legislation, prior to the issuance of a Final Rule. To date, the FERC has not issued a Final Rule in its Standard Market Design proceeding.

In October 2000 and March 2002, in response to FERC Order No. 2000, IPC and nine other regional transmission owners filed Stage One and Stage Two plans to form RTO West, an independent entity that would operate the transmission grid in the northwest and British Columbia. In September 2002, the FERC issued an order granting in part RTO West's Stage Two request for a declaratory order, approving the majority of the proposed plan. With further development of detail and some modification, the FERC stated that the proposal "will satisfy not only the Order No. 2000 requirements, but that it can also provide a basic framework for standard market design for the West."

In mid-2003, the RTO West Regional Representatives Group, in an effort to bolster regional support, began a new phase of discussions related to the development of an independent entity to manage the regional transmission system and improve related wholesale electricity markets. These discussions began with a wide-ranging consideration of current transmission problems and opportunities within the region.

During the remainder of 2003, the Regional Representatives Group focused on exploring options and developing a consensus proposal to address the region's transmission problems and opportunities. As a result of this effort, the Regional Representatives Group endorsed a comprehensive Regional Proposal in February 2004. The Regional Proposal provided a framework to better manage the regional transmission system and enhance wholesale power markets through the creation of an independent entity to manage the region's combined transmission services, operate certain aspects of the combined system such as transmission reservation and scheduling, provide monitoring of regional power markets, perform comprehensive transmission system-wide planning and facilitate other aspects of transmission system operation.

In the spring of 2004, the Regional Representatives Group recommended that the name of RTO West be changed to Grid West and set out a plan to guide its creation. The plan contained the following four steps: (1) to establish governance acceptable to the region and form the initial Developmental Corporation under an interim board comprised of participating entity representatives; (2) participating entities commit to two years of funding and transfer control to a newly seated board comprised of members independent of any market participants; (3) the independent board will develop and offer transmission control agreements under which Grid West will perform certain operating functions on the transmission systems of participating entities, and to develop tariffs for new transmission services and (4) Grid West will reorganize from the Developmental Corporation into an Operating Corporation and will commence actual transmission operation. The fourth step will be taken if sufficient entities sign transmission agreements.
In December 2004, the filing entities of RTO West voted unanimously to adopt the new Bylaws and Articles of Incorporation to formally reorganize into the new entity, Grid West (Developmental Corporation). This completed the first of the four major steps toward bringing Grid West into operation. The participating entities included: Avista Corporation, the Bonneville Power Administration, IPC, Nevada Power Company, NorthWestern Energy, PacifiCorp, Portland General Electric Company, Puget Sound Energy, Sierra Pacific Power Company and British Columbia Transmission Corporation.

The first step establishes the Grid West interim board, initiates a search for candidates to be elected as independent trustees on a new five-person independent board and opens a process for interested parties to become members of the new organization. The next step will transfer control to the new independent board. The present schedule calls for reaching the second step in the fall of 2005. The third step is expected in 2006 and the fourth in 2007.

The operational impact of Grid West on IPC presently and for the near future should be minimal. No IPC facilities will be subject to Grid West operation until after operational authority is granted. IPC will have periodic opportunities to decide whether or not to continue participation. At the final step, signing a transmission agreement will be voluntary for IPC.

IPC has spent funds supporting the development of RTO West and Grid West, and expects to continue funding this development as long as it remains a participating utility. Funding of this effort has taken two forms. First, funds have been loaned to RTO West, and subsequently Grid West, for the purpose of meeting its developmental expenses. IPC expects this loan to be repaid by Grid West when it commences operation. Second, IPC has incurred incremental internal costs from participating in the developmental effort, which are mostly related to travel and legal consultation. IPC has accumulated these costs in deferred expense accounts. The total accumulated expense for both types of funding through 2004 was $3 million and is expected to be approximately $1 million for 2005. At this time IPC expects full recovery of the total accumulated expense through rates.

FERC Market-Based Rate Authority
IPC has FERC-approved market-based rate authority, which permits IPC to sell electric energy at market-based rates rather than cost-based rates. The FERC requires periodic reviews of the conditions under which this market-based rate authority is granted to ensure that the rates charged thereunder are just and reasonable. On April 14, 2004, the FERC issued an order commencing a market power analysis of all companies with market-based rate authority; including IPC. In September 2004, IPC filed a revision of its previously approved (October 9, 2003) market power analysis, which it supplemented in September and October. On March 3, 2005, the FERC issued an order accepting IPC's market power analysis. IPC is required to file another market power analysis on or before March 3, 2008.

OTHER MATTERS:

Adopted Accounting Pronouncement
In January 2004, IDACORP and IPC adopted FIN 46R, which addresses consolidation by business enterprises of Variable Interest Entities (VIEs), which have one or more of the following characteristics:

The equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including the equity holders;
The equity investors lack one or more of the following essential characteristics of a controlling financial interest:

The direct or indirect ability to make decisions about the entity's activities through voting rights or similar rights;
The obligation to absorb the expected losses of the entity;
The right to receive the expected residual returns of the entity; and

The equity investors have voting rights that are not proportionate to their economic interests and the activities of the entity involve or are conducted on behalf of an investor with a disproportionately small voting interest.

IDACORP and IPC evaluated their investments, contracts and other potential variable interests that would be subject to the provisions of FIN 46(R), and IDACORP determined that it must consolidate two entities under those provisions. At adoption, total assets and liabilities each increased by $29 million and consisted primarily of property and long-term debt. Cash flows of the newly consolidated entities are included on IDACORP's Consolidated Statement of Cash Flows from the date of adoption. Net income was not affected by the adoption of the interpretation.

New Accounting Pronouncements
SFAS 151: In November 2004, the FASB issued SFAS 151, "Inventory Costs," which clarifies the accounting for certain inventory-related costs. SFAS 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, and is not expected to have a material effect on IDACORP's or IPC's financial statements.

SFAS 153: In December 2004, the FASB issued SFAS 153, "Exchanges of Nonmonetary Assets," which amends existing guidance on accounting for nonmonetary transactions. SFAS 153 is effective for exchanges occurring in fiscal periods beginning after June 15, 2005, and is not expected to have a material effect on IDACORP's or IPC's financial statements.

SFAS 123(R): In December 2004, the FASB issued SFAS 123 (revised 2004), "Share-Based Payments." SFAS 123(R) which revises SFAS 123, "Accounting for Stock-Based Compensation" and supersedes APB Opinion 25, "Accounting for Stock Issued to Employees," and its related implementation guidance. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. SFAS 123(R) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions.

Under the provisions of SFAS 123(R), the fair value of all stock options must be reported as an expense on the financial statements. IDACORP and IPC currently apply the measurement provisions of APB 25 and the disclosure-only provisions of SFAS 123. SFAS 123(R) also changes other measurement, timing and disclosure rules relating to share-based payments.

SFAS 123(R) is effective for most public entities as of the beginning of the first interim or annual reporting period beginning after June 15, 2005. IDACORP and IPC expect to adopt SFAS 123(R) on July 1, 2005, and adoption is expected to decrease IDACORP's and IPC's pre-tax income by approximately $0.6 million in 2005. Stock-based compensation arrangements are discussed in Note 9 to IDACORP's Consolidated Financial Statements.

FSP FAS 106-2: See Note 10 to IDACORP's Consolidated Financial Statements for a discussion of this FSP, which relates to postretirement benefit obligations.

Transmission
Reliability Management System: On April 6, 2004, the U.S. Department of Energy issued its final report regarding the August 14, 2003 electric blackout in the eastern United States. The Western Electricity Coordinating Council, of which IPC is a member, has treated the recommendations as though the outage occurred in the western interconnection. The recommendations were assigned to various committees in the Western Electricity Coordinating Council to create policies and procedures to ensure compliance. IPC is actively participating in many of these forums on a regional and national basis and is closely following the progress in other areas of the country. Following the 1996 Western Blackout, the Western Electricity Coordinating Council (then the Western Systems Coordinating Council) adopted the Reliability Management System, which created mandatory compliance and financial penalties for non-compliance of the reliability criteria. The North American Electric Reliability Council is using the Western Electricity Coordinating Council Reliability Management System program as the model for their new mandatory compliance program. The FERC has also demonstrated a great interest in ensuring compliance with the reliability standards. In 2004, the FERC required all electric utilities, including IPC, to submit a report on vegetation management practices. IPC submitted this report in June 2004. This year, the FERC is requiring electric utilities to complete a survey on training practices. IPC is currently in the process of submitting the training survey. Implementation of the Blackout Report Recommendations and other FERC and North American Electric Reliability Council policies could increase operating costs, but the extent of this effect cannot be determined at this time.

Stage Three Power Emergency: On June 23, 2004, two downed transmission lines in the Hells Canyon area caused IPC to shed 157 MW of electrical load and declare a Stage Three Power Emergency. The Stage Three Power Emergency lasted approximately 90 minutes and IPC employed all of its available generation resources during this time and purchased power from the wholesale markets. IPC shed 100 MW for the entire 90 minutes and an additional 57 MW for 30 of the 90 minutes. This occurrence did not have a significant impact on IPC's financial results.

Inflation
IDACORP and IPC believe that inflation has caused and will continue to cause increases in certain operating expenses and the replacement of assets at higher costs. Inflation affects the cost of labor, products and services required for operations, maintenance costs and capital improvements. While inflation has not had a significant impact on IDACORP's or IPC's operations, costs for products and services are subject to increases. IPC is subject to rate-of-return regulation and the impact of inflation on the level of cost recovery under regulation. Increases in utility costs and expenses due to inflation could have an adverse effect on earnings because of the need to obtain regulatory approval to recover such increased costs and expenses.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to various market risks, including changes in interest rates, changes in commodity prices, credit risk and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates, commodity prices and equity prices that were held at December 31, 2004.

Interest Rate Risk
IDACORP and IPC manage interest expense and short- and long-term liquidity though a combination of fixed rate and variable rate debt. Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highlyrated financial institutions may be used to achieve the desired combination.

Variable Rate Debt: As of December 31, 2004, IDACORP and IPC had $107 million and $73 million, respectively, in floating rate debt, net of temporary investments. Assuming no change in either company's financial structure, if variable interest rates were to average one percentage point higher than the average rate on December 31, 2004, interest rate expense would increase and pre-tax earnings would decrease by approximately $1 million for both IDACORP and IPC.

Fixed Rate Debt: As of December 31, 2004, IDACORP and IPC had outstanding fixed rate debt of $939 million and $865 million, respectively. The fair market value of this debt was $962 million and $886 million, respectively. These instruments are fixed rate, and therefore do not expose IDACORP or IPC to a loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $78 million for IDACORP and $76 million for IPC if interest rates were to decline by one percentage point from their December 31, 2004 levels.

Commodity Price Risk
Utility: IPC's exposure to changes in commodity price is related to its ongoing utility operations producing electricity to meet the demand of its retail electric customers. The weather is a major uncontrollable factor affecting the local and regional demand for electricity and the availability and price of production. The objective of IPC's energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses which may develop.

IPC's exposure to commodity price risk is largely offset by the previously discussed PCA mechanism. IPC has adopted a risk management program designed to reduce exposure to power supply cost-related uncertainty, further mitigating commodity price risk. This program has been reviewed and accepted by the IPUC. IPC's Energy Risk Management Policy (the Policy) describes a collaborative process with customers and regulators via a committee called the Customer Advisory Group (CAG). The Risk Management Committee (RMC), comprised of IPC officers and other senior staff, oversees the risk management program. The RMC is responsible for communicating status of risk management activities to the IDACORP Board of Directors, and to the CAG.

The Policy requires monitoring monthly volumetric electricity position and total dollar (net power supply cost) exposure for the current PCA-year plus the following PCA-year six months in advance of its commencement. The RMC evaluates revised projections for the operating plan and orders risk mitigating action dictated by the limits stated in the Policy. IPC representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be ratified at this time for referral to the Board of Directors. The primary tools for risk mitigation are physical forward power transactions and fueling alternatives for utility-owned generation.

Energy Trading: The sale of IE's forward book of electricity trading contracts to Sempra Energy Trading and the settlement of all gas trading contracts has eliminated the energy commodity price risk.

Credit Risk
Utility: IPC is subject to credit risk based on its activity with market counterparties. IPC is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy or complete financial settlement for market activities. IPC mitigates this exposure by actively establishing credit limits, measuring, monitoring, reporting, using appropriate contractual arrangements and transferring of credit risk through the use of financial guarantees, cash or letters of credit. A current list of acceptable counterparties and credit limits is maintained.

Energy: As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with Sempra Energy Trading, guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The Indemnity Agreement has been accounted for in accordance with FIN 45 and did not have a significant effect on IDACORP's financial statements.

Equity Price Risk
IDACORP and IPC are exposed to price fluctuations in equity markets, primarily through their pension plan assets, a mine reclamation trust fund owned by an equity-method investment of IPC and other equity investments at IPC. A hypothetical ten percent decrease in equity prices would result in an approximate $2 million decrease in the fair value of financial instruments that are classified as available-for-sale securities.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

		PAGE
Consolidated Financial Statements:
IDACORP, Inc.
Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002		59
Consolidated Balance Sheets as of December 31, 2004 and 2003		60-61
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002		62
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2004, 2003
	and 2002	63
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004,
	2003 and 2002	64
Notes to the Consolidated Financial Statements		65-99
Report of Independent Registered Public Accounting Firm		100

Idaho Power Company
Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002		101
Consolidated Balance Sheets as of December 31, 2004 and 2003		102-103
Consolidated Statements of Capitalization as of December 31, 2004 and 2003		104
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002		105
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2004, 2003
	and 2002	106
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004,
	2003 and 2002	106
Notes to the Consolidated Financial Statements		107-110
Report of Independent Registered Public Accounting Firm		111

Supplemental Financial Information and Consolidated Financial Statement Schedules
Supplemental Financial Information (Unaudited)		112

Financial Statement Schedules for the Years Ended December 31, 2004, 2003 and 2002:
Schedule I - Condensed Financial Information of Registrant-IDACORP, Inc.		127-130
Schedule II-Consolidated Valuation and Qualifying Accounts-IDACORP, Inc.		131
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho Power Company		132

IDACORP, Inc.
Consolidated Statements of Income

					Year Ended December 31,
					2004		2003		2002
				(thousands of dollars except for per share amounts)
Operating Revenues:
	Electric utility:
		General business			$	635,835	$	670,969	$	772,035
		Off-system sales				121,148		71,573		55,031
		Other revenues				65,954		40,178		41,974
			Total electric utility revenues			822,937		782,720		869,040
	Energy marketing					(131)		19,916		46,410
	Other					21,685		20,366		13,350
		Total operating revenues				844,491		823,002		928,800

Operating Expenses:
	Electric utility:
		Purchased power				195,642		150,980		142,102
		Fuel expense				103,261		99,898		102,871
		Power cost adjustment				39,184		70,762		170,489
		Other operations and maintenance				255,867		220,983		207,355
		Depreciation				100,855		97,650		93,609
		Taxes other than income taxes				19,090		20,753		19,953
			Total electric utility expenses			713,899		661,026		736,379
	Energy marketing					(2,565)		37,671		72,540
	Other					39,906		40,243		44,241
			Total operating expenses			751,240		738,940		853,160

Operating Income (Loss):
	Electric utility					109,038		121,694		132,661
	Energy marketing					2,434		(17,755)		(26,130)
	Other					(18,221)		(19,877)		(30,891)
		Total operating income				93,251		84,062		75,640

Other Income						25,777		11,544		6,160

Earnings of Unconsolidated Equity-method Investments						1,050		2,407		746

Other Expense						8,726		7,622		3,076

Interest Expense and Preferred Dividends:
	Interest on long-term debt					54,937		58,670		54,147
	Other interest					3,379		2,832		10,211
	Preferred dividends of Idaho Power Company					4,823		3,430		4,587
		Total interest expense and preferred dividends				63,139		64,932		68,945

Income Before Income Taxes						48,213		25,459		10,525

Income Tax Benefit						(24,770)		(21,119)		(51,147)

Net Income					$	72,983	$	46,578	$	61,672

Weighted Average Common Shares Outstanding (000's)						38,361		38,228		37,790

Earnings Per Share of Common Stock (basic and diluted)					$	1.90	$	1.22	$	1.63
Dividends Paid Per Share of Common Stock					$	1.20	$	1.70	$	1.86

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets

			December 31,
			2004		2003
Assets			(thousands of dollars)

Current Assets:
	Cash and cash equivalents		$	23,403	$	75,159
	Receivables:
		Customer		92,258		93,599
		Allowance for uncollectible accounts		(43,108)		(43,210)
		Employee notes		3,523		3,347
		Other		8,806		8,209
	Energy marketing assets			9,203		4,176
	Accrued unbilled revenues			33,832		30,869
	Materials and supplies (at average cost)			28,008		21,351
	Fuel stock (at average cost)			6,539		6,228
	Prepayments			30,035		27,779
	Deferred income taxes			23,407		4,382
	Regulatory assets			5,510		6,269
		Total current assets		221,416		238,158

Investments				223,061		204,474

Property, Plant and Equipment:
	Utility plant in service			3,324,816		3,220,228
	Accumulated provision for depreciation			(1,316,125)		(1,239,604)
		Utility plant in service - net		2,008,691		1,980,624
	Construction work in progress			152,427		96,091
	Utility plant held for future use			2,636		2,438
	Other property, net of accumulated depreciation			45,708		9,166
		Property, plant and equipment - net		2,209,462		2,088,319

Other Assets:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,765		35,624
	Energy marketing assets - long-term			16,635		14,358
	Regulatory assets			433,271		427,760
	Long-term receivables (net of allowance of $2,578)			2,895		3,106
	Employee notes			3,746		4,775
	Other			56,336		57,949
		Total other assets		580,233		575,157

		Total	$	3,234,172	$	3,106,108

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets

				December 31,
				2004		2003
Liabilities and Shareholders' Equity				(thousands of dollars)

Current Liabilities:
	Current maturities of long-term debt			$	78,603	$	67,923
	Notes payable				36,270		93,650
	Accounts payable				79,156		60,916
	Energy marketing liabilities				9,420		4,317
	Taxes accrued				46,318		45,601
	Interest accrued				14,426		13,741
	Other				21,265		25,557
		Total current liabilities			285,458		311,705

Other Liabilities:
	Deferred income taxes				555,774		554,715
	Energy marketing liabilities - long-term				16,635		14,393
	Regulatory liabilities				275,854		258,524
	Other				112,616		104,290
		Total other liabilities			960,879		931,922

Long-Term Debt					979,549		945,834

Commitments and Contingencies

Preferred Stock of Idaho Power Company					-		52,366

Shareholders' Equity:
	Common stock, no par value (shares authorized 120,000,000;
		42,373,758 and 38,341,358 shares issued, respectively)			589,440		472,902
	Retained earnings				424,312		397,167
	Accumulated other comprehensive income (loss)				(888)		(2,630)
	Treasury stock (156,741 and 110,748 shares at cost, respectively)				(4,578)		(3,158)
		Total shareholders' equity			1,008,286		864,281

			Total	$	3,234,172	$	3,106,108

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Cash Flows

					Year Ended December 31,
					2004		2003		2002
					(thousands of dollars)
Operating Activities:
	Net income				$	72,983	$	46,578	$	61,672
	Adjustments to reconcile net income to net cash provided by
		(used in) operating activities:
			Net non-cash loss on legal disputes			-		12,072		-
			Impairment of long-lived asset			9,075		3,498		8,064
			Unrealized losses from energy marketing activities			131		42,517		65,965
			Depreciation and amortization			124,192		129,070		122,831
			Deferred taxes and investment tax credits			(33,912)		(56,174)		(110,491)
			Change in regulatory assets and liabilities			16,788		68,358		164,201
			Gain on sales of non-utility assets			(4,475)		-		-
			Gain on extinguishment of debt			(7,188)		-		-
			Change in:
				Accounts receivables and prepayments		(1,442)		94,529		28,531
				Accounts payable and other accrued liabilities		15,806		(70,342)		(145,868)
				Taxes receivable/accrued		717		(16,797)		98,795
				Other current assets		(4,568)		7,020		5,332
				Other current liabilities		(1,309)		(6,412)		40,614
				Long-term receivable		-		51,394		-
			Other assets			649		(4,527)		6,735
			Other liabilities			7,249		12,065		6,921
			Net cash provided by operating activities			194,696		312,849		353,302
Investing Activities:
	Additions to property, plant and equipment					(199,770)		(149,643)		(137,442)
	Sale of non-utility assets					5,554		494		3,219
	Investments in affordable housing projects					(7,655)		76		(43,939)
	Purchase of available-for-sale securities					(295,356)		(13,689)		(16,530)
	Sale of available-for-sale securities					266,331		14,040		6,815
	Purchase of held-to-maturity securities					(4,927)		(10,547)		(13,671)
	Maturity of held-to-maturity securities					7,730		7,571		9,713
	Other assets					-		(127)		2,009
	Other liabilities					(1,547)		(98)		(737)
			Net cash used in investing activities			(229,640)		(151,923)		(190,563)
Financing Activities:
	Issuance of long-term debt					106,442		255,292		200,000
	Retirement of long-term debt					(79,890)		(230,003)		(89,403)
	Retirement of preferred stock of Idaho Power Company					(52,351)		(860)		(50,994)
	Dividends on common stock					(45,838)		(64,726)		(70,178)
	Decrease in short-term borrowings					(58,250)		(82,550)		(186,300)
	Issuance of common stock					115,690		4,123		15,770
	Acquisition of treasury shares					(1,420)		(799)		(1,206)
	Other assets					(1,145)		(8,404)		(4,011)
	Other liabilities					(50)		(576)		(369)
			Net cash used in financing activities			(16,812)		(128,503)		(186,691)
Net increase (decrease) in cash and cash equivalents						(51,756)		32,423		(23,952)
Cash and cash equivalents at beginning of year						75,159		42,736		66,688
Cash and cash equivalents at end of year					$	23,403	$	75,159	$	42,736

Supplemental Disclosure of Cash Flow Information:
	Cash paid (received) during the year for:
		Income taxes			$	7,742	$	52,882	$	(39,678)
		Interest (net of amount capitalized)			$	55,122	$	58,931	$	62,665

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Shareholders' Equity

										Accumulated
										Other
										Compre-
										hensive
			Common Stock				Retained			Income		Treasury Stock				Total
			Shares	Amount			Earnings			(Loss)		Shares		Amount		Amount
(thousands)
Balance at January 1,
	2002		37,629	$	451,404	$		424,349	$		(3,719)	1	$		(33)	$	872,001

Net income			-		-			61,672			-	-			-		61,672
Common stock dividends
		($1.86 per share)	-		-			(70,178)			-	-			-		(70,178)
Issued			523		15,770			-			-	-			-		15,770
Acquired			-		-			-			-	31			(1,206)		(1,206)
Other			-		1,067			(528)			-	52			(381)		158
Unrealized loss on
	securities (net of tax)		-		-			-			(1,431)	-			-		(1,431)
Minimum pension
	liability adjustment
	(net of tax)		-		-			-			(1,959)	-			-		(1,959)

Balance at December 31,
	2002		38,152		468,241			415,315			(7,109)	84			(1,620)		874,827

Net income			-		-			46,578			-	-			-		46,578
Common stock dividends
		($1.70 per share)	-		-			(64,726)			-	-			-		(64,726)
Issued			189		4,123			-			-	-			-		4,123
Acquired			-		-			-			-	9			(799)		(799)
Other			-		538			-			-	18			(739)		(201)
Unrealized gain on
	securities (net of tax)		-		-			-			4,809	-			-		4,809
Minimum pension
	liability adjustment
	(net of tax)		-		-			-			(330)	-			-		(330)

Balance at December 31,
	2003		38,341		472,902			397,167			(2,630)	111			(3,158)		864,281

Net income			-		-			72,983			-	-			-		72,983
Common stock dividends
		($1.20 per share)	-		-			(45,838)			-	-			-		(45,838)
Issued			4,033		115,690			-			-	-			-		115,690
Acquired			-		-			-			-	46			(1,420)		(1,420)
Other			-		848			-			-	-			-		848
Unrealized gain on
	securities (net of tax)		-		-			-			862	-			-		862
Minimum pension
	liability adjustment
	(net of tax)		-		-			-			880	-			-		880

Balance at December 31,
	2004		42,374	$	589,440	$		424,312	$		(888)	157	$		(4,578)	$	1,008,286

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Comprehensive Income

				Year Ended December 31,
				2004		2003		2002
				(thousands of dollars)

Net Income				$	72,983	$	46,578	$	61,672

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
		Unrealized holding gains (losses) arising during the year,
			net of tax of $1,234, $2,963 and ($1,840)		2,057		4,982		(2,991)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($768), ($111) and $1,007		(1,195)		(173)		1,560
			Net unrealized gains (losses)		862		4,809		(1,431)
	Minimum pension liability adjustment, net of tax of $565,
		($191) and ($1,265)			880		(330)		(1,959)

Total Comprehensive Income				$	74,725	$	51,057	$	58,282

The accompanying notes are an integral part of these statements

IDACORP, Inc.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Nature of Business
IDACORP, Inc. (IDACORP) is a holding company whose principal operating subsidiary is Idaho Power Company (IPC). IDACORP is exempt from registration as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act). In addition, pursuant to Rule 2 of the General Rules and Regulations under the 1935 Act, IDACORP is exempt from all the provisions of the 1935 Act and rules thereunder, except for Section 9(a)(2) of the 1935 Act, which requires IDACORP to seek prior Securities and Exchange Commission approval to acquire securities of another public utility company.

IDACORP's other operating subsidiaries include:

IDACORP Financial Services, Inc. (IFS) - holder of affordable housing and other real estate investments;

IdaTech - - developer of integrated fuel cell systems;

IDACOMM - - provider of telecommunications services and commercial and residential Internet services; and

Ida-West Energy (Ida-West) - operator of independent power projects.

In 2004, IDACORP transferred its ownership of RMC Holdings, Inc. and its subsidiary Velocitus to IDACOMM. In January 2005, RMC Holdings, Inc. and Velocitus were merged into IDACOMM.

Principles of Consolidation
The consolidated financial statements of IDACORP and IPC include the accounts of each company and those variable interest entities (VIEs) for which the companies are the primary beneficiaries. All significant intercompany balances have been eliminated in consolidation. Investments in business entities in which IDACORP and IPC are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method.

The entities that IDACORP and IPC consolidate consist primarily of wholly-owned or controlled subsidiaries. In addition, IDACORP consolidates the following VIEs:

Ida-West participates in Marysville Hydro Partners, a joint venture that owns a small hydroelectric project. Marysville Hydro Partners has approximately $22 million of assets, primarily the hydroelectric plant, and approximately $18 million of intercompany long-term debt, which is eliminated in consolidation.

IFS is a limited partner in Empire Development Company, LLC, an entity that earns historic tax credits through the rehabilitation of the Empire Building in Boise, Idaho. Empire Development Company, LLC has approximately $8 million of assets, primarily real property, and $8 million of long-term debt. This debt is non-recourse to IDACORP, personally guaranteed by the general partner and collateralized by the property.

Through IFS, IDACORP also holds significant variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent. These investments were acquired between 1996 and 2004. IFS's maximum exposure to loss in these developments totaled $109 million at December 31, 2004.

Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions 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. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual results could differ from those estimates.

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 and Wyoming.

Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, Allowance for Funds Used During Construction (AFDC) 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. Repair and maintenance costs associated with planned major maintenance are recorded as these costs are incurred. For utility 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.

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 2.96 percent in 2004, 2.99 percent in 2003 and 3.00 percent in 2002.

Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable as prescribed under Statement of Financial Accounting Standards (SFAS) 144, "Accounting for the Impairment or Disposal of Long-lived Assets." SFAS 144 requires that if the sum of the undiscounted expected future cash flows from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements.

Allowance for Funds Used During Construction
AFDC represents the cost of financing construction projects with borrowed funds and equity funds. 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 a higher rate base and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. IPC's weighted-average monthly AFDC rates for 2004, 2003 and 2002 were 6.9 percent, 8.3 percent and 4.3 percent, respectively. IPC's reductions to interest expense for AFDC were $3 million for both 2004 and 2003 and $2 million for 2002. Other income included $4 million, $3 million and $0.3 million for 2004, 2003 and 2002, respectively.

Revenues
In order to match revenues with associated expenses, IPC accrues unbilled revenues for electric services delivered to customers but not yet billed at month-end. IPC collects franchise fees and similar taxes related to energy consumption. These amounts are recorded as liabilities until paid to the taxing authority. None of these collections are reported on the income statement as revenue or expense.

IE reports marketing and trading revenues and expenses on a net basis, using the mark-to-market method of accounting. Energy marketing revenues include sales of electricity and gas netted against purchases, whether physically settled or net settled. Additionally, all financial transactions and unrealized income are presented on a net basis in operating revenues. Other cost of revenue items such as transmission and broker fees are reported as operating expenses.

Power Cost Adjustment
IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the true-up of the true-up for the prior years' unrecovered portion, is then included in the calculation of the next year's PCA.

Income Taxes
The liability method of computing deferred taxes is used on all temporary differences between the book and tax basis of assets and liabilities and deferred tax assets and liabilities are adjusted for enacted changes in tax laws or rates. Consistent with orders and directives of the Idaho Public Utilities 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 for more information.

The State of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits 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
The computation of diluted earnings per share (EPS) differs from basic EPS only due to the inclusion of potentially dilutive shares related to stock-based compensation awards.

The diluted EPS computation excluded 818,600 common stock options in 2004, 721,800 in 2003 and 849,000 in 2002, because the options' exercise prices were greater than the average market price of the common stock during those years. In total, 1,211,800 options were outstanding at December 31, 2004, with expiration dates between 2010 and 2014.

Stock-Based Compensation
Stock-based employee compensation is accounted for under the recognition and measurement principles of Accounting Principles Board (APB) Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Grants of performance shares are reflected in net income based on the market value at the award date, or the period-end price for shares not yet vested. Grants of restricted stock are reflected in net income based on the market value on the grant date. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. IDACORP and IPC have adopted the disclosure only provision of SFAS 123, "Accounting for Stock-Based Compensation."

The following table illustrates the effect on net income and EPS if the fair value recognition provisions of SFAS 123 had been applied to stock-based employee compensation:

			2004		2003		2002
			(thousands of dollars except for per share amounts)

Net income, as reported			$	72,983	$	46,578	$	61,672
Add: Stock-based employee compensation expense
	included in reported net income, net of related
	tax effects			399		(76)		(9)
Deduct: Total stock-based employee compensation
	expense determined under fair value based
	method for all awards, net of related tax effects			1,169		1,169		1,958
		Pro forma net income	$	72,213	$	45,333	$	59,705
EPS of common stock:
	Basic and diluted - as reported		$	1.90	$	1.22	$	1.63
	Basic and diluted - pro forma			1.88		1.19		1.58

For purposes of these pro forma calculations, the estimated fair value of the options, restricted stock and performance shares are amortized to expense over the vesting period. The fair value of the restricted stock and performance shares is the market price of the stock on the date of grant. The fair value of an option award is estimated at the date of grant using a binomial option-pricing model. Expense related to forfeited options is reversed in the period in which the forfeit occurs. For more information see Note 9.

Cash and Cash Equivalents
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.

Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in the electricity market. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of electricity and natural gas as well as to optimize energy marketing portfolios. The accounting for derivative financial instruments that are used to manage risk is in accordance with the concepts established by SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.

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 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 rate-making 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 regulatory assets on the balance sheet and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers.

Comprehensive Income
Comprehensive income includes net income, unrealized holding gains and losses on marketable securities, IPC's proportionate share of unrealized holding gains and 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. The following table presents IDACORP's and IPC's accumulated other comprehensive loss balance at December 31:

		2004		2003
		(thousands of dollars)
Unrealized holding gains on securities		$	4,538	$	3,676
Minimum pension liability adjustment			(5,426)		(6,306)
	Total	$	(888)	$	(2,630)

Goodwill
On January 1, 2002, SFAS 142, "Goodwill and Other Intangible Assets," was adopted. SFAS 142 requires that goodwill and certain intangible assets no longer be amortized, but instead be tested for impairment at least annually.

The annual impairment tests have been completed on IDACORP's $14 million goodwill balance, which is related to the acquisitions of IdaTech and Velocitus. Velocitus' test was performed as of June 30, 2004 and IdaTech's as of September 30, 2004. No impairment was noted in these tests. Goodwill impairment tests will continue to be performed at least annually, and more frequently if circumstances indicate a possible impairment. Goodwill is included in other assets on IDACORP's Consolidated Balance Sheets.

Adopted Accounting Pronouncement
In January 2004, IDACORP and IPC adopted Financial Accounting Standards Board (FASB) Interpretation (FIN) 46R, "Consolidation of Variable Interest Entities - an interpretation of ARB No. 51," which addresses consolidation by business enterprises of VIEs, which have one or more of the following characteristics:

The equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by any parties, including the equity holders;
The equity investors lack one or more of the following essential characteristics of a controlling financial interest:

The direct or indirect ability to make decisions about the entity's activities through voting rights or similar rights;
The obligation to absorb the expected losses of the entity;
The right to receive the expected residual returns of the entity; and

The equity investors have voting rights that are not proportionate to their economic interests, and the activities of the entity involve or are conducted on behalf of an investor with a disproportionately small voting interest.

IDACORP and IPC evaluated their investments, contracts and other potential variable interests that would be subject to the provisions of FIN 46R, and IDACORP determined that it must consolidate two entities under those provisions. At adoption, total assets and liabilities each increased by $29 million and consisted primarily of property and long-term debt. Cash flows of the newly consolidated entities are included on IDACORP's Consolidated Statement of Cash Flows from the date of adoption. Net income was not affected by the adoption of the interpretation.

SFAS 123(R): In December 2004, the FASB issued SFAS 123 (revised 2004), "Share-Based Payments," which revises SFAS 123 and supersedes APB 25 and its related implementation guidance. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity's equity instruments or that may be settled by the issuance of those equity instruments. SFAS 123(R) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions.

FSP FAS 106-2: See Note 10 for a discussion of this FSP, which relates to postretirement benefit obligations.

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 2004 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:
A reconciliation between the statutory federal income tax rate and the effective rate is as follows:

		2004		2003		2002
		(thousands of dollars)
Federal income tax expense at 35% statutory rate		$	16,875	$	8,911	$	3,684
Change in taxes resulting from:
	AFDC		(2,400)		(2,343)		(948)
	Investment tax credits		(3,295)		(3,397)		(3,179)
	Repair allowance		(2,450)		(2,450)		(2,450)
	Removal costs		(1,244)		(1,101)		(815)
	Pension accrual		1,237		2,456		(26)
	Capitalized overhead costs		(3,658)		(3,658)		(3,500)
	Regulatory tax liability		(16,457)		-		-
	Tax accounting method change		-		-		(31,162)
	Settlement of prior years tax returns		(1,876)		(8,911)		(2,971)
	State income taxes, net of federal benefit		2,923		1,357		514
	Depreciation		4,350		10,237		8,940
	Affordable housing and historic tax credits		(21,717)		(20,345)		(20,863)
	Preferred dividends of IPC		1,688		1,200		1,606
	Other, net		1,254		(3,075)		23
Total income tax benefit		$	(24,770)	$	(21,119)	$	(51,147)
	Effective tax rate		(51.4%)		(83.0%)		(486.0%)

The items comprising income tax expense are as follows:

			2004		2003		2002
			(thousands of dollars)
Income taxes currently payable:
	Federal		$	6,087	$	26,356	$	46,541
	State			3,055		8,699		12,803
		Total		9,142		35,055		59,344
Income taxes deferred:
	Federal			(30,646)		(44,938)		(95,185)
	State			(2,313)		(11,465)		(14,850)
		Total		(32,959)		(56,403)		(110,035)
Investment tax credits:
	Deferred			2,342		3,627		2,722
	Restored			(3,295)		(3,398)		(3,178)
		Total		(953)		229		(456)
Total income tax benefit			$	(24,770)	$	(21,119)	$	(51,147)

The components of IDACORP's net deferred tax liability are as follows:

			2004		2003
			(thousands of dollars)
Deferred tax assets:
	Regulatory liabilities		$	40,447	$	41,024
	Advances for construction			5,357		4,162
	Deferred compensation			14,001		13,608
	Tax credits			28,211		10,021
	Other			15,737		13,829
		Total		103,753		82,644
Deferred tax liabilities:
	Property, plant and equipment			241,324		238,602
	Regulatory assets			344,220		330,833
	Conservation programs			6,972		8,310
	PCA			20,516		27,529
	Partnership investments			19,975		16,728
	Other			3,113		10,975
		Total		636,120		632,977
Net deferred tax liabilities			$	532,367	$	550,333

Status of Audit Proceedings
The Internal Revenue Service has examined federal income tax returns for years through 2000 and all issues have been settled. Applicable state tax return amendments were completed in 2004 and settled. Finalization of these examinations resulted in deficiencies that were less than previously accrued, enabling IDACORP to decrease income tax expense by $2 million in 2004, $9 million in 2003 and $3 million in 2002.

Regulatory Settlement
In Settlement No. 2, as more fully discussed in Note 13, IPC and the IPUC finalized an income tax issue from IPC's 2003 Idaho general rate case. The issue concerned the regulatory accounting treatment for the capitalized overhead cost tax method IPC adopted in the 2001 IDACORP federal income tax return. As a result of Settlement No. 2, a $16 million regulatory tax liability was reversed to income tax expense in the third quarter of 2004.

Tax Credits
As of December 31, 2004, IDACORP had $22 million of general business credit carryforward for federal income tax purposes. Additionally, IDACORP had $6 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires in 2024 and the Idaho investment tax credit expires from 2016 to 2018. Management believes the utilization of these credits is more likely than not.

Tax Accounting Method Change
During the third quarter of 2002, IDACORP filed its 2001 federal income tax return and adopted a change to IPC's tax accounting method for capitalized overhead costs. The former method allocated such costs primarily to the construction of plant, while the new method allocates such costs to both construction of plant and the production of electricity.

The effect of the tax accounting method change was recorded as a decrease to income tax expense for the year ended December 31, 2002 of $35 million, of which $31 million was attributable to 2001 and prior tax years, and $4 million was attributable to the 2002 tax year. The decrease to tax expense was a result of deductions on the applicable tax returns of costs that were capitalized into fixed assets for financial reporting purposes. Deferred income tax expense was not provided because the prescribed regulatory accounting method does not allow for inclusion of such deferred tax expense in current rates. Regulated enterprises are required to recognize such adjustments as regulatory assets if it is probable that such amounts will be recovered from customers in future rates.

American Jobs Creation Act of 2004: In October 2004, the president signed into law the American Jobs Creation Act of 2004 (the Act), which may have tax implications for IDACORP and IPC. One provision of the Act with potential implications for the companies relates to manufacturing tax incentives for the production of electricity beginning in 2005. Taxpayers will be able to deduct a percentage (three percent in 2005 and 2006, six percent in 2007 through 2009 and nine percent in 2010 and thereafter) of the lesser of their qualified production activities income or their taxable income. Management is currently reviewing this and other aspects of the Act to determine the impact on the companies.

3. COMMON STOCK:

Shares of common stock were reserved for the following purposes at December 31:

		2004	2003
Dividend reinvestment and stock purchase plan and employee savings plan		6,062,314	6,062,314
Restricted stock plan		314,114	314,114
Long-term incentive and compensation plan		2,042,600	2,050,000
	Total shares reserved	8,419,028	8,426,428

In 2001, IDACORP 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, IDACORP acquired 156,300 shares at a cost of $7 million for the same purpose. As of December 31, 2004, IDACORP had issued 242,371 shares to the shareholders of the acquired entity including 1,167 shares in 2004. Of the remaining acquired shares, 71,755 had been issued, primarily in connection with IDACORP's Dividend Reinvestment Program (DRIP).

IDACORP has issued shares of common stock for its DRIP and Employee Savings Plan, although no shares were issued for the DRIP or the Employee Savings Plan in 2004. In 2003, IDACORP issued 122,990 shares for the DRIP and 65,932 shares for the Employee Savings Plan. For additional information related to the Employee Savings Plan, see Note 10.

In 2004, IDACORP purchased 45,988 shares for its 1994 Restricted Stock Plan and issued 7,400 shares pursuant to the exercise of stock options granted under the 2000 Long-Term Incentive and Compensation Plan.

On December 15, 2004, IDACORP issued 4,025,000 shares of its common stock in a public offering for net proceeds of $116 million.

Shareholder Rights Plan
IDACORP 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 IDACORP. Under the Plan, IDACORP declared a distribution of one Preferred Share Purchase Right (Right) for each of its 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 IDACORP's voting stock or commences a tender offer that would result in ownership of 20 percent or more of such stock. IDACORP 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 IDACORP) or other assets at any time prior to the close of business on the tenth day after acquisition by an Acquiring Person of a 20 percent or greater position.

Additionally, the IDACORP Board of Directors 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, IDACORP 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 their holders any voting or other rights as shareholders. 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.

Dividend Restrictions
IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. On September 20, 2004, IPC redeemed all of its outstanding preferred stock. Also, certain provisions of credit facilities contain restrictions on the ratio of debt to total capitalization.

IPC must obtain the approval of the Oregon Public Utility Commission (OPUC) before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

4. PREFERRED STOCK OF IDAHO POWER COMPANY:

The number of shares of IPC preferred stock outstanding at December 31 were as follows:

			Shares Outstanding at
			December 31,
			2004	2003
Preferred stock:
Cumulative, $100 par value:
	4% preferred stock (authorized 215,000 shares)		-	123,664
	Serial preferred stock, 7.68% Series (authorized 150,000 shares)		-	150,000
Serial preferred stock, cumulative, without par value, total of 3,000,000 shares authorized:
	7.07% Series, $100 stated value (authorized 250,000 shares)		-	250,000
		Total	-	523,664

On September 20, 2004, IPC redeemed all of its outstanding preferred stock for $54 million using proceeds from the issuance of first mortgage bonds. This amount includes $2 million of premium that was recorded as preferred dividends on the Consolidated Statements of Income. The redemption price was $104 per share for the 122,989 shares of 4% preferred stock, $102.97 per share for the 150,000 shares of 7.68% preferred stock and $103.18 per share for the 250,000 shares of 7.07% preferred stock, plus accumulated and unpaid dividends.

During 2003 IPC reacquired and retired 10,263 shares of 4% preferred stock.

5. LONG-TERM DEBT:

The following table summarizes long-term debt at December 31:

					2004		2003
					(thousands of dollars)
First mortgage bonds:
	8		%	Series due 2004	$	-	$	50,000
	5.83		%	Series due 2005		60,000		60,000
	7.38		%	Series due 2007		80,000		80,000
	7.20		%	Series due 2009		80,000		80,000
	6.60		%	Series due 2011		120,000		120,000
	4.75		%	Series due 2012		100,000		100,000
	4.25		%	Series due 2013		70,000		70,000
	6		%	Series due 2032		100,000		100,000
	5.50		%	Series due 2033		70,000		70,000
	5.50		%	Series due 2034		50,000		-
	5.875		%	Series due 2034		55,000		-
		Total first mortgage bonds				785,000		730,000
Pollution control revenue bonds:
	Variable Auction Rate Series 2003 due 2024 (a)					49,800		49,800

6.05

Series 1996A due 2026

68,100

	Variable Rate Series 1996B due 2026			24,200		24,200
	Variable Rate Series 1996C due 2026			24,000		24,000
	Variable Rate Series 2000 due 2027			4,360		4,360
		Total pollution control revenue bonds		170,460		170,460
REA notes				-		1,105
American Falls bond guarantee				19,885		19,885
Milner Dam note guarantee				11,700		11,700
Unamortized premium/discount - net				(3,135)		(2,205)
Debt related to investments in affordable housing				66,310		82,715
Other subsidiary debt				7,932		97
	Total			1,058,152		1,013,757
Current maturities of long-term debt				(78,603)		(67,923)
		Total long-term debt	$	979,549	$	945,834
(a) Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total of first mortgage
bonds outstanding at December 31, 2004 to $834.8 million.

At December 31, 2004, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):

	2005		2006		2007		2008		2009		Thereafter

IPC	$	60,000	$	-	$	81,064	$	1,064	$	81,064	$	760,718
Other subsidiary debt		18,603		15,985		13,891		10,392		5,656		9,715
Total	$	78,603	$	15,985	$	94,955	$	11,456	$	86,720	$	770,433

IDACORP currently has two shelf registration statements totaling $679 million that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock.

On October 22, 2003, Humboldt County, Nevada issued, for the benefit of IPC, $49.8 million Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 2003 due December 1, 2024. IPC borrowed the proceeds from the issuance pursuant to a Loan Agreement with Humboldt County and is responsible for payment of principal, premium, if any, and interest on the bonds. The bonds are secured, as to principal and interest, by IPC first mortgage bonds and as to principal and interest when due, by an insurance policy issued by Ambac Assurance Corporation. The bonds were issued in an auction rate mode under which the interest rate is reset every 35 days. The initial auction rate was set at 0.95 percent. At December 31, 2004, the auction rate was 1.85 percent. Proceeds from this issuance together with other funds provided by IPC were used to redeem the outstanding $49.8 million Pollution Control Revenue Bonds (Idaho Power Company Project) 8.3% Series 1984 due 2014, on December 1, 2003, at 103 percent.

On March 14, 2003, IPC filed a $300 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes), unsecured debt and preferred stock. On May 8, 2003, IPC issued $140 million of secured medium-term notes in two series: $70 million First Mortgage Bonds 4.25% Series due 2013 and $70 million First Mortgage Bonds 5.50% Series due 2033. Proceeds were used to pay down IPC short-term borrowings incurred from the payment at maturity of $80 million First Mortgage Bonds 6.40% Series due 2003 and the early redemption of $80 million First Mortgage Bonds 7.50% Series due 2023, on May 1, 2003. On March 26, 2004, IPC issued $50 million First Mortgage Bonds 5.50% Series due 2034. Proceeds were used to reduce short-term borrowings and replace short-term investments, which were used on March 15, 2004 to pay at maturity the $50 million First Mortgage Bonds 8% Series due 2004. On August 16, 2004, IPC issued $55 million First Mortgage Bonds 5.875% Series due 2034. On September 20, 2004, the proceeds of this issuance were used to redeem all of IPC's outstanding preferred stock. At December 31, 2004, $55 million remained available to be issued on this shelf registration statement.

On January 19, 2005, IPC filed a $245 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes) and debt securities.

On August 17, 2004, IPC redeemed all $1 million of its Rural Electrification Administration notes.

At December 31, 2004 and 2003, the overall effective cost of all of IPC's outstanding debt was 5.69 percent and 5.71 percent, respectively.

The amount of first mortgage bonds issuable by IPC is limited to a maximum of $1.1 billion and by property, earnings and other provisions of the mortgage and supplemental indentures thereto. IPC may amend the indenture and increase this amount without consent of the holders of the first mortgage bonds. Substantially all of the electric utility plant is subject to the lien of the mortgage. As of December 31, 2004, IPC could issue under the mortgage approximately $699 million of additional first mortgage bonds based on unfunded property additions and $392 million of additional first mortgage bonds based on retired first mortgage bonds. At December 31, 2004, unfunded property additions, which consist of electric property, were approximately $1.1 billion.

At December 31, 2004, IFS had $66 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.59 percent due between 2005 and 2010. The investments in affordable housing developments that collateralize this debt had a net book value of $110 million at December 31, 2004. IFS's $17 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $11 million Series 2003-2 tax credit note and other outstanding debt are recourse only to IFS.

In June 2004, Ida-West purchased from a third party $18 million of debt issued by Marysville Hydro Partners, a 50-percent-owned, consolidated joint venture, for $11 million. This debt, previously consolidated under the provisions of FIN 46R, is now eliminated in consolidation. Ida-West borrowed $6 million from IDACORP for this transaction.

As a result of IDACORP's adoption of FIN 46R in January 2004, other subsidiary debt increased $8 million from December 31, 2003. This debt is non-recourse to IDACORP, personally guaranteed by the general partner and collateralized by property.

6. FAIR VALUE OF FINANCIAL INSTRUMENTS:

The estimated fair value of IDACORP's financial instruments has been determined 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.

	December 31, 2004				December 31, 2003
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
Assets:
Notes receivable	$	10,376	$	10,245	$	11,576	$	11,590
Investments		67,319		67,479		39,405		39,659

Liabilities:
Long-term debt	$	1,061,287	$	1,084,090	$	1,015,962	$	1,043,116

7. NOTES PAYABLE:

IDACORP has a $150 million credit facility that expires on March 16, 2007. Under this facility IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's Investors Service (Moody's) and Standard & Poor's Ratings Services (S&P). Commercial paper may be issued up to the amounts supported by the bank credit facilities. Commercial paper outstanding was $35 million and $94 million at December 31, 2004 and 2003, respectively.

At December 31, 2004, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. IPC has a $200 million credit facility that expires on March 16, 2007. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. IPC's commercial paper may be issued up to the amounts supported by the bank credit facilities. There was no commercial paper outstanding at December 31, 2004 or 2003.

Balances and interest rates of IDACORP's short-term borrowings were as follows at December 31 (in thousands of dollars):

	2004				2003
			Effective				Effective
	Amount		Interest Rate		Amount		Interest Rate
Commercial Paper	$	35,400		2.52%	$	93,650		1.21%
Notes Payable		870		3.24%		-		-
Balance	$	36,270			$	93,650

8. COMMITMENTS AND CONTINGENCIES:

As of December 31, 2004, IPC had agreements to purchase energy from 71 cogeneration and small power production (CSPP) facilities with contracts ranging from one to 30 years. Under these contracts IPC is required to purchase all of the output from the facilities inside the IPC service territory. For projects outside the IPC service territory, IPC is required to purchase the output which IPC has the ability to receive at the facility's requested point of delivery on the IPC system. IPC purchased 677,868 megawatt-hours (MWh) at a cost of $40 million in 2004 and 654,131 MWh at a cost of $38 million in 2003.

IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at December 31, 2004. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs and expects that the fund will be sufficient to cover all such costs. Because of the existence of the fund, the estimated fair value of this guarantee is minimal.

In August 2003, IE sold its forward book of electricity trading contracts to Sempra Energy Trading. As part of the sale, IE entered into an Indemnity Agreement with Sempra Energy Trading guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The indemnity agreement has been accounted for in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and did not have a significant effect on IDACORP's financial statements.

From time to time IDACORP and IPC are a party to various legal claims, actions and complaints in addition to those discussed below. IDACORP and IPC believe that they have meritorious defenses to all lawsuits and legal proceedings. Although they will vigorously defend against them, they are unable to predict with certainty whether or not they will ultimately be successful. However, based on the companies' evaluation, they believe that the resolution of these matters will not have a material adverse effect on IDACORP's or IPC's consolidated financial positions, results of operations or cash flows.

Legal Proceedings
Alves Dairy: On May 18, 2004, Herculano and Frances Alves, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs seek unspecified monetary damages for negligence and nuisance (allegedly allowing electrical current to flow in the earth, injuring the plaintiffs' right to use and enjoy their property and adversely affecting their dairy herd). On July 16, 2004, IPC filed an answer to Mr. and Mrs. Alves' complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The parties have begun discovery in the case. No trial date has been scheduled. On December 14, 2004, IPC filed a motion with the District Court for permission to appeal the court's denial of IPC's Motion to Disqualify the trial judge, for cause. The District Court granted the motion for permissive appeal. On February 16, 2005, IPC filed a motion for permissive appeal with the Idaho Supreme Court. If granted, the Supreme Court will determine whether the District Court properly refused to disqualify the trial judge for cause.

Public Utility District No. 1 of Grays Harbor County, Washington: On October 15, 2002, Public Utility District No. 1 of Grays Harbor County, Washington (Grays Harbor) filed a lawsuit in the Superior Court of the State of Washington, for the County of Grays Harbor, against IDACORP, IPC and IE. On March 9, 2001, Grays Harbor entered into a 20 Megawatt (MW) purchase transaction with IPC for the purchase of electric power from October 1, 2001 through March 31, 2002, at a rate of $249 per MWh. In June 2001, with the consent of Grays Harbor, IPC assigned all of its rights and obligations under the contract to IE. In its lawsuit, Grays Harbor alleged that the assignment was void and unenforceable, and sought restitution from IE and IDACORP, or in the alternative, Grays Harbor alleged that the contract should be rescinded or reformed. Grays Harbor sought as damages an amount equal to the difference between $249 per MWh and the "fair value" of electric power delivered by IE during the period October 1, 2001 through March 31, 2002.

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit. The appeal has been fully briefed, however no date has yet been set for oral argument. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Wah Chang: On May 5, 2004, Wah Chang, a division of TDY Industries, Inc., filed two lawsuits in the U.S. District Court for the District of Oregon against numerous defendants. IDACORP, IE and IPC are named as defendants in one of the lawsuits. The complaints allege violations of federal antitrust laws, violations of the Racketeer Influenced and Corrupt Organizations Act, violations of Oregon antitrust laws and wrongful interference with contracts. Wah Chang's complaint is based on allegations relating to the western energy situation. These allegations include bid rigging, falsely creating congestion and misrepresenting the source and destination of energy. The plaintiff seeks compensatory damages of $30 million and treble damages.

City of Tacoma: On June 7, 2004, the City of Tacoma, Washington filed a lawsuit in the U.S. District Court for the Western District of Washington at Tacoma against numerous defendants including IDACORP, IE and IPC. The City of Tacoma's complaint alleges violations of the Sherman Antitrust Act. The claimed antitrust violations are based on allegations of energy market manipulation, false load scheduling and bid rigging and misrepresentation or withholding of energy supply. The plaintiff seeks compensatory damages of not less than $175 million.

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. IDACORP, IE and IPC have not answered the complaint, as a response is not yet required. The companies, along with the other defendants, filed a motion to dismiss the complaint which was taken under submission by the court, without oral argument. By order dated February 11, 2005, the court granted the companies' and other defendants' motion to dismiss. The companies intend to vigorously defend their position in this proceeding and believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

State of California Attorney General: The California Attorney General filed the complaint in this case in the California Superior Court in San Francisco on May 30, 2002. This is one of thirteen virtually identical cases brought by the Attorney General against various sellers of power in the California market, seeking civil penalties pursuant to California's Unfair Competition Law, Business and Professions Code Section 17200. Section 17200 defines unfair competition as any "unlawful, unfair or fraudulent business act or practice . . . ." The Attorney General alleges that IPC engaged in unlawful conduct by violating the Federal Power Act in two respects: (1) by failing to file its rates with the FERC and (2) charging unjust and unreasonable rates. The Attorney General alleged that there were "thousands of . . . sales or purchases" for which IPC failed to file its rates, and that IPC charged unjust and unreasonable rates on "thousands of occasions." Pursuant to Business and Professions Code Section 17206, the Attorney General seeks civil penalties of up to $2,500 for each alleged violation. On June 25, 2002, IPC removed the action to federal court, and on July 25, 2002, the Attorney General filed a motion to remand back to state court. On March 25, 2003, the court denied the Attorney General's motion to remand and granted IPC's motion to dismiss the case based upon grounds of federal preemption and the filed-rate doctrine. On March 28, 2003, the Attorney General filed a Notice of Appeal to the U.S. Court of Appeals for the Ninth Circuit, appealing the court's decision granting IPC's motion to dismiss. Briefing on the appeal was completed in October 2003. On October 12, 2004, the Ninth Circuit unanimously affirmed the order denying remand and dismissing all of the Attorney General's actions, including the action against IPC. The Attorney General did not file a petition for rehearing in the Ninth Circuit and has not sought review from the U.S. Supreme Court. As a result, the Ninth Circuit's October 12, 2004 decision is final.

Wholesale Electricity Antitrust Cases I & II: These cross-actions against IE and IPC emerged from multiple California state court proceedings first initiated in late 2000 against various power generators/marketers by various California municipalities and citizens. Suit was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay, L.L.C. and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C. and Duke Energy Oakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim that Reliant, Duke and certain others (not including IE or IPC) colluded to influence the price of electricity in the California wholesale electricity market. Plaintiffs asserted various claims that the defendants violated the California Antitrust Law (the Cartwright Act), Business and Professions Code Section 16720 and California's Unfair Competition Law, Business and Professions Code Section 17200. Among the acts complained of are bid rigging, information exchanges, withholding of power and other wrongful acts. These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than a year after the initial complaints were filed, two of the original defendants, Duke and Reliant, filed separate cross-complaints against IPC and IE, and approximately 30 other cross-defendants. Duke and Reliant's cross-complaints seek indemnity from IPC, IE and the other cross-defendants for an unspecified share of any amounts they must pay in the underlying suits because, they allege, other market participants like IPC and IE engaged in the same conduct at issue in the Plaintiffs' Master Complaint. Duke and Reliant also seek declaratory relief as to the respective liability and conduct of each of the cross-defendants in the actions alleged in the Plaintiffs' Master Complaint. Reliant also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200. As a buyer of electricity in California, Reliant seeks the same relief from the cross-defendants, including IPC, as that sought by plaintiffs in the Plaintiffs' Master Complaint as to any power Reliant purchased through the California markets.

Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court. IPC and IE, together with numerous other defendants added by the cross-complaints, have moved to dismiss these claims, and those motions were heard in September 2002, together with motions to remand the case back to state court filed by the original plaintiffs. On December 13, 2002, the U.S. District Court granted Plaintiffs' Motion to Remand to state court, but did not issue a ruling on IPC and IE's motion to dismiss. The U.S. Court of Appeals for the Ninth Circuit granted certain Defendants and Cross-Defendants' Motions to Stay the Remand Order while they appeal the order. The briefing on the appeal was completed in December 2003. On December 8, 2004, the Ninth Circuit issued its opinion in California v. NRG Energy, Inc., et al., which affirmed the district court's remand of these cases to state court and dismissed certain federal government defendants due to their sovereign immunity from suit. Cross-defendant, Powerex Corp., sought Rehearing En Banc at the Ninth Circuit arguing that while it is a government entity, it is not immune from suit but should be permitted to litigate in federal rather than state court. If the case is returned to state court, the companies, and other cross-defendants, intend to re-file their motions to dismiss in state court, which had been filed in federal court but never ruled upon. The companies believe these matters will not have a material adverse effect on their consolidated financial positions, results of operations or cash flow.

Western Energy Proceedings at the FERC:
California Power Exchange Chargeback:
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 defaulted on a payment, the other participants were required to pay their allocated share of the default amount to the CalPX. The allocated shares were based upon the level of trading activity, which included 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 million - a "default share invoice" - as a result of an alleged Southern California Edison payment default of $215 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated its participation agreement with the CalPX. On February 8, 2001, the CalPX sent a further invoice for $5 million, due on February 20, 2001, as a result of alleged payment defaults by Southern California Edison, Pacific Gas and Electric Company and others. However, because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8 invoice. The CalPX later reversed IPC's payment of the January 18, 2001 invoice, but on June 20, 2001 invoiced IPC for an additional $2 million which the CalPX has not reversed. The CalPX owes IPC $14 million for power sold in November and December including $2 million associated with the default share invoice dated June 20, 2001. IPC essentially discontinued energy trading with the CalPX and the California Independent System Operator (Cal ISO) 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 the FERC to intervene in a proceeding that requested the FERC to suspend the use of the CalPX chargeback methodology and provide for further oversight in the CalPX's implementation of its default mitigation procedures.

A preliminary injunction was granted by a federal judge in the U.S. 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, Pacific Gas and Electric Company filed for bankruptcy. The CalPX and the Cal ISO were among the creditors of Pacific Gas and Electric Company. To the extent that Pacific Gas and Electric Company's bankruptcy filing affects the collectibility of the receivables from the CalPX and the Cal ISO, the receivables from these entities are at greater risk.

The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to Pacific Gas and Electric Company's and Southern California Edison's liabilities. Shortly after the issuance of that order, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claims it is awaiting further orders from the FERC and the bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. Although certain parties to the California refund proceeding urged the FERC's Presiding Administrative Law Judge to consider the chargeback amounts in his determination of who owes what to whom, in his Certification of Proposed Findings on California Refund Liability, he concluded that the matter already was pending before the FERC for disposition. On October 7, 2004, the FERC issued an order determining that it would not require the disbursement of chargeback funds until the completion of the California refund proceedings. On November 8, 2004, IE, along with a number of other parties, sought rehearing of that order. The FERC has not yet acted on the requests for rehearing.

California Refund:
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 a 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 spot market 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's Chief Administrative Law 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.

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 (Refund Period).

This case had been complicated by an August 13, 2002 FERC Staff Report which included the recommendation to replace the published California indices for gas prices that the FERC previously established as just and reasonable for calculating a Mitigated Market Clearing Price to calculate refunds with other published indices for producing basin prices plus a transportation allowance. The FERC Staff's recommendation is grounded on speculation that some sellers had an incentive to report exaggerated prices to publishers of the indices, resulting in overstated published index prices. The FERC Staff based its speculation in large part on a statistical correlation analysis of Henry Hub and California prices. IE, in conjunction with others, submitted comments on the FERC Staff recommendation - asserting that the staff's conclusions were incorrect because the staff's correlation study ignored evidence of normal market forces and scarcity that created the pricing variations that the staff observed, rather than improper manipulation of reported prices.

The Administrative Law Judge issued a Certification of Proposed Findings on California Refund Liability on December 12, 2002.

The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affirmed the recommendations of its Administrative Law Judge. However, the FERC changed a component of the formula the Administrative Law Judge was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the prices a gas market that had not been manipulated would have produced, despite the fact that many gas buyers paid those amounts. The findings of the Administrative Law Judge, as adjusted by the FERC's March 26, 2003 order, are expected to increase the offsets to amounts still owed by the Cal ISO and the CalPX to the companies. Calculations remain uncertain because the FERC has required the Cal ISO to correct a number of defects in its calculations and because the FERC has stated that if refunds will prevent a seller from recovering its California portfolio costs during the Refund Period, it will provide an opportunity for a cost showing by such a respondent. As a result, IE is unsure of the impact this ruling will have on the refunds due from California. However, as to potential refunds, if any, IE believes its exposure is likely to be offset by amounts due from California entities.

IE, along with a number of other parties, filed an application with the FERC on April 25, 2003 seeking rehearing of the March 26, 2003 order. On October 16, 2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and directing the Cal ISO to prepare its compliance filing calculating revised Mitigated Market Clearing Prices and refund amounts within five months. The Cal ISO has since requested additional time to complete its compliance filings. By order of February 3, 2004, the FERC granted additional time. In a February 10, 2004 report to the FERC, the Cal ISO asserted its belief that it would complete re-running the data and financial clearing of amounts due by August 2004, subject to a number of events that must occur in the interim, including FERC disposition of a number of pending issues. This Cal ISO compliance filing has since been delayed until at least April 2005. The Cal ISO is required to update the FERC on its progress monthly. After receipt of the compliance filing, the FERC will consider cost-based filings from sellers to reduce their refund exposure.

On December 2, 2003, IE petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties' petitions with the petitions for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than 100. The Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the development of a comprehensive plan to brief this complicated case. Certain parties also sought further rehearing and clarification before the FERC. On September 21, 2004, the Ninth Circuit convened case management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed a subset of the stayed appeals in order that briefing could commence regarding limited issues of: (1) which parties are subject to the FERC's refund jurisdiction under section 201(f) of the Federal Power Act; (2) the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transactions are subject to refunds. Petitioners and petitioner-intervenors, including IE, filed opening briefs regarding the latter two issues on December 23, 2004. The FERC filed its respondent's brief on January 31, 2005, and petitioners and petitioner-intervenors, including IE , filed their reply briefs on March 1, 2005. Oral argument is scheduled for April 12-13, 2005.

On May 12, 2004, the FERC issued an order clarifying portions of its earlier refund orders and, among other things, denying a proposal made by Duke Energy North America and Duke Energy Trading and Marketing (and supported by IE) to lodge as evidence a contested settlement in a separate complaint proceeding, California Public Utilities Commission (CPUC) v. El Paso et al. The CPUC's complaint alleged that the El Paso companies manipulated California energy markets by withholding pipeline transportation capacity into California in order to drive up natural gas prices immediately before and during the California energy crisis in 2000-2001. The settlement will result in the payment by El Paso of some $1.69 billion. Duke claimed that the relief afforded by the settlement was duplicative of the remedies imposed by the FERC in its March 26, 2003 order changing the gas cost component of its refund calculation methodology. IE, along with other parties, has sought rehearing of the May 12, 2004 order. On November 23, 2004, the FERC denied rehearing and within the statutory time allowed for petitions, a number of parties, including IE, filed petitions for review of the FERC's order. These petitions have since been consolidated with the larger number of review petitions in connection with the California refund proceeding.

In June 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with this transfer, the outstanding receivables and payables with the CalPX and the Cal ISO were assigned from IPC to IE. At December 31, 2004, with respect to the CalPX chargeback and the California refund proceedings discussed above, the CalPX and the Cal ISO owed $14 million and $30 million, respectively, for energy sales made to them by IPC in November and December 2000. IE has accrued a reserve of $42 million against these receivables. This reserve was calculated taking into account the uncertainty of collection given the California energy situation. Based on the reserve recorded as of December 31, 2004, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

On March 20, 2002, the California Attorney General filed a complaint with the FERC against various sellers in the wholesale power market, including IE and IPC, alleging that the FERC's market-based rate requirements violate the Federal Power Act, and, even if the market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the Federal Power Act and the FERC. The complaint stated that refunds for amounts charged between market-based rates and cost-based rates should be ordered. The FERC denied the challenge to market-based rates and refused to order refunds, but did require sellers, including IE and IPC, to refile their quarterly reports to include transaction-specific data. The Attorney General appealed the FERC's decision to the U.S. Court of Appeals for the Ninth Circuit. The Attorney General contends that the failure of all market-based rate authority sellers of power to have rates on file with the FERC in advance of sales is impermissible. The Ninth Circuit issued its decision on September 9, 2004, concluding that market-based tariffs are permissible under the Federal Power Act, but remanded the matter to the FERC to consider whether the FERC should exercise remedial power (including some form of refunds) when a market participant failed to submit reports that the FERC relies on to confirm the justness and reasonableness of rates charged. Certain parties to the litigation have sought rehearing. The companies cannot predict whether rehearing will be granted or what action the FERC might take if the matter is remanded.

Market Manipulation:
In a November 20, 2002 order, the FERC permitted discovery and the submission of evidence respecting market manipulation by various sellers during the western power crises of 2000 and 2001.

On March 3, 2003, the California Parties (certain investor owned utilities, the California Attorney General, the California Electricity Oversight Board and the CPUC) filed voluminous documentation asserting that a number of wholesale power suppliers, including IE and IPC, had engaged in a variety of forms of conduct that the California Parties contended were impermissible. Although the contentions of the California Parties were contained in more than 11 compact discs of data and testimony, approximately 12,000 pages, IE and IPC were mentioned in limited contexts with the overwhelming majority of the claims of the California Parties relating to the conduct of other parties.

The California Parties urged the FERC to apply the precepts of its earlier decision, to replace actual prices charged in every hour starting May 1, 2000 through the beginning of the existing Refund Period with a Mitigated Market Clearing Price, seeking approximately $8 billion in refunds to the Cal ISO and the CalPX. On March 20, 2003, numerous parties, including IE and IPC, submitted briefs and responsive testimony.

In its March 26, 2003 order, discussed above in "California Refund," the FERC declined to generically apply its refund determinations to sales by all market participants, although it stated that it reserved the right to provide remedies for the market against parties shown to have engaged in proscribed conduct.

On June 25, 2003, the FERC ordered over 50 entities that participated in the western wholesale power markets between January 1, 2000 and June 20, 2001, including IPC, to show cause why certain trading practices did not constitute gaming or anomalous market behavior in violation of the Cal ISO and the CalPX Tariffs. The Cal ISO was ordered to provide data on each entity's trading practices within 21 days of the order, and each entity was to respond explaining their trading practices within 45 days of receipt of the Cal ISO data. IPC submitted its responses to the show cause orders on September 2 and 4, 2003. On October 16, 2003, IPC reached agreement with the FERC Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the FERC Staff determined it had no basis to proceed with allegations of false imports and paper trading and IPC agreed to pay $83,373 to settle allegations of circular scheduling. IPC believed that it had defenses to the circular scheduling allegation but determined that the cost of settlement was less than the cost of litigation. In the settlement, IPC did not admit any wrongdoing or violation of any law. With respect to the "partnership" order, the FERC Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IPC did not use its "parking" and "lending" arrangement with Public Service Company of New Mexico to engage in "gaming" or anomalous market behavior ("partnership"). The "gaming" settlement was approved by the FERC on March 3, 2004. Eight parties have requested rehearing of the FERC's March 3, 2004 order, but the FERC has not yet acted on those requests. The motion to dismiss the "partnership" proceeding was approved by the FERC in an order issued on January 23, 2004 and rehearing of that order was not sought within the time allowed by statute. Some of the California Parties and other parties have petitioned the U.S. Court of Appeals for the Ninth Circuit and the District of Columbia Circuit for review of the FERC's orders initiating the show cause proceedings. Some of the parties contend that the scope of the proceedings initiated by the FERC was too narrow. Other parties contend that the orders initiating the show cause proceedings were impermissible. Under the rules for multidistrict litigation, a lottery was held and although these cases were to be considered in the District of Columbia Circuit by order of February 10, 2005, the District of Columbia Circuit transferred the proceedings to the Ninth Circuit. The FERC had moved the District of Columbia Circuit to dismiss these petitions on the grounds of prematurity and lack of ripeness and finality. The transfer order was issued before a ruling from the District of Columbia Circuit and the motions, if renewed, will be considered by the Ninth Circuit. The company is not able to predict the outcome of the judicial determination of these issues.

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. In this investigation, the FERC was to review evidence of alleged economic withholding of generation. The FERC determined that all bids into the CalPX and the Cal ISO markets for more than $250 per MWh for the time period May 1, 2000 through October 1, 2000 would be considered prima facie evidence of economic withholding. The FERC Staff issued data requests in this investigation to over 60 market participants including IPC. IPC responded to the FERC's data requests. In a letter dated May 12, 2004, the FERC's Office of Market Oversight and Investigations advised that it was terminating the investigation as to IPC.

Pacific Northwest Refund:
On July 25, 2001, the FERC issued an order establishing 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 submitted recommendations and findings to the FERC on September 24, 2001. The Administrative Law Judge found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the Administrative Law Judge's decision is a recommendation to the commissioners of the FERC. Multiple parties submitted comments to the FERC with respect to the Administrative Law Judge's recommendations. The Administrative Law Judge's recommended findings had been pending before the FERC, when at the request of the City of Tacoma and the Port of Seattle on December 19, 2002, the FERC reopened the proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others. As was the case in the California refund proceeding, at the conclusion of the discovery period, parties alleging market manipulation were to submit their claims to the FERC and responses were due on March 20, 2003. Grays Harbor, whose civil litigation claims were dismissed, as noted above, intervened in this FERC proceeding, asserting on March 3, 2003 that its six-month forward contract, for which performance has been completed, should be treated as a spot market contract for purposes of the FERC's consideration of refunds and is requesting refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by IPC or IE. The companies submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made filings with the FERC on March 3, 2003 claiming that because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets. Although the majority of the claims of these parties are generic, they named a number of power market suppliers, including IPC and IE, as having used parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of improperly having received congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the month, the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated the proceeding and denied claims that refunds should be paid. The FERC denied rehearing on November 10, 2003, triggering the right to file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General, the CPUC and Puget Sound Energy Inc. filed petitions for review in the Ninth Circuit. These petitions have been consolidated. Grays Harbor did not file a petition for review, although it has sought to intervene in the proceedings initiated by the petitions of others. The FERC has certified the record to the Ninth Circuit. On July 21, 2004, the City of Seattle submitted to the Ninth Circuit in the Pacific Northwest refund petition for review a motion requesting leave to offer additional evidence before the FERC in order to try to secure another opportunity for reconsideration by the FERC of its earlier rulings. The evidence that the City of Seattle seeks to introduce before the FERC consists of audio tapes of what purports to be Enron trader conversations containing inflammatory language that have been the subject of coverage in the press. Under Section 313(b) of the Federal Power Act, a court is empowered to direct the introduction of additional evidence if it is material and could not have been introduced during the underlying proceeding. The City of Seattle also requested that the current briefing schedule, which required briefs to be filed by August 5, 2004, be delayed. On September 29, 2004, the Ninth Circuit denied the City of Seattle's motion for leave to adduce evidence, without prejudice to renewing the request for remand in the briefing in the Pacific Northwest refund case. Petitioner's briefs were filed January 14, 2005, Petitioner-intervenors briefs were filed on February 14, 2005 and Respondent's brief is due March 30, 2005 and Respondent-intervenor's briefs and the briefs of any non-aligned intevenors are due April 29, 2005. Petitioners reply briefs are due 42 days after service of respondent's briefs. Petitioner-intervenors' briefs are due 56 days after service of respondent's briefs. A date for oral argument has not yet been set.

The companies are unable to predict the outcome of these matters.

On July 21, 2004, Californians for Renewable Energy, Inc. (CARE) filed a motion with the FERC in connection with the California Refund proceedings, the Pacific Northwest refund proceedings and the show cause proceedings, both gaming and partnership, including those in which IPC was the respondent. CARE has participated in many of the FERC proceedings dealing with California energy matters, having appointed itself as a representative of low-income communities and other groups that it claims are otherwise not represented. The FERC permitted CARE to participate in the cases as an intervenor. In its current motion, CARE requests that the FERC radically restructure its approach to California and western energy proceedings involving the events of 2000 and 2001 by revoking market-based rate authority from the date of their approvals, replacing market-based rates with cost-of-service rates by requiring refunds back to the date of the orders granting market-based rate authority, revising long-term energy contracts negotiated during 2000 and 2001 (it appears that the contracts that CARE identified do not include any to which IPC is a party), deferring further refund settlements, establishing a direct pass-through refund mechanism for California consumers and having "previously executed settlement agreements rejected." CARE also requested that the FERC revoke market-based rates for those entities identified in the June 25, 2003 show cause orders, which would include IPC. IPC defended itself in response to this motion and is unable to predict how the FERC will respond to CARE's motion. On September 9, 2004, CARE filed a motion to withdraw its July 21, 2004 pleading. By operation of law, the withdrawal was effective September 24, 2004.

Shareholder Lawsuits: On May 26, 2004 and June 22, 2004, respectively, two shareholder lawsuits were filed against IDACORP and certain of its directors and officers. The lawsuits, captioned Powell, et al. v. IDACORP, Inc., et al. and Shorthouse, et al. v. IDACORP, Inc., et al., raise largely similar allegations. The lawsuits are putative class actions brought on behalf of purchasers of IDACORP stock between February 1, 2002 and June 4, 2002, and were filed in the U.S. District Court for the District of Idaho. The named defendants in each suit, in addition to IDACORP, are Jon H. Miller, Jan B. Packwood, J. LaMont Keen and Darrel T. Anderson.

The complaints alleged that, during the purported class period, IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about the company's financial outlook in violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5, thereby causing investors to purchase the company's common stock at artificially inflated prices. More specifically, the complaints alleged that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to defendants or recklessly disregarded by them: (1) IDACORP failed to appreciate the negative impact that lower volatility and reduced pricing spreads in the western wholesale energy market would have on its marketing subsidiary, IE; (2) IDACORP would be forced to limit its origination activities to shorter-term transactions due to increasing regulatory uncertainty and continued deterioration of creditworthy counterparties; (3) IDACORP failed to discount for the fact that IPC may not recover from the lingering effects of the prior year's regional drought and (4) as a result of the foregoing, defendants lacked a reasonable basis for their positive statements about IDACORP and their earnings projections. The Powell complaint also alleged that the defendants' conduct artificially inflated the price of the company's common stock. The actions seek an unspecified amount of damages, as well as other forms of relief. By order dated August 31, 2004, the court consolidated the Powell and Shorthouse cases for pretrial purposes, and ordered the plaintiffs to file a consolidated complaint within 60 days. On November 1, 2004, IDACORP and the directors and officers named above were served with a purported consolidated complaint captioned Powell et al. v. IDACORP, Inc. et al., which was filed in the U.S. District Court for the District of Idaho.

IDACORP and the other defendants intend to defend themselves vigorously against the allegations. The company cannot, however, predict the outcome of these matters.

Powerex: On August 31, 2004, Powerex Corp., the wholly owned power marketing subsidiary of BC Hydro, a Crown Corporation of the province of British Columbia, Canada, filed a lawsuit against IE and IDACORP in the U.S. District Court for the District of Idaho. Powerex Corp. alleges that IE breached an oral and written contract regarding the assignment of transmission capacity for electric power by IE to Powerex Corp. for a fourteen-month period and for intentional interference with Powerex Corp.'s alleged contract with IE. Powerex Corp. seeks unspecified general and special damages. On November 29, 2004, the companies filed an answer to Powerex Corp.'s complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The companies intend to vigorously defend their position in this proceeding but cannot predict the outcome of this matter.

Other Legal Issues
Idaho Power Company Transmission Line Rights-of-Way Across Fort Hall Indian Reservation: IPC has multiple transmission lines that cross the Shoshone-Bannock Tribes' Fort Hall Indian Reservation near the city of Pocatello in southeastern Idaho. IPC has been working since 1996 to renew four of the right-of-way permits (for five of the transmission lines), which have stated permit expiration dates between 1996 and 2003. IPC filed applications with the U.S. Department of the Interior, Bureau of Indian Affairs, to renew the four rights-of-way for 25 years, including payment of the independently appraised value of the rights-of-way to the tribes (and the tribal allottees who own portions of the rights-of-way). Due to the lack of definitive legal guidelines for valuation of the permit renewals, IPC is in the process of negotiating mutually acceptable renewal terms with the tribes and allottees. The parties are pursuing a possible 23-year renewal of the permits (including all pre-renewal periods) for a total payment of approximately $7 million to the tribes and allottees. IPC, the tribes and the Bureau of Indian Affairs are currently working through the process of finalizing the agreement, including obtaining the requisite consents from the allottees. The parties hope to obtain the required consents early in 2005. On December 27, 2004, IPC filed an application with the IPUC seeking an accounting order regarding the treatment of this transaction. On February 28, 2005, the IPUC issued an order approving IPC's application procedure.

9. STOCK-BASED COMPENSATION:

IDACORP has two stock-based compensation plans, the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (Restricted Stock Plan). These plans are intended to align employee and shareholder objectives related to its long-term growth.

The LTICP for officers, key employees and directors 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 2004, 2003 and 2002, IDACORP granted 142,100, 429,000 and 355,000 stock options, respectively, with an exercise price equal to the market price of IDACORP's stock on the date of grant. In accordance with APB 25, no compensation costs have been recognized for the option awards.

Stock option transactions are summarized as follows:

		2004			2003			2002
			Weighted			Weighted			Weighted
		Number	average		Number	average		Number	average
		of	exercise		of	exercise		of	exercise
		shares	price		shares	price		shares	price
Outstanding, beginning of year		1,148,400	$	32.71	849,000	$	38.50	494,000	$	37.79
	Granted	142,100		31.21	429,000		23.01	355,000		39.50
	Exercised	(7,400)		22.92	-		-	-		-
	Forfeited	(71,300)		31.81	(129,600)		38.57	-		-
Outstanding, end of year		1,211,800	$	32.64	1,148,400	$	32.71	849,000	$	38.50

Exercisable		473,800	$	35.58	266,600	$	37.91	120,800	$	37.20

The following table summarizes information about stock options outstanding at December 31, 2004:

	Outstanding				Exercisable
				Weighted
		Weighted		average		Weighted
		average		remaining		average
	Number	exercise		contractual	Number	exercise
Exercise Price Ranges	of shares	price		life	of shares	price
$22.92 - $31.21	525,200	$	25.08	8.43 years	78,000	$	23.02
$35.81 - $40.31	686,600	$	38.43	6.38 years	395,800	$	38.05

The fair value of each option granted was estimated at the date of grant using a binomial option-pricing model with the following assumptions:

	2004	2003	2002
Dividend yield	3.84%	8.09%	4.71%
Expected stock price volatility	29%	28%	32%
Risk-free interest rate	3.97%	3.94%	4.92%
Expected option lives	7 years	7 years	7 years
Weighted average fair value of options granted	$7.93	$ 3.90	$10.54

IDACORP's Restricted Stock Plan is for key employees. Each restricted stock grant has a four-year restricted period. Each performance share grant has a three-year restricted period and the final award amount depends on the attainment of cumulative EPS performance goals. At December 31, 2004, there were 63,572 remaining shares available under the Restricted Stock Plan.

Restricted stock and performance share awards are compensatory awards and IDACORP accrues compensation expense, which is charged to operations, based upon the market value of the granted shares. For 2004, 2003 and 2002, total compensation accrued under the Restricted Stock Plan was less than $1 million annually.

The following table summarizes restricted stock and performance share activity:

	2004		2003		2002
Shares outstanding - beginning of year	94,363		87,669		63,551
Shares granted	78,116		52,517		44,832
Shares forfeited	(30,931)		(6,679)		(132)
Shares issued	-		(39,144)		(20,582)
Shares outstanding - end of year	141,548		94,363		87,669
Weighted average fair value of current year stock grants on grant date	$	31.21	$	23.01	$	38.58

10. BENEFIT PLANS:

Pension Plans
IPC has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee's final average earnings. IPC's policy is to fund, with an independent corporate trustee, at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. IPC was not required to contribute to the plan in 2004, 2003 or 2002, and does not expect to make a contribution in 2005. The market-related value of assets for the plan is equal to market value.

In addition, IPC has a nonqualified, deferred compensation plan for certain senior management employees and directors. This plan was financed 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.

IPC uses a December 31 measurement date for its plans.

The following table summarizes the changes in benefit obligations and plan assets of these plans:

		Pension Plan				Deferred Compensation Plan
		2004		2003		2004		2003
		(thousands of dollars)
Change in benefit obligation:
	Benefit obligation at January 1	$	339,121	$	294,881	$	38,870	$	35,792
	Service cost		11,809		10,173		1,358		1,212
	Interest cost		20,437		19,463		2,312		2,414
	Actuarial loss (gain)		16,626		27,420		(1,225)		1,786
	Benefits paid		(13,660)		(13,345)		(2,670)		(2,369)
	Plan amendments		-		529		-		35
	Benefit obligation at December 31		374,333		339,121		38,645		38,870
Change in plan assets:
	Fair value at January 1		335,229		282,531		-		-
	Actual return on plan assets		34,648		66,043		-		-
	Employer contributions		-		-		-		-
	Benefit payments		(13,660)		(13,345)		-		-
	Fair value at December 31		356,217		335,229		-		-

Funded status			(18,116)		(3,892)		(38,645)		(38,870)
Unrecognized actuarial loss			28,491		18,577		11,443		13,547
Unrecognized prior service cost			5,889		6,660		1,372		1,010
Unrecognized net transition liability			(126)		(389)		310		923
Net amount recognized		$	16,138	$	20,956	$	(25,520)	$	(23,390)
Amounts recognized in the statement of
	financial position consist of:
Prepaid (accrued) pension cost		$	16,138	$	20,956	$	(36,110)	$	(35,676)
Intangible asset			-		-		1,682		1,933
Accumulated other comprehensive income			-		-		8,908		10,353
Net amount recognized		$	16,138	$	20,956	$	(25,520)	$	(23,390)
Accumulated benefit obligation		$	316,498	$	284,910	$	36,110	$	35,676

The following table shows the components of net periodic benefit cost for these plans:

	Pension Plan							Deferred Compensation Plan
	2004		2003		2002		2004			2003		2002
	(thousands of dollars)

Service cost	$	11,809	$	10,173	$	9,548	$		1,358	$	1,212	$	944
Interest cost		20,437		19,463		18,684			2,312		2,414		2,108
Expected return on assets		(27,935)		(23,445)		(28,797)			-		-		-
Recognized net actuarial loss		-		361		-			878		744		498
Amortization of prior service cost		770		729		729			(361)		(345)		(353)
Amortization of transition asset		(263)		(263)		(263)			613		613		613
Net periodic pension cost (benefit)	$	4,818	$	7,018	$	(99)	$		4,800	$	4,638	$	3,810

Changes in the Deferred Compensation Plan minimum liability increased other comprehensive income by $1 million in 2004 and decreased other comprehensive income by $1 million and $3 million in 2003 and 2002, respectively.

The following table summarizes the expected future benefit payments of these plans:

		2005		2006		2007		2008		2009		2010-2014
Pension Plan	$	13,846	$	14,277	$	14,996	$	16,018	$	17,244	$	110,833
Deferred Compensation Plan	$	2,296	$	2,345	$	2,461	$	2,551	$	2,721	$	15,041

Plan Asset Allocations: IPC's pension plan and postretirement benefit plan weighted average asset allocations at December 31, 2004 and 2003, by asset category are as follows:

		Pension		Postretirement
		Plan		Benefits
Asset Category		2004	2003	2004	2003
Equity securities		69%	69%	-%	-%
Debt securities		21	21	3	2
Real estate		9	9	-	-
Other (a)		1	1	97	98
	Total	100%	100%	100%	100%
(a) The postretirement benefit plan assets are primarily life insurance contracts.

Pension Asset Allocation Policy: The target allocations for the portfolio by asset class are as follows:

Large-Cap Growth Stocks	12%	International Growth Stocks	7%
Large-Cap Core Stocks	12%	International Value Stocks	7%
Large-Cap Value Stocks	12%	Intermediate-Term Bonds	13%
Small-Cap Growth Stocks	7%	Short-Term Bonds	10%
Small-Cap Value Stocks	7%	Core Real Estate	9%
Cash and Cash Equivalents	3%	Venture Capital	1%

Assets are rebalanced as necessary to keep the portfolio close to target allocations.

The plan's principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio. Emphasis is placed on preservation and growth of capital along with adequacy of cash flow sufficient to fund current and future payments to pensioners.

There are three major goals in IPC's asset allocation process:

Determine if the investments have the potential to earn the rate of return assumed in the actuarial liability calculations.

Match the cash flow needs of the plan. IPC sets cash allocations sufficient to cover the current year benefit payments and bond allocations sufficient to cover at least five years of benefit payments. IPC then utilizes growth instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan.

Maintain a prudent risk profile consistent with ERISA fiduciary standards. The baseline risk measure is a 60 percent S&P 500 stocks and a 40 percent Lehman Aggregate bond portfolio.

Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, core real estate funds, private equity funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price. Uncovered options, short sales, margin purchases, letter stock and commodities are prohibited.

Rate-of-return projections for plan assets are based on historical real returns adjusted for inflation for each asset class, based on a recognized index established for the asset class being measured. Historical real returns are then adjusted to include an inflation premium based on the current inflation environment. IPC currently uses a three percent inflation assumption in the asset modeling process.

IPC's asset modeling process also utilizes historical market returns to measure the portfolio's exposure to a "worst-case" market scenario, to determine how much performance could vary from the expected "average" performance over various time periods. This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the basis for managing the risk associated with investing portfolio assets.

Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents. Effective January 1, 2003, IPC amended its postretirement benefit plan. The amendment affects all employees who retire after December 31, 2002, limiting their postretirement benefit to a fixed amount. This amendment will limit the growth of IPC's future obligations under this plan.

The net periodic postretirement benefit cost was as follows (in thousands of dollars):

	2004		2003		2002
Service cost	$	1,400	$	1,207	$	927
Interest cost		3,974		4,017		3,648
Expected return on plan assets		(2,294)		(1,930)		(2,320)
Amortization of unrecognized transition obligation		2,040		2,040		2,040
Amortization of prior service cost		(523)		(563)		(563)
Recognized actuarial loss		1,489		1,402		487
Net periodic postretirement benefit cost	$	6,086	$	6,173	$	4,219

The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars):

		2004		2003
Change in accumulated benefit obligation:
	Benefit obligation at January 1	$	67,090	$	57,267
	Service cost		1,400		1,207
	Interest cost		3,974		4,017
	Actuarial loss		2,201		8,780
	Benefits paid		(3,997)		(4,181)
	Plan Amendments		437		-
	Benefit obligation at December 31		71,105		67,090

Change in plan assets:
	Fair value of plan assets at January 1		26,603		22,522
	Actual return on plan assets		2,301		4,081
	Employer contributions		4,577		3,961
	Benefits paid		(3,758)		(3,961)
	Fair value of plan assets at December 31		29,723		26,603

Funded status			(41,382)		(40,487)
Unrecognized prior service cost			(4,087)		(5,047)
Unrecognized actuarial loss			24,559		23,854
Unrecognized transition obligation			16,320		18,360
Accrued benefit obligations included with other deferred credits		$	(4,590)	$	(3,320)

The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan was 6.75 percent in 2004 and 2003. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of dollars):

	1-Percentage-Point
	increase		decrease

Effect on total of cost components	$	220	$	(170)
Effect on accumulated postretirement benefit obligation	$	1,996	$	(1,625)

The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all IPC-sponsored pension and postretirement benefits plans:

	Pension		Postretirement
	Benefits		Benefits
	2004	2003	2004	2003
Discount rate	5.75%	6.15%	5.75%	6.15%
Expected long-term rate of return on assets	8.5	8.5	8.5	8.5
Rate of compensation increase	4.5	4.5	-	-
Medical trend rate	-	-	6.75	6.75
Expected working lifetime (years)	-	-	11	12

The following table sets forth the weighted-average assumptions used for the end of each year to determine net periodic benefit cost for all IPC-sponsored pension and postretirement benefit plans:

	Pension		Postretirement
	Benefits		Benefits
	2004	2003	2004	2003
Discount rate	6.15%	6.75%	6.15%	6.75%
Expected long-term rate of return on assets	8.5	8.5	8.5	8.5
Rate of compensation increase	4.5	4.5	-	-
Medical trend rate	-	-	6.75	6.75
Expected working lifetime (years)	-	-	11	12

FSP FAS 106-1 and FSP FAS 106-2
In January and May 2004, the FASB released FSP FAS 106-1 and FSP FAS 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003."

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law in December 2003 and establishes a prescription drug benefit, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare's prescription drug coverage.

FSP FAS 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits and requires those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. Under FSP FAS 106-1, IDACORP and IPC elected to defer accounting for the effects of the Medicare Act. This deferral remained in effect until the appropriate effective date of FSP FAS 106-2.

FSP FAS 106-2 was effective for the first interim or annual period beginning after June 15, 2004. However, for entities that did not recognize a significant impact, delayed recognition of the effects of the Medicare Act until the next regularly scheduled measurement date following the issuance of FSP FAS 106-2 was required.

The measures of accumulated postretirement benefit obligation and net periodic benefit cost do not reflect any amount associated with the subsidy, because IDACORP and IPC initially determined that the effect of the Medicare Act would not be material. Regulations published on January 28, 2005 provide more flexibility in determining actuarial equivalence to Medicare of the benefits provided by the plan than was initially estimated by IDACORP's and IPC's actuaries.Based on these new regulations, IDACORP and IPC estimate that the accumulated postretirement benefit obligation as of January 1, 2005 will be reduced by $6 million, and 2005 periodic postretirement benefit cost will decrease by $1 million.

Employee Savings Plan
IPC has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. IPC matches specified percentages of employee contributions to the plan. Matching contributions amounted to $3 million in both 2004 and 2003 and $4 million in 2002.

Postemployment Benefits
IPC provides certain benefits to former or inactive employees, their beneficiaries and covered dependents after employment but before retirement. These benefits include salary continuation, health care and life insurance for those employees found to be disabled under IPC's disability plans and health care for surviving spouses and dependents. IPC accrues a liability for such benefits. In accordance with an IPUC order, the portion of the liability attributable to regulated activities in Idaho as of December 31, 1993, was deferred as a regulatory asset, and amortized over a ten-year period, which ended in January 2005.

The following table summarizes postemployment benefit amounts included in IDACORP and IPC's consolidated balance sheets at December 31 (in thousands of dollars):

	2004		2003
Included with regulatory assets	$	31	$	403
Included with other deferred credits	$	3,924	$	4,079

11. PROPERTY PLANT AND EQUIPMENT AND JOINTLY-OWNED PROJECTS:

The following table presents the major classifications of IPC's utility plant in service, annual depreciation provisions as a percent of average depreciable balance and accumulated provision for depreciation for the years 2004 and 2003 (in thousands of dollars):

		2004			2003
		Balance		Avg Rate	Balance		Avg Rate
Production		$	1,482,517	2.51%	$	1,456,954	2.62%
Transmission			560,303	2.18		526,887	2.21
Distribution			992,248	2.59		952,979	3.25
General and Other			289,748	10.02		283,408	6.51
	Total in service		3,324,816	2.96%		3,220,228	2.99%
Accumulated provision for depreciation			(1,316,125)			(1,239,604)
	In service - net	$	2,008,691		$	1,980,624

IPC has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. IPC's proportionate share of direct operation and maintenance expenses applicable to the projects is included in the Consolidated Statements of Income. These facilities, and the extent of IPC's participation, were as follows at December 31, 2004 (in thousands of dollars):

		Utility		Construction		Accumulated
		Plant In		Work in		Provision for
Name of Plant	Location	Service		Progress		Depreciation		%	MW
Jim Bridger Units 1-4	Rock Springs, WY	$	442,367	$	4,310	$	255,229	33	707
Boardman	Boardman, OR		66,116		1,277		44,275	10	55
Valmy Units 1 and 2	Winnemucca, NV		310,917		889		184,025	50	261

IPC's wholly owned subsidiary, Idaho Energy Resources Co., is a joint venturer in Bridger Coal Company, which operates the mine supplying coal to the Jim Bridger generating plant. Coal purchased by IPC from the joint venture amounted to $47 million in 2004 and $44 million in both 2003 and 2002.

IPC has contracts to purchase the energy from four Public Utilities Regulatory Policy Act of 1978 (PURPA) Qualified Facilities that are 50 percent owned by Ida-West. Power purchased from these facilities amounted to $7 million, annually in 2004, 2003 and 2002.
See Note 1 for a discussion of the property of IDACORP's consolidated VIEs.

Ida-West
During 2002, Ida-West recorded an $8.6 million partial write-down of its investment in equipment for the Garnet facility project. This partial write-down reflects the decrease in prices for and increased availability of generating equipment due to the collapse of the merchant power plant development business. In the fourth quarter of 2003, Ida-West wrote down its remaining investment of $3.6 million in the Garnet facility project.

12. SEGMENT INFORMATION:

Information regarding segments is presented in accordance with SFAS 131, "Disclosure about Segments of an Enterprise and Related Information." Based on the criteria outlined in SFAS 131, IDACORP has identified two reportable segments in 2004: utility operations and IFS.

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.

IFS represents that subsidiary's investments in affordable housing developments and historic preservation projects.

Energy marketing, which was formerly reported as a separate operating segment, has been removed, since it no longer meets the quantitative thresholds outlined in SFAS 131, and is not considered to be of continuing significance. See Note 15 for a discussion of the wind down of energy marketing operations.

The following table summarizes the segment information for IDACORP's utility operations, IFS and the total of all other segments, and reconciles this information to total enterprise amounts.

	Utility											Consolidated
	Operations		IFS			Other			Eliminations			Total
	(thousands of dollars)
2004
Revenues	$	822,937	$	1,392	$		20,162	$		-	$		844,491
Operating income (loss)		109,038		(544)			(15,243)			-			93,251
Other income (expense)		4,516		4,857			4,324			(69)			13,628
Interest income		2,413		655			1,250			(895)			3,423
Equity method income (loss)		12,313		(12,502)			1,239			-			1,050
Interest expense and preferred dividends		56,167		4,719			3,217			(964)			63,139
Income (loss) before income taxes		72,113		(12,253)			(11,647)			-			48,213
Income tax expense (benefit)		6,328		(25,566)			(5,532)			-			(24,770)
Net income (loss)		65,785		13,313			(6,115)			-			72,983
Total assets		2,969,212		145,279			211,120			(91,439)			3,234,172
Expenditures for long-lived assets		190,379		7,670			9,469			-			207,518
2003
Revenues	$	782,720	$	-	$		40,282	$		-	$		823,002
Operating income (loss)		121,694		(796)			(36,836)			-			84,062
Other income (expense)		105		71			(508)			(221)			(553)
Interest income		3,237		460			4,116			(3,338)			4,475
Equity method income (loss)		11,336		(10,461)			1,532			-			2,407
Interest expense and preferred dividends		59,483		5,821			3,187			(3,559)			64,932
Income (loss) before income taxes		76,889		(16,547)			(34,883)			-			25,459
Income tax expense (benefit)		21,728		(26,951)			(15,896)			-			(21,119)
Net income (loss)		55,161		10,404			(18,987)			-			46,578
Total assets		2,820,711		141,286			213,731			(69,620)			3,106,108
Expenditures for long-lived assets		148,494		3			1,393			-			149,890
2002
Revenues	$	869,040	$	-	$		59,760	$		-	$		928,800
Operating income (loss)		132,661		(923)			(56,098)			-			75,640
Other income (expense)		(3,330)		(21)			2,497			(275)			(1,129)
Interest income		2,873		555			7,497			(6,712)			4,213
Equity method income (loss)		12,065		(12,312)			993			-			746
Interest expense and preferred dividends		62,529		7,147			6,256			(6,987)			68,945
Income (loss) before income taxes		81,739		(19,848)			(51,366)			-			10,525
Income tax expense (benefit)		(2,594)		(28,680)			(19,873)			-			(51,147)
Net income (loss)		84,333		8,832			(31,493)			-			61,672
Total assets		2,876,167		157,018			579,999			(226,016)			3,387,168
Expenditures for long-lived assets		129,132		44,064			8,999			-			182,195

13. REGULATORY MATTERS:

General Rate Case
Idaho:IPC filed its Idaho general rate case with the IPUC on October 16, 2003. IPC originally requested approximately $86 million annually in additional revenue, an average 17.7 percent increase to base rates. On rebuttal, IPC lowered its overall requested increase to $70 million annually, an average of 14.5 percent. The IPUC approved an increase of $25 million in IPC's electric rates, an average of 5.2 percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004.

Additionally, the IPUC approved higher rates for residential and small-commercial customers during the summer months to encourage conservation. The 12.6 percent higher summer rate applies to monthly usage over 300 kilowatt-hours. The IPUC also ordered time-of-use rates to be phased in for industrial customers, asked IPC to submit a proposal for a conservation program for industrial customers and ordered increased low-income weatherization funding of $1 million annually.

On September 28, 2004, the IPUC issued separate orders approving two Settlement Agreements entered into on August 16, 2004 between IPC and the IPUC Staff.

Settlement No. 2, approved by the IPUC in Order No. 29600, resolved outstanding issues related to: (1) an unplanned outage at one of the two units of the North Valmy Steam Electric Generating Plant (Valmy) in the summer of 2003, (2) a matter relating to the expense adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002. In Settlement No. 2, IPC and the IPUC Staff agreed that the IPUC will not examine the cost of replacement power and a possible PCA adjustment resulting from the Valmy outage, and the expense adjustment rate for growth component of the PCA will continue at its existing value until IPC's next general rate case. In September 2004, as a result of the order, IPC established a regulatory liability of $19 million with a charge to PCA expense. A monthly credit of approximately $804,000 will be included in the PCA from June 2004 through May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing income tax expense. This regulatory tax liability was established in 2002 when IPC changed its tax accounting method for capitalized overhead costs.

On March 2, 2005, IPC made a rate filing with the IPUC to include the investment associated with the construction of the Bennett Mountain Power Plant in Idaho retail rates.

Oregon: On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or approximately $4 million annually. IPC's filing includes a request to introduce summer and non-summer rates similar to proposals that were approved in the Idaho general rate case. IPC has not filed for a change to its overall rates in Oregon since 1995.

On October 19, 2004, the OPUC suspended IPC's request for a period of time not to exceed nine months from October 20, 2004 to investigate the propriety and reasonableness of the request. A pre-hearing conference and public meeting was held on November 18, 2004. The hearing schedule called for a settlement conference, which began on February 14, 2005 and an evidentiary hearing to begin on May 23, 2005. IPC is unable to predict what rate relief the OPUC will grant.

Deferred Power Supply Costs
IPC's deferred net power supply costs consisted of the following at December 31 (in thousands of dollars):

		2004		2003
Oregon deferral		$	12,047	$	13,620
Idaho PCA current year net power supply cost deferrals:
	Deferral for 2004-2005 rate year		-		44,664
	Deferral for 2005-2006 rate year		22,778		-
Irrigation Lost Revenues			13,290		-
Idaho PCA true-up awaiting recovery:
	Remaining true-up authorized May 2003		-		13,646
	Remaining true-up authorized May 2004		11,415		-
	Total deferral	$	59,530	$	71,930

Idaho:IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the true-up of the true-up for the prior years' unrecovered portions, is then included in the calculation of the next year's PCA.

Oregon: On March 2, 2005 IPC file for an accounting order to defer net power supply costs for the period of March 1, 2005 through February 28, 2006 in anticipation of the low water conditions IPC is currently experiencing. The net system power supply costs included in this filing was $169 million. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses.

Idaho: In an IPUC proceeding that began in May 2001, IPC, the IPUC staff and several interested customer groups worked cooperatively to determine the appropriate compensation IE should provide to IPC for certain transactions between the affiliates. The IPUC has issued several orders since then regarding these matters. Order No. 28852 issued on September 28, 2001 covered the time period prior to February 2001. Order No. 29026 covered the time period from March 2001 through March 2002. The IPUC also approved IPC's ongoing hedging and risk management strategies in Order No. 29102 issued on August 28, 2002. This order formalized IPC's agreement to implement a number of changes to its existing practices for managing risk and initiating hedging purchases and sales. The $5.8 million in benefits related to the FERC settlement were included in the 2003-2004 PCA and credited to Idaho retail customers in accordance with the PCA methodology. The parties to the proceeding have executed a settlement agreement providing that an additional $5.5 million be flowed through the PCA mechanism to the Idaho retail customers from April 2003 through December 2005. This agreement was filed with the IPUC on February 17, 2004 and approved on March 15, 2004.

Regulatory Assets and Liabilities
The following is a breakdown of IPC's regulatory assets and liabilities (in thousands of dollars):

		2004				2003
		Assets		Liabilities		Assets		Liabilities
Income taxes		$	344,220	$	40,447	$	330,833	$	41,024
Conservation			17,836		5,205		21,108		5,288
Employee benefits			76		-		993		-
PCA deferral and amortization			34,193		-		58,310		-
Oregon deferral and amortization			12,047		-		13,620		-
Derivatives			-				125		-
Asset retirement obligations			8,372		147,700		6,456		142,595
Deferred investment tax credits			-		66,836		-		67,789
IPUC settlement order			7,119		13,671		-		-
Irrigation lost revenues			13,290		-		-		-
BPA settlement			-		1,833		-		1,735
Incremental security costs			813		-		1,076		-
OPUC settlement			-		100		-		-
Other			815		149		1,508		93
	Total	$	438,781	$	275,941	$	434,029	$	258,524

The regulatory assets related to income taxes and asset retirement obligations do not earn a current return on investment. For further information on the asset retirement obligations amounts, see Note 17.

In the event that recovery of costs through rates becomes unlikely or uncertain, SFAS 71 would no longer apply. If IPC were to discontinue application of SFAS 71 for some or all of its operations, then these items may represent stranded investments. If IPC is not allowed recovery of these investments, it would be required to write off the applicable portion of regulatory assets and the financial effects could be significant.

14. DERIVATIVE FINANCIAL INSTRUMENTS:

Energy Trading Contracts
The commodity transactions entered into by IE were classified as energy trading contracts or derivatives in accordance with SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" and Emerging Issues Task Force Issue 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Under SFAS 133 as amended, 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 offsetting 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 offsetting contracts, are realized over the life of the contract.

When determining the fair value of marketing and trading contracts, IE used 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 were not consistent with actively quoted prices IE used, when available, prices provided by other external sources. When prices from external sources were not available, IE determined prices by using internal pricing models that incorporated available current and historical pricing information. Finally, the fair market value of contracts was adjusted 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 thousands of dollars):

			2004		2003		2002
Gross Margin:
	Realized or otherwise settled		$	82	$	61,183	$	70,262
	Unrealized			(131)		(42,517)		(65,965)
		Total	$	(49)	$	18,666	$	4,297

15. RESTRUCTURING COSTS:

IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations due to changing liquidity requirements brought on by rating agencies, continued uncertainty in the regulatory and political environment and the reduction of creditworthy counterparties. On November 5, 2002, IDACORP announced that it was terminating further evaluation of growth opportunities in the mid-stream natural gas markets, and stated that IE would close its Denver office by year-end 2002, would shut down its natural gas trading operation in Houston by March 2003 and would further reduce its workforce in its Boise operations through mid-2003. IE has completed the major milestones of winding down the business, including the sale of IE's forward book of electricity trading contracts to Sempra Energy Trading in August 2003, closing of the Denver, Houston and Boise offices and the final workforce terminations in November 2003.

IE incurred involuntary termination benefit expenses, lease termination costs and other exit-related costs in connection with the wind down. Termination benefit expenses relate to the termination of 98 employees (primarily energy traders and administrative support positions). Of the 98 employees laid off, 19 were hired by other IDACORP subsidiaries, and thus received no severance benefits. Restructuring expenses are presented as energy marketing operating expenses on the Consolidated Statements of Income and restructuring accruals are presented as other liabilities on the Consolidated Balance Sheets.

The following table summarizes restructuring costs during the periods (in thousands of dollars):

		Severance		Lease
		and Other		Termination
		Benefits		Costs		Other		Total
Balance at January 1, 2002		$	-	$	-	$	-	$	-
	Amounts accrued		5,009		2,485		1,376		8,870
	Amounts paid		(838)		-		(1,181)		(2,019)
Balance at December 31, 2002			4,171		2,485		195		6,851
	Amounts accrued		4,379		182		-		4,561
	Amounts paid		(6,594)		(645)		(162)		(7,401)
	Amounts reversed		(149)		-		-		(149)
Balance at December 31, 2003			1,807		2,022		33		3,862
	Amounts accrued		-		28		-		28
	Amounts paid		(1,807)		(657)		-		(2,464)
	Amounts reversed		-		-		(33)		(33)
Balance at December 31, 2004		$	-	$	1,393	$	-	$	1,393

16. INVESTMENTS:

The following table summarizes IDACORP's and IPC's investments as of December 31 (in thousands of dollars):

			2004		2003
IPC Investments:
	Auction rate securities (available-for-sale)		$	31,650	$	-
	Equity method investment			25,028		25,576
	Available-for-sale equity securities			21,505		22,438
	Executive deferred compensation			6,002		617
	Other investments			808		14
		Total IPC investments		84,993		48,645
Investments in affordable housing				108,974		115,776
Equity method investments				8,670		10,772
Held-to-maturity debt securities				14,164		16,967
Executive deferred compensation				5,928		11,264
Other investments				332		1,050
		Total IDACORP investments	$	223,061	$	204,474

Equity Method Investments
IPC, through its subsidiary Idaho Energy Resources Co., is a 33 percent owner of Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC. Ida-West, through separate subsidiaries, owns 50 percent of each of the following electric generation projects: South Forks Joint Venture; Hazelton/Wilson Joint Venture and Snow Mountain Hydro LLC.

IFS invests in affordable housing developments that are accounted for in accordance with APB 18, "The Equity Method of Accounting for Investments in Common Stock" and Emerging Issues Task Force Issue 94-1, "Accounting for Tax Benefits Resulting from Investments in Affordable Housing Projects," and are presented as Investments on the Consolidated Balance Sheets. IFS currently accounts for these investments using the equity method, with the exception of one investment consolidated under FIN 46R. All projects are reviewed periodically for impairment.

The following table presents IDACORP's and IPC's earnings of unconsolidated equity-method investments (in thousands of dollars):

		2004		2003		2002
Bridger Coal Company (IPC)		$	12,313	$	11,336	$	12,065
Ida-West projects			1,239		1,532		993
IFS affordable housing projects			(12,502)		(10,461)		(12,312)
	Total	$	1,050	$	2,407	$	746

Investments in Debt and Equity Securities
Investments in debt and equity securities are accounted for in accordance with SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." Those investments classified as available-for-sale securities are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses. Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income.

IPC held $32 million of auction rate securities at December 31, 2004. Auction rate securities are long-term instruments whose interest rates or dividends are reset at specific frequencies. The typical reset periods are either 28 or 35 days. The rates or dividends are reset via a Dutch auction. The original maturities of these securities at the time of issuance ranged from 2007 to 2042.

Investments classified as held-to-maturity securities are reported at amortized cost. Held-to-maturity securities are investments in debt securities for which the company has the positive intent and ability to hold the securities until maturity. These debt securities have maturities ranging from 2005 through 2009.

The following table summarizes investments in debt and equity securities (in thousands of dollars):

	2004						2003
	Gross		Gross				Gross		Gross
	Unrealized		Unrealized		Fair		Unrealized		Unrealized		Fair
	Gain		Loss		Value		Gain		Loss		Value

Available-for-sale securities (IPC)	$	2,530	$	256	$	53,155	$	2,665	$	276	$	22,438
Held-to-maturity debt securities (IFS)		332		172		14,324		354		100		17,221

The following table summarizes sales of available-for-sale securities (in thousands of dollars):

	2004		2003		2002

Proceeds from sales	$	266,331	$	14,040	$	6,815
Gross realized gains from sales		2,044		1,046		365
Gross realized losses from sales		634		1,169		1,953

Additionally, these investments are evaluated to determine whether they have experienced a decline in market value that is considered other-than-temporary. IDACORP and IPC analyze securities in loss positions as of the end of each reporting period. Any security with an unrealized loss of more than 20 percent is evaluated for other-than-temporary impairment. A security will generally be written down to market value if it has an unrealized loss of 20 percent or more for more than nine months. If additional information is available that indicates a security is other-than-temporarily impaired, it will be written down prior to the nine-month time period. In the alternative, if a security has been impaired for more than nine months but available information indicates that the impairment is temporary, the security will not be written down. IDACORP and IPC recognized other-than-temporary impairments of $0.6 million and $1 million in 2003 and 2002, respectively. These declines are included in other income in the Consolidated Statements of Income. For 2004, it was determined there were no other-than-temporary declines in market value.

The following table summarizes information regarding securities that were in an unrealized loss position at the end of each year, but for which no other-than-temporary impairment was recognized (in thousands of dollars).


	Aggregate		Aggregate		Aggregate		Aggregate
	Unrealized		Related Fair		Unrealized		Related Fair
	Loss		Value		Loss		Value
	Less than 12 months				12 months or longer
2004:
Available for sale equity securities (IPC)	$	181	$	2,934	$	75	$	362
Held to maturity debt securities (IFS)		97		4,071		75		1,794

2003:
Available for sale equity securities (IPC)	$	200	$	2,577	$	76	$	359
Held to maturity debt securities (IFS)		88		3,862		12		429

The available-for-sale equity securities in unrealized loss positions are diversified investments in common stock of various companies used to fund IPC's Senior Management Security Plan. The held-to-maturity debt securities in unrealized loss positions are mainly yield-to-maturity bonds, whose market values fluctuate based on the interest rate environment. At December 31, 2004, ten available-for-sale and 14 held-to-maturity securities were in an unrealized loss position. At December 31, 2003, seven available-for-sale and 13 held-to-maturity securities were in an unrealized loss position. All unrealized losses were less than 20 percent. IDACORP and IPC have the ability and intent to hold the equity securities for a reasonable period of time sufficient for a forecasted recovery of fair value and do not consider these investments to be other-than-temporarily impaired at December 31, 2004 or 2003. Because IDACORP has the ability and intent to hold the debt securities until a recovery of fair value, which may be maturity, it does not consider them to be other-than-temporarily impaired at December 31, 2004 or 2003.

17. ASSET RETIREMENT OBLIGATIONS:

On January 1, 2003, IDACORP and IPC adopted SFAS 143, "Accounting for Asset Retirement Obligations." 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 or the normal operation of a long-lived asset. SFAS 143 requires an entity to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. If, at the end of the asset's life, the recorded liability differs from the actual obligations paid, a gain or loss would be recognized at that time. As a rate-regulated entity, IPC records regulatory assets and liabilities instead of accretion, depreciation and gains or losses. This treatment was approved by Order No. 29414 from the IPUC. The regulatory assets recorded under this order do not earn a return on investment.

IDACORP and IPC performed detailed assessments of the applicability and implications of SFAS 143 and identified AROs related to two of IPC's jointly owned coal-fired generation facilities and IPC's transmission and distribution facilities. Upon adoption, IPC recorded an ARO of $7 million, fixed assets of $2 million, accumulated depreciation of $1 million and a regulatory asset of $6 million. These amounts do not include an amount for the transmission and distribution facilities, because, based on the indeterminate life of these assets, an ARO calculation cannot be made.

The regulated operations of IPC also collect removal costs in rates for certain assets that do not have associated AROs. The adoption of SFAS 143 required IPC to redesignate these removal costs as regulatory liabilities. As of December 31, 2004, IPC had $148 million of such costs recorded as regulatory liabilities on its Consolidated Balance Sheet.

An ARO also exists for the reclamation of the Bridger Coal mine property, which is leased by Bridger Coal Company, an equity-method investee of IPC. As Bridger Coal Company has a March 31 fiscal year end, it adopted SFAS 143 on April 1, 2003. Upon adoption of SFAS 143, IPC did not record a net change in its investment in Bridger Coal Company, as Bridger Coal Company also is applying regulatory accounting, recording regulatory assets and liabilities instead of accretion, depreciation and gains or losses.

The following table presents the changes in the aggregate carrying amount of AROs (in thousands of dollars):

	2004		2003
Balance at beginning of year	$	7,140	$	-
Amount recorded on adoption		-		6,743
Accretion expense		421		397
Revisions in estimated cash flows		1,727		-
Balance at end of year	$	9,288	$	7,140

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of IDACORP, Inc.
Boise, Idaho

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the "Company") as of December 31, 2004 and 2003, 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, 2004. Our audits also included the consolidated financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As described in Note 1 to the consolidated financial statements, during 2004 the Company was required to consolidate two variable interest entities related to the adoption of Financial Accounting Standards Board Interpretation No. 46(R).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

DELOITTE & TOUCHE LLP

Boise, Idaho
March 8, 2005

Idaho Power Company
Consolidated Statements of Income

			Year Ended December 31,
			2004		2003		2002
			(thousands of dollars)
Operating Revenues:
	General business		$	635,835	$	670,969	$	772,035
	Off-system sales			121,148		71,573		55,031
	Other revenues			62,526		37,840		39,981
		Total operating revenues		819,509		780,382		867,047

Operating Expenses:
	Operation:
		Purchased power		195,642		150,980		142,102
		Fuel expense		103,261		99,898		102,871
		Power cost adjustment		39,184		70,762		170,489
		Other		194,073		156,030		150,884
	Maintenance			58,405		62,799		54,599
	Depreciation			100,855		97,650		93,609
	Taxes other than income taxes			19,090		20,753		19,953
		Total operating expenses		710,510		658,872		734,507

Income from Operations				108,999		121,510		132,540

Other Income (Expense):
	Allowance for equity funds used during construction			3,904		3,385		333
	Earnings of unconsolidated equity-method investments			12,313		11,336		12,065
	Other income			12,138		8,467		7,206
	Other expense			(9,074)		(8,326)		(7,876)
		Total other income		19,281		14,862		11,728

Interest Charges:
	Interest on long-term debt			50,317		54,645		51,127
	Other interest			3,980		4,718		9,190
	Allowance for borrowed funds used during
		construction		(2,953)		(3,310)		(2,375)
		Total interest charges		51,344		56,053		57,942

Income Before Income Taxes				76,936		80,319		86,326

Income Tax Expense (Benefit)				6,328		21,728		(2,594)

Net Income				70,608		58,591		88,920

	Dividends on preferred stock			4,823		3,430		4,587

Earnings on Common Stock			$	65,785	$	55,161	$	84,333

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets

Assets

				December 31,
				2004		2003
				(thousands of dollars)

Electric Plant:
	In service (at original cost)			$	3,324,816	$	3,220,228
		Accumulated provision for depreciation			(1,316,125)		(1,239,604)
		In service - Net			2,008,691		1,980,624
	Construction work in progress				151,652		96,086
	Held for future use				2,636		2,438
			Electric plant - Net		2,162,979		2,079,148

Investments and Other Property					86,086		49,739

Current Assets:
	Cash and cash equivalents				17,679		4,031
	Receivables:
		Customer			45,441		43,694
		Allowance for uncollectible accounts			(1,363)		(1,466)
		Notes			3,129		3,186
		Employee notes			3,523		3,347
		Related parties			1,298		1,143
		Other			5,253		4,848
	Accrued unbilled revenues				33,832		30,869
	Materials and supplies (at average cost)				26,065		19,755
	Fuel stock (at average cost)				6,539		6,228
	Prepayments				28,449		26,835
	Regulatory assets				5,510		6,269
			Total current assets		175,355		148,739

Deferred Debits:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,765		35,624
	Regulatory assets				433,271		427,760
	Employee notes				3,746		4,775
	Other				40,425		43,341
			Total deferred debits		544,792		543,085

	Total			$	2,969,212	$	2,820,711

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets

Capitalization and Liabilities

				December 31,
				2004		2003
					(thousands of dollars)
Capitalization:
	Common stock equity:
		Common stock, $2.50 par value (50,000,000 shares
			authorized; 39,150,812 shares outstanding	$	97,877	$	97,877
		Premium on capital stock			483,707		398,231
		Capital stock expense			(2,097)		(2,686)
		Retained earnings			340,107		320,735
		Accumulated other comprehensive income (loss)			(888)		(2,630)
			Total common stock equity		918,706		811,527

	Preferred stock				-		52,366

	Long-term debt				923,910		880,868
			Total capitalization		1,842,616		1,744,761

Current Liabilities:
	Long-term debt due within one year				60,000		50,077
	Accounts payable				74,642		45,529
	Notes and accounts payable to related parties				278		75
	Taxes accrued				42,228		55,383
	Interest accrued				13,743		12,893
	Deferred income taxes				5,510		6,179
	Other				18,103		20,985
			Total current liabilities		214,504		191,121

Deferred Credits:
	Deferred income taxes				542,829		546,205
	Regulatory liabilities				275,854		258,524
	Other				93,409		80,100
			Total deferred credits		912,092		884,829

Commitments and Contingencies

			Total	$	2,969,212	$	2,820,711

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization

				December 31,
				2004		%		2003		%
				(thousands of dollars)
Common Stock Equity:
	Common stock			$	97,877			$	97,877
	Premium on capital stock				483,707				398,231
	Capital stock expense				(2,097)				(2,686)
	Retained earnings				340,107				320,735
	Accumulated other comprehensive income (loss)				(888)				(2,630)
		Total common stock equity			918,706		50		811,527		47

Preferred Stock:
	4% preferred stock				-				12,366
	7.68% Series, serial preferred stock				-				15,000
	7.07% Series, serial preferred stock				-				25,000
		Total preferred stock			-		-		52,366		3

Long-Term Debt:
	First mortgage bonds:
		8 % Series due 2004			-				50,000
		5.83% Series due 2005			60,000				60,000
		7.38% Series due 2007			80,000				80,000
		7.20% Series due 2009			80,000				80,000
		6.60% Series due 2011			120,000				120,000
		4.75% Series due 2012			100,000				100,000
		4.25% Series due 2013			70,000				70,000
		6 % Series due 2032			100,000				100,000
		5.50% Series due 2033			70,000				70,000
		5.50% Series due 2034			50,000				-
		5.875% Series due 2034			55,000				-
			Total first mortgage bonds		785,000				730,000
		Amount due within one year			(60,000)				(50,000)
			Net first mortgage bonds		725,000				680,000

	Pollution control revenue bonds:
		6.05% Series 1996A due 2026			68,100				68,100
		Variable Rate Series 1996B due 2026			24,200				24,200
		Variable Rate Series 1996C due 2026			24,000				24,000
		Variable Rate Series 2000 due 2027			4,360				4,360
		Variable Auction Rate Series 2003 due 2024			49,800				49,800
			Total pollution control revenue bonds		170,460				170,460

	REA notes				-				1,105
		Amount due within one year			-				(77)
			Net REA notes		-				1,028

	American Falls bond guarantee				19,885				19,885
	Milner Dam note guarantee				11,700				11,700
	Unamortized premium/discount - Net				(3,135)				(2,205)
			Total long-term debt		923,910		50		880,868		50

Total Capitalization				$	1,842,616		100	$	1,744,761		100

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Cash Flows

				Year Ended December 31,
				2004		2003		2002
				(thousands of dollars)
Operating Activities:
	Net income			$	70,608	$	58,591	$	88,920
	Adjustments to reconcile net income to net cash provided by
	(used in) operating activities:
		Impairment of assets			9,075		-		-
		Depreciation and amortization			108,551		110,228		104,948
		Deferred taxes and investment tax credits			(19,992)		(44,221)		(81,511)
		Change in regulatory assets and liabilities			16,788		68,358		164,201
		Change in:
			Accounts receivable and prepayments		(3,846)		24,447		(2,521)
			Accounts payable		29,112		(7,147)		(23,009)
			Taxes receivable/accrued		(13,155)		(33,707)		97,335
			Other current assets		(4,220)		7,263		5,291
			Other current liabilities		(2,029)		(1,427)		5,980
		Other assets			140		(5,776)		5,276
		Other liabilities			6,753		10,119		6,720
		Net cash provided by operating activities			197,785		186,728		371,630

Investing Activities:
	Additions to utility plant				(190,286)		(148,246)		(128,318)
	Note receivable payment from parent				-		19,282		11,859
	Purchase of available-for-sale securities				(295,356)		(13,689)		(16,530)
	Sale of available-for-sale securities				266,331		14,040		6,815
	Other assets				(38)		685		2,217
		Net cash used in investing activities			(219,349)		(127,928)		(123,957)

Financing Activities:
	Issuance of long-term debt				105,000		189,800		200,000
	Retirement of long-term debt				(51,105)		(209,880)		(77,078)
	Retirement of preferred stock				(52,351)		(860)		(50,994)
	Sale of common stock to parent				-		39,987		-
	Dividends on common stock				(46,413)		(64,726)		(70,178)
	Dividends on preferred stock				(4,823)		(3,430)		(4,587)
	Decrease in short-term borrowings				-		(10,500)		(271,500)
	Capital contribution from parent				85,920		-		-
	Other assets				(1,145)		(7,450)		(3,745)
	Other liabilities				129		(409)		68
		Net cash provided by (used in) financing activities			35,212		(67,468)		(278,014)

Net increase (decrease) in cash and cash equivalents					13,648		(8,668)		(30,341)
Cash and cash equivalents at beginning of year					4,031		12,699		43,040

Cash and cash equivalents at end of year				$	17,679	$	4,031	$	12,699

Supplemental Disclosure of Cash Flow Information:
	Cash paid (received) during the year for:
		Income taxes paid to (received from) parent		$	39,190	$	99,879	$	(17,974)
		Interest (net of amount capitalized)			48,113		54,911		56,167

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Retained Earnings

		Year Ended December 31,
		2004		2003		2002
		(thousands of dollars)

Retained Earnings, Beginning of Year		$	320,735	$	330,300	$	316,856

Net Income			70,608		58,591		88,920

Dividends:
	Common stock		(46,413)		(64,726)		(70,178)
	Preferred stock		(4,823)		(3,430)		(4,587)

Preferred Stock Redemption			-		-		(711)

Retained Earnings, End of Year		$	340,107	$	320,735	$	330,300

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income

						Year Ended December 31,
						2004		2003		2002
						(thousands of dollars)

Net Income						$	70,608	$	58,591	$	88,920

Other Comprehensive Income (Loss):
	Unrealized gains (losses) on securities:
			Unrealized holding gains (losses) arising during the year,
					net of tax of $1,234, $2,963 and ($1,840)		2,057		4,982		(2,991)
			Reclassification adjustment for (gains) losses included
					in net income, net of tax of ($768), ($111) and $1,007		(1,195)		(173)		1,560
					Net unrealized gains (losses)		862		4,809		(1,431)
		Minimum pension liability adjustment, net of tax of $565, ($191)
				and ($1,265)			880		(330)		(1,959)

Total Comprehensive Income						$	72,350	$	63,070	$	85,530

The accompanying notes are an integral part of these statements.

IDAHO POWER COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The outstanding shares of IPC's common stock were exchanged on a share-for-share basis into common stock of IDACORP on October 1, 1998 and are no longer actively traded. IPC's preferred stock and debt securities were unaffected.

Except as modified below, the Notes to the Consolidated Financial Statements of IDACORP included in this 2004 Annual Report on Form 10-K are incorporated herein by reference insofar as they relate to IPC.

Note 1 - Summary of Significant Accounting Policies

Note 2 - Income Taxes

Note 4 - Preferred Stock of Idaho Power Company

Note 5 - Long-Term Debt

Note 7 - Notes Payable

Note 8 - Commitments and Contingencies

Note 10 - Benefit Plans

Note 11 - Property, Plant and Equipment and Jointly-Owned Projects

Note 13 - Regulatory Matters

Note 16 - Investments

Note 17 - Asset Retirement Obligations

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stock-Based Compensation
The following table illustrates the effect on net income if the fair value recognition provisions of SFAS 123 had been applied to stock-based employee compensation:

			2004		2003		2002
			(thousands of dollars)
Net income, as reported			$	70,608	$	58,591	$	88,920
Add: Stock-based employee compensation expense included in
	reported net income, net of related tax effects			276		(56)		(10)
Deduct: Total stock-based employee compensation expense determined
	under fair value based method for all awards ,net of related tax effects			977		1,073		1,837
		Pro forma net income	$	69,907	$	57,462	$	87,073

2. INCOME TAXES:

A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:

		2004		2003		2002
		(thousands of dollars)
Federal income tax expense at 35% statutory rate		$	26,928	$	28,112	$	30,214
Change in taxes resulting from:
	AFDC		(2,400)		(2,343)		(948)
	Investment tax credits		(3,295)		(3,397)		(3,179)
	Repair allowance		(2,450)		(2,450)		(2,450)
	Removal cost		(1,244)		(1,101)		(815)
	Pension accrual		1,237		2,456		(26)
	Capitalized overhead costs		(3,658)		(3,658)		(3,500)
	Regulatory tax liability		(16,457)		-		-
	Tax accounting method change		-		-		(31,162)
	Settlement of prior years tax returns		(1,398)		(8,908)		(2,600)
	State income taxes, net of federal benefit		4,100		3,973		3,946
	Depreciation		4,350		10,237		8,940
	Other, net		615		(1,193)		(1,014)
Total income tax expense (benefit)		$	6,328	$	21,728	$	(2,594)
	Effective tax rate		8.2%		27.1%		(3.0)%

The items comprising income tax expense are as follows:

			2004		2003		2002
			(thousands of dollars)
Income taxes currently payable:
	Federal		$	19,003	$	55,034	$	70,318
	State			7,317		10,915		8,599
		Total		26,320		65,949		78,917
Income taxes deferred:
	Federal			(15,488)		(35,166)		(75,600)
	State			(3,551)		(9,284)		(5,455)
		Total		(19,039)		(44,450)		(81,055)
Investment tax credits:
	Deferred			2,700		3,627		2,722
	Restored			(3,653)		(3,398)		(3,178)
		Total		(953)		229		(456)
Total income tax expense (benefit)			$	6,328	$	21,728	$	(2,594)

The components of IPC's net deferred tax liability are as follows:

			2004		2003
			(thousands of dollars)
Deferred tax assets:
	Regulatory liabilities		$	40,447	$	41,024
	Advances for construction			5,357		4,162
	Deferred compensation			12,324		9,385
	Other			14,584		12,329
		Total		72,712		66,900
Deferred tax liabilities:
	Property, plant and equipment			241,324		238,602
	Regulatory assets			344,220		330,833
	Conservation programs			6,972		8,310
	PCA			20,516		27,529
	Partnership investments			5,600		3,770
	Other			2,419		10,240
		Total		621,051		619,284

Net deferred tax liabilities			$	548,339	$	552,384

Amounts accrued for income taxes are payable to IPC's parent company, IDACORP, as IPC joins in the filing of IDACORP's federal and state consolidated income tax returns.

3. COMMON STOCK:

In December 2004, IDACORP contributed $86 million of additional equity to IPC. No additional shares of IPC common stock were issued in this transaction.

In December 2003, IPC issued 1,538,461 shares of $2.50 par value common stock to IDACORP for $40 million. Each share of IPC's common stock is entitled to one vote.

5. LONG-TERM DEBT:

IPC's $49.8 million Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total first mortgage bonds outstanding at December 31, 2004 to $834.8 million.

6. FAIR VALUE OF FINANCIAL INSTRUMENTS:

The estimated fair value of IPC's financial instruments has been determined 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 is based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.

	December 31, 2004				December 31, 2003
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
Assets:
Notes receivable	$	8,946	$	8,877	$	10,145	$	10,159
Investments		53,155		53,155		22,438		22,438

Liabilities:
Long-term debt	$	987,045	$	1,008,369	$	933,150	$	957,399

9. STOCK-BASED COMPENSATION:

The maximum number of shares available under the LTICP is 2,050,000. In 2004, 2003 and 2002, IDACORP granted to IPC employees 110,500, 343,000 and 230,000 stock options, respectively, with an exercise price equal to the market price of IDACORP's stock on the date of grant. In accordance with APB 25, no compensation costs have been recognized for the option awards.

Stock option transactions are summarized as follows:

		2004			2003			2002
			Weighted			Weighted			Weighted
		Number	average		Number	average		Number	average
		of	exercise		of	exercise		of	exercise
		shares	price		shares	price		shares	price
Outstanding beginning of year		889,800	$	32.50	594,000	$	38.33	364,000	$	37.59
	Granted	110,500		31.21	343,000		22.95	230,000		39.50
	Exercised	(4,200)		22.92	-		-	-		-
	Forfeited	(40,500)		32.27	(47,200)		36.42	-		-
Outstanding end of year		955,600	$	32.41	889,800	$	32.50	594,000	$	38.33

Exercisable		374,800	$	35.43	211,600	$	37.84	100,800	$	37.10

The following table summarizes information about stock options outstanding at December 31, 2004:

	Outstanding				Exercisable
				Weighted
		Weighted		average		Weighted
		average		remaining		average
	Number	exercise		contractual	Number	exercise
Exercise Price Ranges	of shares	price		life	of shares	price
$22.92 - $31.21	428,800	$	24.98	8.80 years	64,000	$	22.95
$35.81 - $40.31	526,800	$	38.45	6.29 years	310,800	$	38.00

Restricted stock and performance share awards are compensatory awards and IPC accrues compensation expense, which is charged to operations, based upon the market value of the granted shares. For 2004, 2003 and 2002, total compensation accrued under the Restricted Stock Plan was less than $1 million annually.

The following table summarizes restricted stock activity:

		2004			2003		2002
Shares outstanding - beginning of year		80,454			77,192		58,024
Shares granted		61,806			41,945		38,752
Shares forfeited		(24,014)			(1,889)		(132)
Shares issued		-			(36,794)		(19,452)
Shares outstanding - end of year		118,246			80,454		77,192
Weighted average fair value of current year stock
	grants on grant date	$	31.21	$		22.95	$	38.64

18. RELATED PARTY TRANSACTIONS:

IDACORP
In exchange for the transfer of Energy Marketing to IE in June 2001, IPC received a partnership interest in IE, which was then transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million. The notes receivable were due over periods of one to ten years, bore interest at IDACORP's overall variable short-term borrowing rate and were paid in full in 2003.

IPC performs corporate functions such as financial, legal and management services for IDACORP and its subsidiaries. IPC charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. IPC billed IDACORP $4 million, $3 million and $1 million in 2004, 2003 and 2002, respectively, for these services.

IDACORP Energy
In 2002, IPC paid IE approximately $2 million under the Electricity Supply Management Services Agreement. In August 2002, IPC and IE terminated the agreement eliminating all future payments. The FERC gave public notice of IPC's request to cancel the agreement and no comments on the request were filed by the due date.

The following table presents IPC's sales to and purchases from IE for the years ended December 31:

	2004		2003		2002
	(thousands of dollars)
Sales to IE	$	-	$	2,268	$	27,182
Purchases from IE		-		-		13,665

IDACOMM
IPC provides project management and engineering services to IDACOMM. IDACOMM also pays joint use fees to IPC. Total fees charged to IDACOMM were $0.3 million, $0.3 million and $1.1 million in 2004, 2003 and 2002, respectively.

Ida-West
IPC purchases all of the power generated by four of Ida-West's hydroelectric projects. IPC paid $7 million per year in 2004, 2003 and 2002.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have audited the accompanying consolidated balance sheets and statements of capitalization of Idaho Power Company and subsidiary (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the consolidated financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Idaho Power Company and subsidiary at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, 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
March 8, 2005

SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA:

The following unaudited information is presented for each quarter of 2004 and 2003 (in thousands of dollars except for per share amounts). In the opinion of each 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.

IDACORP, Inc.:

	Quarter Ended
	March 31		June 30		September 30		December 31

2004
Revenues	$	188,189	$	211,872	$	246,677	$	197,752
Income from operations		36,194		15,407		18,933		22,717
Income tax expense (benefit)		4,685		(3,379)		(20,886)		(5,191)
Net income		19,659		12,992		26,067		14,266
Earnings per share of common stock		0.51		0.34		0.68		0.37

2003
Revenues	$	211,928	$	200,276	$	239,228	$	171,570
Income from operations		11,434		14,000		47,974		10,654
Income tax benefit		-		-		(12,495)		(8,624)
Net income (loss)		(3,072)		(879)		46,775		3,754
Earnings (loss) per share of common stock		(0.08)		(0.02)		1.22		0.10

Idaho Power Company:

	Quarter Ended
	March 31		June 30		September 30		December 31

2004
Revenues	$	183,326	$	205,693	$	240,219	$	190,271
Income from operations		40,854		18,411		20,396		29,338
Income tax expense (benefit)		13,169		273		(13,981)		6,867
Net income		20,263		8,790		26,995		14,560
Dividends on preferred stock		854		853		3,116		-
Earnings on common stock		19,409		7,937		23,879		14,560

2003
Revenues	$	202,990	$	197,265	$	214,225	$	165,902
Income from operations		32,333		27,339		37,696		24,142
Income tax expense		7,893		2,457		11,133		245
Net income		14,581		12,633		15,955		15,422
Dividends on preferred stock		868		866		847		849
Earnings on common stock		13,713		11,767		15,108		14,573

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

(a) Disclosure controls and procedures:

IDACORP:

The Chief Executive Officer and Chief Financial Officer of IDACORP, based on their evaluation of IDACORP's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2004, have concluded that IDACORP's disclosure controls and procedures are effective.

IPC:

The Chief Executive Officer and Chief Financial Officer of IPC, based on their evaluation of IPC's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2004, have concluded that IPC's disclosure controls and procedures are effective.

(b) Internal control over financial reporting:

IDACORP:

Management's Annual Report On Internal Control Over Financial Reporting
The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company's principal executive and principal financial officers and effected by the company's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

IDACORP's management assessed the effectiveness of the company's internal control over financial reporting as of December 31, 2004. In making this assessment, the company's management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2004, IDACORP's internal control over financial reporting is effective based on those criteria.

IDACORP's independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2004 and issued a report, which appears on the next page and expresses an unqualified opinion on management's assessment and on the effectiveness of IDACORP's internal control over financial reporting as of December 31, 2004.

March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of IDACORP, Inc.
Boise, Idaho

We have audited management's assessment, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting, that IDACORP, Inc. and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company's adoption of Financial Accounting Standards Board Interpretation No. 46(R).

DELOITTE & TOUCHE LLP

Boise, Idaho
March 8, 2005

IPC:

Management's Annual Report on Internal Control Over Financial Reporting
The management of IPC is responsible for establishing and maintaining adequate internal control over financial reporting of IPC. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company's principal executive and principal financial officers and effected by the company's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

IPC's management assessed the effectiveness of the company's internal control over financial reporting as of December 31, 2004. In making this assessment, the company's management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2004, IPC's internal control over financial reporting is effective based on those criteria.

IPC's independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2004 and issued a report, which appears on the next page and expresses an unqualified opinion on management's assessment and on the effectiveness of IPC's internal control over financial reporting as of December 31, 2004.

March 8, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have audited management's assessment, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting, that Idaho Power Company and subsidiary (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2004 of the Company and our report dated March 8, 2005 expressed an unqualified opinion on those financial statements and financial statement schedule.

DELOITTE & TOUCHE LLP

Boise, Idaho
March 8, 2005

Changes in Internal Control Over Financial Reporting
Section 404 of the Sarbanes-Oxley Act of 2002 (SOX) and the rules issued thereunder require that as of December 31, 2004, IDACORP's and IPC's Chief Executive Officer and Chief Financial Officer assess the effectiveness of IDACORP's and IPC's internal control over financial reporting. This internal control report must include: (i) a statement of management's responsibility for establishing and maintaining adequate internal control over financial reporting, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of the company's internal control over financial reporting, (iii) management's assessment of the effectiveness of the company's internal control over financial reporting as of December 31, 2004, including a statement as to whether or not internal control over financial reporting is effective and (iv) a statement that the company's independent registered public accounting firm has issued an attestation report on management's assessment of internal control over financial reporting. To satisfy this requirement, IDACORP and IPC developed and implemented a SOX 404 process, which includes steps to (i) identify significant accounts and disclosures and related financial statement assertions, (ii) document the existing control activities for each significant account, and disclosure and related assertions, (iii) test each of those control activities, (iv) identify control deficiencies, if any, (v) remediate the identified control deficiencies and (vi) test the remediated control activity to ensure that the identified control deficiencies have been properly remediated.

IDACORP and IPC have completed their SOX 404 process for 2004. Set forth above is each company's Management's Annual Report on Internal Control Over Financial Reporting, stating that as of December 31, 2004 each company's internal control over financial reporting is effective, and each company's independent public accounting firm's report, which expresses an unqualified opinion on management's assessment and on the effectiveness of internal control over financial reporting as of December 31, 2004.

ITEM 9B. OTHER INFORMATION

None

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The portion of IDACORP's definitive proxy statement appearing under the captions "Election of Directors - Nominees For Election - Terms Expire 2008," "Continuing Directors - Terms Expire 2007," "Continuing Directors - Terms Expire 2006," "The Board of Directors and Committees - Committees - Audit Committee," "Section 16(a) Beneficial Ownership Reporting Compliance" and "Corporate Governance - Code of Ethics," to be filed pursuant to Regulation 14A for the 2005 Annual Meeting of Shareholders to be held on May 19, 2005 is hereby incorporated by reference.

ITEM 11. EXECUTIVE COMPENSATION

The portion of IDACORP's definitive proxy statement appearing under the caption "Compensation of Directors and Executive Officers" (except the Report of the Compensation Committee and the Performance Graph) to be filed pursuant to Regulation 14A for the 2005 Annual Meeting of Shareholders to be held on May 19, 2005 is hereby incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The portion of IDACORP's definitive proxy statement appearing under the caption "Security Ownership of Directors and Executive Officers" and the Regulation S-K, Item 201(d) information appearing under the caption "Amendment of the IDACORP Long-Term Incentive and Compensation Plan to Increase Number of Shares Subject to the Plan" to be filed pursuant to Regulation 14A for the 2005 Annual Meeting of Shareholders to be held on May 19, 2005 is hereby incorporated by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

IDACORP:

The portion of IDACORP's definitive proxy statement appearing under the caption "Independent Accountant Billings" in the proxy statement to be filed pursuant to Regulation 14A for the 2005 Annual Meeting of Shareholders to be held on May 19, 2005 is hereby incorporated by reference.

IPC:

The following table presents fees billed for professional services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, Deloitte & Touche), for the fiscal years ended December 31, 2004 and 2003. The amounts presented below reflect allocations from IDACORP for IPC's portion of the fees, as well as amounts billed directly to IPC.

		2004		2003
Audit fees		$	760,496	$	306,485
Audit-related fees ⁽¹⁾			74,243		120,455
Tax fees ⁽²⁾			140,472		91,170
All other fees			-		-
Total		$	975,211	$	518,110

⁽¹⁾	Includes fees for audits of IPC's benefit plans and Sarbanes-Oxley Section 404 readiness assistance.
⁽²⁾	Includes fees for tax compliance and tax consulting in connection with IRS account analysis.

Policy on Audit Committee Pre-Approval
IPC and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, the Audit Committee has established a pre-approval policy in accordance with applicable securities rules. All fees were pre-approved by the Audit Committee in 2004.

On February 4, 2004, the IPC Audit Committee adopted a policy for pre-approval of services to be performed by the company's independent public accounting firm.

In addition to the audits of IPC's consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax and other services. The Audit Committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm's independence. The services that the Audit Committee will consider include audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed audit and audit-related services. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to IPC's Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval.

In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations and whether the nature of the engagement and the related fees are consistent with the following principles, as stated in the SEC's adopting release for the rules on auditor independence:

the independent public accounting firm cannot function in the role of management of IPC;

the independent public accounting firm cannot audit its own work; and

the independent public accounting firm cannot serve in any advocacy role on behalf of IPC.

The appendices to the pre-approval policy describe the specific audit, audit related, tax and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1) and (2) Please refer to Part II, Item 8 - "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules.

(3) Exhibits.

*Previously Filed and Incorporated Herein by Reference

Exhibit	File Number	As Exhibit

*2	333-48031	2	Agreement and Plan of Exchange between IDACORP, Inc., and IPC dated as of February 2, 1998.

*3(a)	33-00440	4(a)(xiii)	Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 30, 1989.

*3(a)(i)	33-65720	4(a)(ii)	Statement of Resolution Establishing Terms of Flexible Auction Series A, Serial Preferred Stock, Without Par Value (cumulative stated value of $100,000 per share) of IPC, as filed with the Secretary of State of Idaho on November 5, 1991.

*3(a)(ii)	33-65720	4(a)(iii)	Statement of Resolution Establishing Terms of 7.07% Serial Preferred Stock, Without Par Value (cumulative stated value of $100 per share) of IPC, as filed with the Secretary of State of Idaho on June 30, 1993.

*3(a)(iii)	1-3198 Form 8-K dated January 20, 2005	3.3	Articles of Amendment to Restated Articles of Incorporation of IPC, as amended, as filed with the Secretary of State of Idaho on January 21, 2005.

*3(b)	1-3198 Form 8-K dated January 20, 2005	3.2	Amended Bylaws of IPC, amended on January 20, 2005 and presently in effect.

*3(c)	33-56071	3(d)	Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998.

*3(d)	333-64737	3.1	Articles of Incorporation of IDACORP, Inc.



*3(d)(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(d)(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(e)	1-14456 Form 8-K dated January 20, 2005	3.1	Amended Bylaws of IDACORP, Inc., amended on January 20, 2005 and presently in effect.

*4(a)(i)	2-3413	B-2	Mortgage and Deed of Trust, dated as of October 1, 1937, between IPC and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) and R. G. Page, as Trustees.

*4(a)(ii)			IPC Supplemental Indentures to Mortgage and Deed of Trust:

			Number		Dated
	1-MD	B-2-a	First		July 1, 1939
	2-5395	7-a-3	Second		November 15, 1943
	2-7237	7-a-4	Third		February 1, 1947
	2-7502	7-a-5	Fourth		May 1, 1948
	2-8398	7-a-6	Fifth		November 1, 1949
	2-8973	7-a-7	Sixth		October 1, 1951
	2-12941	2-C-8	Seventh		January 1, 1957
	2-13688	4-J	Eighth		July 15, 1957
	2-13689	4-K	Ninth		November 15, 1957
	2-14245	4-L	Tenth		April 1, 1958
	2-14366	2-L	Eleventh		October 15, 1958
	2-14935	4-N	Twelfth		May 15, 1959
	2-18976	4-O	Thirteenth		November 15, 1960
	2-18977	4-Q	Fourteenth		November 1, 1961
	2-22988	4-B-16	Fifteenth		September 15, 1964
	2-24578	4-B-17	Sixteenth		April 1, 1966
	2-25479	4-B-18	Seventeenth		October 1, 1966
	2-45260	2(c)	Eighteenth		September 1, 1972
	2-49854	2(c)	Nineteenth		January 15, 1974
	2-51722	2(c)(i)	Twentieth		August 1, 1974
	2-51722	2(c)(ii)	Twenty-first		October 15, 1974
	2-57374	2(c)	Twenty-second		November 15, 1976
	2-62035	2(c)	Twenty-third		August 15, 1978
	33-34222	4(d)(iii)	Twenty-fourth		September 1, 1979
	33-34222	4(d)(iv)	Twenty-fifth		November 1, 1981
	33-34222	4(d)(v)	Twenty-sixth		May 1, 1982
	33-34222	4(d)(vi)	Twenty-seventh		May 1, 1986
	33-00440	4(c)(iv)	Twenty-eighth		June 30, 1989
	33-34222	4(d)(vii)	Twenty-ninth		January 1, 1990
	33-65720	4(d)(iii)	Thirtieth		January 1, 1991
	33-65720	4(d)(iv)	Thirty-first		August 15, 1991
	33-65720	4(d)(v)	Thirty-second		March 15, 1992
	33-65720	4(d)(vi)	Thirty-third		April 1, 1993
	1-3198 Form 8-K Dated 12/17/93	4	Thirty-fourth		December 1, 1993

	1-3198 Form 8-K Dated 11/21/00	4	Thirty-fifth		November 1, 2000

	1-3198 Form 8-K Dated 9/27/01	4	Thirty-sixth		October 1, 2001
	1-3198 Form 8-K Dated 4/15/03	4	Thirty-seventh		April 1, 2003
	1-3198 Form 10-Q Dated 6/30/03	4(a)(iii)	Thirty-eighth		May 15, 2003
	1-3198 Form 10-Q for the quarter ended 9/30/03	4(a)(iii)	Thirty-ninth		October 1, 2003

*4(b)	1-3198 Form 10-Q for the quarter ended 6/30/00	4(b)	Instruments relating to IPC American Falls bond guarantee (see Exhibit 10(c)).

*4(c)(i)	33-65720	4(f)	Agreement of IPC to furnish certain debt instruments.

*4(c)(ii)	1-14465 Form 10-Q for the quarter ended 9/30/03	4(c)(ii)	Agreement of IDACORP, Inc. to furnish certain debt instruments.

*4(d)	33-00440	2(a)(iii)	Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation.

*4(e)	1-14465 Form 8-K dated September 15, 1998	4	Rights Agreement, dated as of September 10, 1998, between IDACORP, Inc. and Wells Fargo Bank, N.A., as successor to The Bank of New York, as Rights Agent.

*4(f)	1-14465 Form 8-K dated February 28, 2001	4.1	Indenture for Senior Debt Securities dated as of February 1, 2001, between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee.

*4(g)	1-14465 Form 8-K dated February 28, 2001	4.2	First Supplemental Indenture dated as of February 1, 2001 to Indenture for Senior Debt Securities dated as of February 1, 2001 between IDACORP, Inc. and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee.

*4(h)	333-67748	4.13	Indenture for Debt Securities dated as of August 1, 2001 between Idaho Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee.

*10(a)	2-49584	5(b)	Agreements, dated September 22, 1969, between IPC and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project.
*10(a)(i)	2-51762	5(c)	Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10(a).

*10(b)	2-49584	5(c)	Agreement, dated as of October 11, 1973, between IPC and Pacific Power & Light Company.

*10(c)	1-3198 Form 10-Q for the quarter ended 6/30/00	10(c)	Guaranty Agreement, dated April 11, 2000, between IPC and Bank One Trust Company, N.A., as Trustee, relating to $19,885,000 American Falls Replacement Dam Refinancing Bonds of the American Falls Reservoir District, Idaho.

*10(d)	2-62034	5(r)	Guaranty Agreement, dated as of August 30, 1974, between IPC and Pacific Power & Light Company.

*10(e)	2-56513	5(i)	Letter Agreement, dated January 23, 1976, between IPC and Portland General Electric Company.

*10(e)(i)	2-62034	5(s)	Agreement for Construction, Ownership and Operation of the Number One Boardman Station on Carty Reservoir, dated as of October 15, 1976, between Portland General Electric Company and IPC.

*10(e)(ii)	2-62034	5(t)	Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(e).

*10(e)(iii)	2-62034	5(u)	Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(e).

*10(e)(iv)	2-62034	5(v)	Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10(e).

*10(e)(v)	2-62034	5(w)	Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(e).

*10(e)(vi)	2-68574	5(x)	Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(e).

*10(f)	2-68574	5(z)	Participation Agreement, dated September 1, 1979, relating to the sale and leaseback of coal handling facilities at the Number One Boardman Station on Carty Reservoir.

*10(g)	2-64910	5(y)	Agreements for the Operation, Construction and Ownership of the North Valmy Power Plant Project, dated December 12, 1978, between Sierra Pacific Power Company and IPC.

*10(h)(i) 1	1-14465 1-3198 Form 10-Q for the quarter ended 3/31/04	10(h)(i)	The Revised Security Plan for Senior Management Employees - a non-qualified, deferred compensation plan, amended and restated effective November 20, 2003.


1 Compensatory plan



*10(h)(ii) 1	1-14465 1-3198 Form 8-K dated January 20, 2005	10.2	2005 IDACORP, Inc. Executive Incentive Plan.

*10(h)(iii) 1	1-3198 Form 10-K for 1994	10(n)(iii)	The 1994 Restricted Stock Plan for officers and key executives of IDACORP, Inc. and IPC effective July 1, 1994.

*10(h)(iv) 1	1-14465 1-3198 Form 10-Q for the quarter ended 9/30/04	10(h)(iv)	Form of Restricted Stock Award Agreement.

*10(h)(v) 1	1-14465 1-3198 Form 10-Q for the quarter ended 9/30/04	10(h)(v)	Form of Performance Share Award Agreement.

*10(h)(vi) 1	1-14465 1-3198 Form 10-K for 1998	10(h)(iv)	The Revised Security Plan for Board of Directors - a non-qualified, deferred compensation plan effective August 1, 1996, revised March 8, 1999, as amended.

*10(h)(vii) 1	1-14465 1-3198 Form 8-K dated 1/20/05	10.9	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as amended on January 20, 2005.

*10(h)(viii)	1-14465 Form 10-Q for the quarter ended 9/30/99	10(h)	Form of Change in Control Agreement between IDACORP, Inc. and Jan B. Packwood, J. LaMont Keen, James C. Miller, Darrel T. Anderson, Thomas R. Saldin and A. Bryan Kearney.

*10(h)(ix) 1	1-14465 1-3198 Form 10-Q for the quarter ended 3/31/02	10(i) 10(h)(ix)	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended.

*10(h)(x) 1	1-14465 1-3198 Form 10-Q for the quarter ended 9/30/04	10(h)(x)	Form of Stock Option Award Agreement.

*10(h)(xi) 1	1-14465 1-3198 Form 10-Q for the quarter ended 6/30/04	10(h)(viii)	Form of Officer Indemnification Agreement as signed by all Officers of IDACORP, Inc. and IPC.



1 Compensatory plan


*10(h)(xii) 1	1-14465 1-3198 Form 10-Q for the quarter ended 6/30/04	10(h)(ix)	Form of Director Indemnification Agreement as signed by all Directors of IDACORP, Inc.

*10(h)(xiii) 1	1-14465 1-3198 Form 8-K dated November 24, 2004	10	Employment Agreement, dated November 24, 2004, by and between IDACORP, Inc. and Luci K. McDonald.

*10(h)(xiv) 1	1-14465 1-3198 Form 8-K dated December 29, 2004	10	Consulting agreement, dated as of January 3, 2005, by and between Robert W. Stahman and IPC, including its parent IDACORP, Inc. and all subsidiaries and affiliates.

*10(h)(xv)	1-14465 1-3198 Form 8-K dated January 20, 2005	10.1	IDACORP, Inc. and Idaho Power Company NEO 2005 Base Compensation Table.

*10(h)(xvi)	1-14465 1-3198 Form 8-K dated January 20, 2005	10.3	2005 IDACORP, Inc. Executive Incentive Plan NEO Award Opportunity Chart.

*10(h)(xvii)	1-14465 1-3198 Form 8-K dated January 20, 2005	10.4	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan-Form of Restricted Stock Award Agreement (time vesting).

*10(h)(xviii)	1-14465 1-3198 Form 8-K dated January 20, 2005	10.5	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan-Form of Restricted Stock Award Agreement (performance vesting).

*10(h)(xix) 1	1-14465 1-3198 Form 8-K dated January 20, 2005	10.6	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan Restricted Stock Awards (time vesting) to NEOs Chart.

*10(h)(xx) 1	1-14465 1-3198 Form 8-K dated January 20, 2005	10.7	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan Restricted Stock Awards (performance vesting) to NEOs Chart.

*10(h)(xxi) 1	1-14465 1-3198 Form 8-K dated January 20, 2005	10.8	IDACORP, Inc. and Idaho Power Company 2005 Compensation for Non-Employee Directors of the Board of Directors.

*10(h)(xxii) 1	1-14465 1-3198 Form 8-K dated January 20, 2005	10.9	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended on January 20, 2005.


1 Compensatory plan
*10(h)(xxiii) 1	1-14465 1-3198 Form 8-K dated January 20, 2005	10.10	Jan B. Packwood 2005 Restricted Stock Award Agreement.

10(h)(xxiv)			Offer of employment letter dated July 9, 2004, to Thomas R. Saldin from IDACORP, Inc.

*10(h)(xxv) 1	1-14465 1-3198 Form 8-K dated February 17, 2005	10.1	IDACORP, Inc. 2004 Executive Incentive Plan.

*10(h)(xxvi)	1-14465 1-3198 Form 8-K dated February 17, 2005	10.2	IDACORP, Inc. 2004 Executive Incentive Plan NEO Incentive Chart.

*10(i)	33-65720	10(h)	Framework Agreement, dated October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights.

*10(i)(i)	33-65720	10(h)(i)	Agreement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i).

*10(i)(ii)	33-65720	10(h)(ii)	Contract to Implement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i).

*10(j)	33-65720	10(m)	Agreement Regarding the Ownership, Construction, Operation and Maintenance of the Milner Hydroelectric Project (FERC No. 2899), dated January 22, 1990, between IPC and the Twin Falls Canal Company and the Northside Canal Company Limited.

*10(j)(i)	33-65720	10(m)(i)	Guaranty Agreement, dated February 10, 1992, between IPC and New York Life Insurance Company, as Note Purchaser, relating to $11,700,000 Guaranteed Notes due 2017 of Milner Dam Inc.

*10(k)	1-3198 Form 10-Q for the quarter ended 6/30/03	10(k)	Power Purchase Agreement between IPC and PPL Montana, LLC, dated March 1, 2003 and Revised Confirmation Agreement dated May 9, 2003.

12			Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12(a)			Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12(b)			Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.)


1 Compensatory plan

12(c)			Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.)

12(d)			Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IPC)

12 (e)			Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC)

21			Subsidiaries of IDACORP, Inc..

23			Consent of Independent Registered Public
				Accounting Firm.

31(a)			IDACORP, Inc. Rule 13a-14(a) certification.

31(b)			IDACORP, Inc. Rule 13a-14(a) certification.

31(c)			IPC Rule 13a-14(a) certification.

31(d)			IPC Rule 13a-14(a) certification.

32(a)			IDACORP, Inc. Section 1350 certification.

32(b)			IPC Section 1350 certification.

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF INCOME

				Year Ended December 31,
				2004		2003		2002
				(thousands of dollars)
Income:
	Equity in income of subsidiaries			$	76,482	$	48,163	$	63,417
	Other income				535		2,309		4,981
			Total income		77,017		50,472		68,398

Expenses:
	Operating expenses				5,782		5,340		4,564
	Interest expense				1,221		1,088		3,550
	Other expense				994		1,570		2,221
		Total expenses			7,997		7,998		10,335

Income Before Income Taxes					69,020		42,474		58,063

Income Tax Benefit					(3,963)		(4,104)		(3,609)

Net Income				$	72,983	$	46,578	$	61,672

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

					December 31,
					2004			2003
					(thousands of dollars)
Assets

Current Assets:
	Cash and cash equivalents				$	2,637		$	60,921
	Receivables					1,467			1,642
	Taxes receivable					-			5,106
	Deferred income taxes					28,211			10,021
	Other					692			678
			Total current assets			33,007			78,368

Investment in subsidiaries						1,033,141			900,682

Other Assets
	Intercompany notes receivable					35,753			48,160
	Other					1,396			570
		Total other assets				37,149			48,730

				Total	$	1,103,297	$		1,027,780



Liabilities and Shareholders' Equity

Current Liabilities:
	Notes payable				$	35,400		$	93,650
	Accounts payable					3,127			13,757
	Taxes accrued					4,242			-
	Other					1			17
			Total current liabilities			42,770			107,424

Other Liabilities:
	Intercompany notes payable					51,537			55,860
	Other					704			215
		Total other liabilities				52,241			56,075

Shareholders' Equity						1,008,286			864,281

	Total				$	1,103,297	$		1,02,780

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

			Year Ended December 31,
			2004		2003		2002
			(thousands of dollars)

Operating Activities:
	Net cash provided by (used in) operating activities		$	23,958	$	131,533	$	64,888

Investing Activities:
	Contributions to subsidiaries			(100,456)		(40,237)		(566)
	Distributions from subsidiaries			-		77,792		-
	Change in intercompany notes receivable			12,407		66,286		(45,575)
	Other			(53)		158		191
		Net cash provided by (used in) investing activities		(88,102)		103,999		(45,950)

Financing Activities:
	Issuance of common stock			115,690		4,123		15,770
	Dividends on common stock			(45,837)		(64,726)		(70,178)
	Increase (decrease) in short-term borrowings			(58,250)		(72,050)		85,200
	Change in intercompany notes payable			(4,323)		(41,025)		(49,730)
	Other			(1,420)		(1,227)		(1,247)
		Net cash provided by (used in) financing activities		5,860		(174,905)		(20,185)

Net increase (decrease) in cash and cash equivalents				(58,284)		60,627		(1,247)

Cash and cash equivalents at beginning of year				60,921		294		1,541

Cash and cash equivalents at end of year			$	2,637	$	60,921	$	294

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Pursuant to rules and regulations of the Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2004 Form 10-K, Part II, Item 8.

Accounting for subsidiaries
IDACORP has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements.

IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2004, 2003 and 2002

Column A				Column B		Column C					Column D			Column E
						Additions
								Charged
				Balance at		Charged		(Credited)							Balance at
				Beginning		to		to Other			Deductions				End
Classification				of Period		Income		Accounts			(1)				of Period
				(thousands of dollars)

2004:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	43,210	$	3,010	$	-	$		3,112	$			43,108
		Reserve for uncollectible notes			2,578		-		-			-				2,578
Other Reserves:
	Rate refunds				1,514		-		-			1,114				400
	Injuries and damages reserve				831		1,801		-			835				1,797
	Miscellaneous operating reserves				61		-		-			26				35

2003:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	43,311	$	3,958	$	-	$		4,059	$			43,210
		Reserve for uncollectible notes			-		2,578		-			-				2,578
Other Reserves:
	Rate refunds				-		1,514		-			-				1,514
	Injuries and damages reserve				1,936		111		-			1,216				831
	Miscellaneous operating reserves				-		61		-			-				61

2002:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	42,529	$	5,415	$	-	$		4,633	$			43,311
Other Reserves:
	Injuries and damages reserve				1,500		(255)		719			28				1,936
	Miscellaneous operating reserves				1,286		-		(250)			1,036				-

Notes:			(1) Represents deductions from the reserves for purposes for which the reserves were created.

IDAHO POWER COMPANY
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2004, 2003 and 2002

Column A				Column B		Column C					Column D			Column E
						Additions
								Charged
				Balance at		Charged		(Credited)						Balance at
				Beginning		to		to Other			Deductions			End
Classification				of Period		Income		Accounts			(1)			of Period
				(thousands of dollars)

2004:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	1,466	$	3,010	$	-	$		3,113	$		1,363
Other Reserves:
	Rate refunds				1,514		-		-			1,114			400
	Injuries and damages reserve				831		1,801		-			835			1,797
	Miscellaneous operating reserves				61		-		-			26			35

2003:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	1,566	$	3,958	$	-	$		4,058	$		1,466
Other Reserves:
	Rate refunds				-		1,514		-			-			1,514
	Injuries and damages reserve				1,936		111		-			1,216			831
	Miscellaneous operating reserves				-		61		-			-			61

2002:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	1,500	$	4,699	$	-	$		4,633	$		1,566
Other Reserves:
	Injuries and damages reserve				1,500		(255)		719			28			1,936
	Miscellaneous operating reserves				1,286		-		(250)			1,036			-

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 9, 2005

By: /s/Jan B. Packwood
Jan B. Packwood
President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By:	/s/Jon H. Miller		/s/	Chairman of the Board	March 9, 2005
	Jon H. Miller


By:	/s/Jan B. Packwood		/s/	President and Chief Executive	"
	Jan B. Packwood			Officer and Director

By:	/s/J. LaMont Keen
	J. LaMont Keen			Executive Vice President	"
				and Director

By:	/s/Darrel T. Anderson		/s/	Senior Vice President - Administrative	"
	Darrel T. Anderson			Services and Chief Financial Officer
				(Principal Financial Officer)
				(Principal Accounting Officer)

By:	/s/Rotchford L. Barker	By:		/s/Joan H. Smith	"
	Rotchford L. Barker			Joan H. Smith
	Director			Director

By:	/s/Gary G. Michael	By:		/s/Robert A. Tinstman	"
	Gary G. Michael			Robert A. Tinstman
	Director			Director

By:	/s/Peter S. O'Neill	By:		/s/Thomas J. Wilford	"
	Peter S. O'Neill			Thomas J. Wilford
	Director			Director

By:	/s/Richard G. Reiten	By:			"
	Richard G. Reiten			Jack K. Lemley
	Director			Director

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

IDAHO POWER COMPANY
(Registrant)

March 9, 2005

By: /s/J. LaMont Keen
J. LaMont Keen
President and Chief Operating Officer

By:	/s/Jon H. Miller			Chairman of the Board	March 9, 2005
	Jon H. Miller


By:	/s/Jan B. Packwood			Chief Executive Officer	"
	Jan B. Packwood			and Director


By:	/s/J. LaMont Keen			President and Chief Operating	"
By:	J. LaMont Keen			Officer and Director


By:	/s/Darrel T. Anderson		/s/	Senior Vice President - Administrative	"
	Darrel T. Anderson			Services and Chief Financial Officer
				(Principal Financial Officer)
				(Principal Accounting Officer)

By:	/s/Rotchord L. Barker	By:		/s/Joan H. Smith	"
	Rotchford L. Barker			Joan H. Smith
	Director			Director

By:	/s/Gary G. Michael	By:		/s/Robert A. Tinstman	"
	Gary G. Michael			Robert A. Tinstman
	Director			Director

By:	/s/Peter S. O'Neill	By:		/s/Thomas J. Wilford	"
	Peter S. O'Neill			Thomas J. Wilford
	Director			Director

By:	/s/Richard G. Reiten	By:			"
	Richard G. Reiten			Jack K. Lemley
	Director			Director

EXHIBIT INDEX


Exhibit Number


10(h)(xxiv)		Offer of employment letter dated July 9, 2004, to Thomas R. Saldin from IDACORP, Inc.

12		Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12(a)		Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges.
		(IDACORP, Inc.)

12(b)		Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and
		Preferred Dividend Requirements. (IDACORP, Inc.)

12(c)		Statements Re: Computation of Supplemental Ratio of Earnings to Combined Fixed
		Charges and Preferred Dividend Requirements. (IDACORP, Inc.)

12(d)		Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IPC)

12(e)		Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC)

21		Subsidiaries of IDACORP, Inc.

23		Consent of Independent Registered Public Accounting Firm.

31(a)		Rule 13a-14(a) certification.

31(b)		Rule 13a-14(a) certification.

31(c)		Rule 13a-14(a) certification.

31(d)		Rule 13a-14(a) certification.

32(a)		Section 1350 certification.

32(b)		Section 1350 certification.

		Exact name of registrants as specified in
Commission		their charters, address of principal executive	IRS Employer
File Number		offices, zip code and telephone number	Identification Number
1-14465		IDACORP, Inc.	82-0505802
1-3198		Idaho Power Company	82-0130980
		1221 W. Idaho Street
		Boise, ID 83702-5627
		(208) 388-2200
State of incorporation: Idaho
Websites: www.idacorpinc.com
www.idahopower.com
				Name of exchange on
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:				which registered
IDACORP, Inc.:	Common Stock, without par value			New York and Pacific
	Preferred Share Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company:	Preferred Stock

Documents Incorporated by Reference:

Part III, Items 10 - 14	Portions of IDACORP, Inc.'s definitive proxy statement to be filed pursuant to Regulation 14A for the
	2005 Annual Meeting of Shareholders to be held on May 19, 2005.

TABLE OF CONTENTS
				Page
Part I

	Item 1.	Business		1-11
	Item 2.	Properties		11-12
	Item 3.	Legal Proceedings		12
	Item 4.	Submission of Matters to a Vote of Security Holders		12

	Executive Officers of the Registrant			13

Part II

	Item 5.	Market for Registrant's Common Equity, Related Stockholder
			Matters and Issuer Purchases of Equity Securities	14
	Item 6.	Selected Financial Data		15
	Item 7.	Management's Discussion and Analysis of Financial Condition and
			Results of Operations	15-56
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		56-57
	Item 8.	Financial Statements and Supplementary Data		58-112
	Item 9.	Changes in and Disagreements with Accountants on Accounting and
			Financial Disclosure	113
	Item 9A.	Controls and Procedures		113-117
	Item 9B.	Other Information		117

Part III

	Item 10.	Directors and Executive Officers of the Registrant*		117
	Item 11.	Executive Compensation*		117
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related
			Stockholder Matters*	117
	Item 13.	Certain Relationships and Related Transactions*		117
	Item 14.	Principal Accountant Fees and Services*		118-119

Part IV

	Item 15.	Exhibits and Financial Statement Schedules		119-132

	Signatures			133-134



	*IDACORP, Inc. information is incorporated by reference to IDACORP, Inc.'s definitive proxy statement for
	the 2005 Annual Meeting of Shareholders.

X		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2004

IDACORP, Inc.:	42,217,017
Idaho Power Company:	39,150,812 all held by IDACORP, Inc.

COMMONLY USED TERMS

AFDC	-	Allowance for Funds Used During Construction
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CSPP	-	Cogeneration and Small Power Production
EPS	-	Earnings per share
ESA	-	Endangered Species Act
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
Fitch	-	Fitch, Inc.
FSP	-	Financial Accounting Standards Board Staff Position
GAAP	-	Accounting Principles Generally Accepted in the United States of America
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
MD&A	-	Management's Discussion and Analysis of Financial Condition and Results of Operations
Moody's	-	Moody's Investors Service
MW	-	Megawatt
MWh	-	Megawatt-hour
NEPA	-	National Environmental Policy Act of 1996
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PM&E	-	Protection, Mitigation and Enhancement
PURPA	-	Public Utilities Regulatory Policy Act of 1978
REA	-	Rural Electrification Administration
RFP	-	Request for Proposal
RTO	-	Regional Transmission Organization
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

Quarter Ended