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

IDACORP's other operating subsidiaries include:

IdaTech - - developer of integrated fuel cell systems;

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

Velocitus - - commercial and residential Internet service provider;

IDACOMM - - provider of telecommunications services;

Ida-West Energy (Ida-West) - developer and manager of independent power projects; and

IDACORP Energy (IE) - marketer of electricity and natural gas.

IE is in the late stages of winding down its operations. In 2003, IDACORP decided that Ida-West would also wind down its operations, as discussed in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Ida-West."

During 2003, IDACORP refocused 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 revised 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 federal income tax credits, remains a key component of the revised corporate strategy.

At December 31, 2003, IDACORP had 1,861 full-time employees. Of these employees, 1,713 were employed by IPC.

IDACORP has identified three reportable business segments: the regulated utility operations of IPC, the energy marketing activities of IE and IFS. IPC, IE and IFS contributed $55 million, ($10) million and $10 million to consolidated net income, respectively, in 2003. IE's 2003 results include earnings from the August sale of its forward book of electricity trading contracts, which was the last major step in the wind down of energy marketing that began in 2002. Financial information relating to amounts of sales, revenue, net income and total assets of IDACORP's operating segments is presented in Note 12 to IDACORP's Consolidated Financial Statements and below in "Utility Operations," "Energy Marketing" and "IFS."

IDACORP and IPC make available free of charge their Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 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 website at www.idacorpinc.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 20,000 square mile area in southern Idaho and eastern Oregon, with an estimated population of 883,000. 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 25 counties in Idaho and three counties in Oregon. As of December 31, 2003, IPC supplied electric energy to approximately 427,000 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. 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 snowpack in the mountains upstream of IPC's hydroelectric facilities, precipitation and other weather and streamflow 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 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, lumber, beet sugar refining and the skiing industry. FMC/Astaris, previously IPC's largest volume customer, closed its Pocatello, Idaho manufacturing plant in late 2001. IPC entered into a load reduction agreement with FMC/Astaris in 2001. See further discussion of FMC/Astaris in Part II, Item 7 - "MD&A - REGULATORY ISSUES - FMC/Astaris Settlement Agreement."

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, OPUC and the Public Service Commission of Wyoming as to the issuance of securities. IPC is subject to the provisions of the Federal Power Act (FPA) as a "licensee" and "public utility" as therein defined. IPC's retail rates are established under the jurisdiction of the state regulatory 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.

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

The State of Oregon has a Hydroelectric Act providing for licensing of hydroelectric projects in that state. IPC's Brownlee, Oxbow and Hells Canyon facilities are on the Snake River where it forms the boundary between Idaho and Oregon and occupy land located in both states. With respect to project property located in Oregon, these facilities are subject to the Oregon Hydroelectric Act. IPC has obtained Oregon licenses for these facilities and these licenses are not in conflict with the FPA or IPC's FERC license (see Item 2 - "Properties").

Rates
The rates IPC charges to its general business customers are determined by the IPUC and OPUC. Approximately 96 percent of IPC's general business revenue comes from customers in Idaho. The rates charged to these customers are adjusted annually by a Power Cost Adjustment (PCA), a mechanism that provides for annual adjustment to the rates charged to IPC's Idaho retail customers. These adjustments, which take effect in May, are based on forecasts of net power supply costs (fuel and purchased power less sales for resale) and the true-up of the prior year's forecast. The PCA adjusts rates to reflect the changes in costs incurred by IPC to supply power. Throughout the year, IPC compares its actual power supply costs to the amounts it is recovering in rates. Most, but not all, of this difference is deferred and included in the calculation of rates for future years. See further discussion of the PCA in Part II, Item 7 - "MD&A - REGULATORY ISSUES - Deferred Power Supply Costs," and Note 13 to IDACORP's Consolidated Financial Statements.

General Rate Case Filing: IPC is proceeding through its Idaho general rate case that was originally filed with the IPUC on October 16, 2003. IPC requested approximately $86 million annually in additional revenue, or an average 17.7 percent increase to base rates. On February 20, 2004, the IPUC Staff and seven other intervenors filed their testimony with the IPUC. The testimony covered revenue requirement and rate design issues. The IPUC Staff's proposal of $15 million, a three-percent overall increase to base rates, was the lowest recommendation of any of the parties. Copies of the parties' testimony and exhibits can be viewed at the IPUC web site. IPC has until March 19, 2004 to prepare its rebuttal to these recommendations. Formal hearings are scheduled to begin on March 29, 2004, and a final order is expected from the IPUC on May 28, 2004, with a June 1, 2004 effective date.

IPC has not had an overall base rate increase since 1995. Since that time, IPC has invested more than $850 million in its electrical system, experienced an increase in normal operating costs due to inflation and added nearly 100,000 customers.

IPC's application also includes proposals to increase customers' monthly service charges and introduce summer and non-summer rates. IPC cannot predict what level of rate adjustment the IPUC will grant. See further discussion of the general rate case in Part II, Item 7 - "MD&A - - REGULATORY ISSUES - General Rate Case."

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 demand in 2003 was 2,944 MW, set on July 22, 2003. IPC expects total system energy requirements to grow 2.3 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
		2003	2002	2001	2003	2002	2001
		(thousands of MWhs)
Hydroelectric		6,149	6,069	5,638	47%	45%	43%
Thermal		6,914	7,286	7,622	53%	55%	57%
	Total system generation	13,063	13,355	13,260	100%	100%	100%

The amount of electricity IPC is able to generate from its hydroelectric plants depends on a number of factors, primarily snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage and streamflow 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 plants and purchased power.

Continued below normal streamflow conditions in 2003 yielded a system generation mix of 47 percent hydroelectric and 53 percent thermal. Under normal streamflow conditions, IPC's system generation mix is approximately 56 percent hydroelectric and 44 percent thermal.

Current Snake River basin snowpack numbers suggest that streamflow conditions for 2004 will remain below normal. IPC's February 17, 2004 snowpack accumulations were 99 percent of normal, compared to 79 percent at the same time a year earlier. As of February 17, 2004, storage for selected reservoirs upstream of Brownlee was 63 percent of normal, compared to 68 percent of normal a year earlier. IPC is currently expecting its fifth consecutive year of below normal water conditions.

Seasonal exchanges of winter-for-summer power are included among the resources under contract to maximize the firm load carrying capability.

IPC's generating facilities are interconnected through its integrated transmission system and are operated on a coordinated basis to achieve maximum load-carrying capability and reliability. IPC's transmission system is directly interconnected with the transmission systems of the Bonneville Power Administration (BPA), Avista Corporation, PacifiCorp, NorthWestern Energy and Sierra Pacific Power Company (SPPCo). Such interconnections, coupled with transmission line capacity made available under agreements with some of the above utilities, permit the interchange, purchase and sale of power among all major electric systems in the west. IPC is a member of the Western Electricity Coordinating Council, the Western Systems Power Pool (WSPP), 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: Every two years, IPC is required to file an Integrated Resource Plan (IRP) with both the IPUC and the OPUC. An IRP is a comprehensive analysis of IPC's present and future demands for electricity and the plan for meeting that demand. IPC last filed an IRP in June 2002.

The 2002 IRP identified the need for additional peaking resources in 2005. IPC issued a Request for Proposal (RFP) for up to 200 MW from a generating resource located in the IPC service area, which would provide electrical capacity during June, July, August, November and December. The RFP generated a strong response and IPC selected TR2 (formerly known as Mountain View Power) of Boise, Idaho to construct and deliver a 162-MW natural gas fired plant to be built in Mountain Home, Idaho, at an estimated project cost of $61 million. These estimated costs are not included in the current rate case request. The IPUC reviewed the selection process and IPC was issued a Certificate of Convenience and Necessity in January 2004 through IPUC Order No. 29410 and Order No. 29422. IPC has issued a formal notice to proceed with plant construction and the plant is scheduled to be on-line, commissioned and operational by June 2005. See further discussion in Part II, Item 7 - "MD&A - REGULATORY ISSUES - Bennett Mountain Power Plant."

Presently, work is underway to file another IRP with the utility commissions in June 2004. To provide additional input on the 2004 IRP, IPC has formed an IRP advisory council. The advisory council consists of public representatives from state government, industrial customers, environmental advocates and utility commission staff members. The IRP advisory council meets with IPC periodically to discuss the 2004 IRP.

The draft 2004 IRP should be available in the spring of 2004 and the final IRP will be published and filed with the IPUC and the OPUC in June 2004. The IPC service territory population continues to increase and it is expected that the 2004 IRP will identify the need for additional capacity.

CSPP Purchases: As mandated by the enactment of 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. Because IPC's service territory encompasses substantial irrigation canal development, forest product production facilities, mountain streams and food processing facilities, a considerable amount of CSPP facility development potential exists. As of December 31, 2003, IPC had signed agreements to purchase energy from 69 CSPP facilities with contracts ranging from one to 30 years. Of these facilities, 68 were on-line at the end of 2003; the other facility under contract is due to come on-line in May 2004. 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. During 2003, IPC purchased 654,131 megawatt hours (MWh) from these projects at a cost of $38 million, resulting in a blended price of 5.8 cents per kilowatt hour (kWh).

For IPUC jurisdictional projects, new projects up to ten MW are eligible for IPUC Published Avoided Costs (PAC) for up to a 20-year contract term. The PAC is a price established by the IPUC and the OPUC to estimate IPC's cost of developing additional generation resources. For all other PURPA projects, IPC is required to negotiate the terms, conditions and pricing. For OPUC jurisdictional projects, new projects up to one MW are eligible for OPUC PAC for up to a five-year contract term (automatically renewable at the end of five years). For all other PURPA projects, IPC is required to negotiate the terms, conditions and pricing. If a PURPA project does not qualify for the PAC, then IPC is required to negotiate the terms, prices and conditions with that project. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the IPC electrical system and must be consistent with other similar energy alternatives.

Wholesale Power Sales: IPC has three firm wholesale power sales contracts and one wholesale contract for load following services. Load following services allow a plant to react as the system load changes by increasing or decreasing output according to the system needs, while the output is fixed in a firm contract. These contracts are for energy up to 12 average MW and expire between 2004 and 2006. Two contracts will expire at the end of 2004. As these contracts expire, IPC will either renew, negotiate an extension or use this power to meet its own system requirements.

Wholesale Power Purchases: IPC has one firm wholesale power purchase contract. This contract is with PPL Montana, LLC (PPLM) for 83 MW per hour to address increased demand during June, July and August. The term of this contract begins in June 2004 and runs through August 2009. See further discussion in Part II, Item 7 - "MD&A - REGULATORY ISSUES - PPL Montana Power Purchase Agreement."

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.

In December 1999, the FERC issued Order No. 2000 encouraging companies with transmission assets to form Regional Transmission Organizations (RTOs). 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.

SPPCo has signed an agreement with Arch Coal Sales Company, Inc. to supply coal to the North Valmy Steam Electric Generating Plant (Valmy) 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, under the Arch Coal Sales Company agreement.

IPC owns 10 percent of the Boardman Plant. Boardman receives coal from the Powder River Basin through annual contracts. Portland General Electric, as operator of the Boardman Plant, has signed an agreement with Triton Coal Company to supply all of Boardman's 2004 coal requirements.

The Danskin combustion turbines receive gas through the Williams Northwest Pipeline. All gas is purchased on an as needed basis. Danskin's gas is transported under a long-term capacity contract with Northwest Pipeline. This contract, which extends through February 28, 2007 with annual extensions at IPC's sole discretion, is for 24,523 million British thermal units (MMbtu) per day from Sumas, Washington to Elmore, Idaho.

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 some reduction in the streamflows 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 streamflows and establishing an administrative process governing the future development of water rights that may affect IPC's hydroelectric generation. In 1987, Congress passed and the President signed into law House Bill 519. This legislation permitted implementation of the Swan Falls agreement and further provided that during the remaining term of certain of IPC's project licenses that the relationship established by the agreement would not be considered by the FERC as being inconsistent with the terms of IPC's project licenses or imprudent for the purposes of determining rates under Section 205 of the FPA. The FERC entered an order implementing the legislation on March 25, 1988.

In addition to providing for the protection of IPC's hydropower water rights, the Swan Falls agreement contemplated the initiation of a general adjudication of all water uses within the Snake River basin. In 1987, the director of the Idaho Department of Water Resources filed a petition in state district court asking that the court adjudicate all claims to water rights, whether based on state or federal law, within the Snake River basin. A commencement order initiating the Snake River Basin Adjudication was signed by the court on November 19, 1987. This legal proceeding was authorized by state statute based upon a determination by the Idaho Legislature that the effective management of the waters of the Snake River basin required a comprehensive determination of the nature, extent and priority of all water uses within the basin. The adjudication is proceeding and is expected to continue for at least the next 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 Item 2 - "Properties," and Part II, Item 7 - "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 2004 capital expenditures for environmental matters, excluding Allowance for Funds Used During Construction (AFDC), will total $21 million. Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $18 million and investments in environmental equipment and facilities at the thermal plants account for $3 million. From 2005 through 2006, environmental-related capital expenditures, excluding AFDC, are estimated to be $47 million. Anticipated expenses related to IPC's hydroelectric facilities account for $36 million and thermal plant expenses are expected to total $11 million.

IPC anticipates $14 million in annual operating costs for environmental facilities during 2004. Hydroelectric facility expenses account for $9 million of this total and $5 million is related to thermal plant operating expenses. From 2005 through 2006, total environmental-related operating costs are estimated to be $28 million. Anticipated expenses related to the hydroelectric facilities account for $18 million and thermal plant expenses are expected to total $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 in Oregon and Nevada already meet the federal emission rate standards for sulfur dioxide (SO₂) and IPC's coal-fired plant in Wyoming meets that state's even more stringent SO₂ regulations. IPC has sufficient SO₂ allowances to provide compliance for all three coal-fired facilities and its Danskin natural gas-fired facility. At the end of 2003, IPC had 61,425 allowances in excess of the amount needed for Clean Air Act compliance. Currently, IPC has been granted an annual allotment of allowances ranging from 15,524 to 28,628 through 2032. These amounts are in excess of IPC's annual compliance requirements of up to 14,500. Any excess allowances owned by IPC may be held for future use as they do not expire. Allowances determined to be excess can be sold to other companies. Accordingly, IPC does not foresee any material adverse effects upon its operations with regard to SO₂ emissions.

In July 1997, the Environmental Protection Agency (EPA) announced the National Ambient Air Quality Standards for Ozone and Particulate Matter (PM) and in July 1999, the EPA announced regional haze regulations for protection of visibility in national parks and wilderness areas. On May 14, 1999, a federal court ruling blocked implementation of these standards. In November 2000, the EPA appealed to the U.S. Supreme Court to reconsider that decision. The Supreme Court has ruled in favor of the EPA. The EPA has not yet implemented tighter regulations on PM, regional haze or ozone. The impacts of PM, regional haze and ozone 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 depend if and how they are ultimately implemented.

Valmy, Boardman and Jim Bridger Unit 4 elected to meet Phase I nitrogen oxide (NO_x) limits beginning in 1998. As a result of this voluntary "early election" and pending current proposed legislation, these units will not be required to meet the more restrictive Phase II NO_x limits until 2008. Had the units not voluntarily "early elected," they would have been required to meet the Phase II limits in 2000. Jim Bridger Units 1, 2 and 3 were accepted as substitution units in 1995 and are subject to NO_x limits of Phase I instead of the more restrictive limits of Phase II. Jim Bridger has installed low NO_x equipment to reduce NO_x levels even lower than currently required.

The Danskin gas turbine plant in Mountain Home, Idaho is operating in compliance with a "permit to construct" issued by the Idaho Department of Environmental Quality (DEQ). IPC has applied for a Title V Operating Permit from the Idaho DEQ, which is expected during 2004. The units are fitted with dry-low-NO_x burners and a continuous emissions monitoring system. This equipment should ensure that the facility will operate within the permitted federal and state NO_x and carbon monoxide limits.

Water: IPC has received National Pollutant Discharge Elimination System Permits, as required under the Federal Water Pollution Control Act Amendments of 1972, for the discharge of effluents from its hydroelectric generating plants.

IPC 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 the Cascade hydroelectric project to provide accurate water quality data and increase dissolved oxygen levels as necessary to maintain water quality standards on the Payette River. IPC has also installed and operates water quality monitors at the Milner, Shoshone Falls, Twin Falls, Upper Salmon, Lower Salmon and Bliss hydroelectric projects, in order to meet compliance standards for water quality.

IPC owns and finances the operation of anadromous fish hatcheries and related facilities to mitigate the effects of its hydroelectric dams on fish populations. In connection with its fish facilities, IPC sponsors ongoing programs for the control of fish disease and improvement of fish production. IPC's anadromous fish facilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs continue to be operated by the Idaho Department of Fish and Game. At December 31, 2003, the investment in these facilities was $10 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 - LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened and Endangered Snails."

Hazardous/Toxic Wastes and Substances: Under the Toxic Substances Control Act (TSCA), the EPA has adopted regulations governing the use, storage, inspection and disposal of electrical equipment that 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 TSCA 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 EPA. Total costs for the identification and disposal of PCBs from IPC's system were less than $1 million annually from 2000 to 2002. In 2003, IPC spent approximately $1.4 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.

In December 1999, the FERC, in its landmark Order No. 2000, said that all companies with transmission assets must file 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 seeks to further facilitate the formation of efficient, competitive wholesale electricity markets.

In October 2000 and March 2002, in response to FERC Order No. 2000, IPC and other regional transmission owners filed Stage One and Stage Two plans to form RTO West, an entity that would operate the transmission grid in seven western states. RTO West will have its own independent governing board. The participating transmission owners will retain ownership of the lines, but will not have a role in operating the grid. IPC has been an active participant in the development of RTO West. 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,
			2003		2002		2001

Revenues (thousands of dollars)
	Residential		$	275,920	$	305,827	$	260,251
	Commercial			173,820		196,454		164,019
	Industrial			128,620		176,648		154,318
	Irrigation			92,609		93,106		72,020
		Total general business		670,969		772,035		650,608
	Off-system sales			71,573		55,031		219,966
	Other			37,840		39,981		41,738
		Total	$	780,382	$	867,047	$	912,312

Energy use (thousands of MWh)
	Residential			4,427		4,387		4,307
	Commercial			3,511		3,460		3,380
	Industrial			3,206		3,226		3,925
	Irrigation			1,836		1,821		1,419
		Total general business		12,980		12,894		13,031
	Off-system sales			1,830		2,069		2,387
		Total		14,810		14,963		15,418

ENERGY MARKETING:
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. Nearing the conclusion of the wind down process, IE sold its forward book of electricity trading contracts in August 2003 to Sempra Energy Trading (SET).

See further discussion of the energy marketing wind down in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Energy Marketing", Note 13 to IDACORP's Consolidated Financial Statements and Note 17 to IPC's Consolidated Financial Statements.

Energy Marketing Operating Statistics
The following table presents IE's revenues and volumes (including intersegment transactions) for the last three years ended December 31:

			2003		2002		2001

Net Revenues (thousands of dollars)
	Electricity		$	19,267	$	42,304	$	330,793
	Gas			649		4,106		17,870
		Total	$	19,916	$	46,410	$	348,663

Operating Volumes (settled)
	Electricity (MWh)		13,045,863		39,526,630		34,936,951
	Gas (MMbtu)		2,255,881		35,895,039		97,327,432

IDACORP FINANCIAL SERVICES, INC.:

IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and tax depreciation benefits. IFS's portfolio also includes historic rehabilitation projects such as the El Cortez Hotel in San Diego, California and the Empire Building in Boise, Idaho. IFS made no new investments in 2003.

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, 2003, IFS's total portfolio exceeded $160 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 four are administered through syndicated funds.

IFS generates federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. Net reductions in consolidated income taxes related to IFS tax credits were $20 million, $21 million and $13 million for the years 2003, 2002 and 2001, respectively.

IDA-WEST:

In 2003, IDACORP began winding down Ida-West's operations. The wind down is discussed further in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Ida-West."

Ida-West develops, acquires, constructs, finances, owns and operates electric power generation facilities. Ida-West has a 50 percent interest in nine operating hydroelectric plants with a total generating capacity of 45 MW.

IPC has purchased all of the power generated by Ida-West's four Idaho hydroelectric projects at a cost of $7 million in both 2003 and 2002 and $6 million in 2001.

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 components such as multi-fuel fuel processors, fuel cell stack technology, automated fuel cell systems and integration and maintenance services. 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 kW 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.

On September 18, 2003, IdaTech was awarded a development program of $9.6 million by the United States Department of Energy for the development of a 50 kilowatt (kW) PEM fuel cell system suitable for energy supplied independent of the electrical grid for large facilities. This is a three-year, cost-shared cooperative agreement between IdaTech and other technology, utility and hotel companies.

In October 2003, IdaTech received ISO 9001:2000 certification, an international certification for quality management requirements in business-to-business dealings.

In February 2004, IdaTech and RWE Fuel Cells, a utility based in Germany, announced that they will install the first two 5-kW, combined heat and power fuel cell systems operating on natural gas at the representative office of the State of North Rhine-Westphalia in Berlin. The fuel cells will augment the supply of electricity and heat used in the building.

IDACOMM AND VELOCITUS:

In August 2000, IDACORP formed IDACOMM, Inc. and acquired Velocitus, Inc., a Boise, Idaho-based Internet service provider founded in 1992. IDACOMM and Velocitus provide a wide range of integrated communication services to business and residential customers in 22 markets across eight western states, Virginia and New York.

IDACOMM, a facility-based integrated communication provider, delivers high-speed network connectivity using fiber optic network technology. IDACOMM's technologies enable high-speed voice, Internet and data communications, including video conferencing, voice-over Internet protocol, off-site training and gigabit ethernet service. IDACOMM is conducting a broadband-over-powerline (BPL) technical trial in Boise and will be testing the commercial marketability of the product in 2004. BPL will provide 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 and school districts. IDACOMM's metropolitan area network in Idaho's Treasure Valley serves Boise, Meridian, Nampa and Caldwell.

Velocitus operates as a managed service provider by offering high-speed Internet access, Internet system support and other related services such as virtual private networks, firewalls and web hosting to 20,000 customers. Velocitus Internet serves the traditional residential and general consumer segment. Velocitus Broadband targets small to medium size business clients with high-speed connectivity and security solutions, including fixed wireless technology.

RESEARCH AND DEVELOPMENT:

In 2003, 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 methanol fuel processor 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 and two stage hydrogen purification devices based on membranes used to filter out impurities in the hydrogen fuel. Cost reduction through improved designs and reduced use of expensive materials are useful objectives of these patents. IdaTech also received approval in early 2003 from the U.S. Patent and Trademark Office of its patent application for a metal alloy composition that yields a durable and economical membrane for hydrogen purification. Currently, 26 twenty-year U.S. patents have been issued to IdaTech. These permits expire from 2016 to 2024. IdaTech also has approximately 150 pending domestic and foreign patent applications addressing various aspects of (a) fuel processor system design, operation, materials and integration; (b) membrane purification, materials and design; and (c) fuel cell system operation, thermal recovery, design, remote control and diagnostics. These patents will help IdaTech to bring its technology to commercialization. The patents also provide the potential for licensing of IdaTech's technology in the future.

In 2003, IPC spent nearly $3 million to promote energy efficiency and summer peak reduction. Just over $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 residential lighting and air conditioning, manufactured homes and duct sealing. Low-income weatherization assistance and Oregon residential weatherization efforts were also funded in 2003. 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 commercial and residential sectors. Most of the funding for these programs and program development comes from the Idaho tariff rider for demand-side management (DSM) programs and from the Conservation and Renewable Discount Program of the BPA.

ITEM 2. PROPERTIES

IPC's system includes 17 hydroelectric 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. The system also includes approximately 4,655 miles of high voltage transmission lines; 22 step-up transmission substations located at power plants; 18 transmission substations; seven transmission switching stations; and 208 energized distribution substations (excluding mobile substations and dispatch centers).

IPC holds FERC licenses for its 13 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		1997	(a)
			Bliss		80,000		75,000		1998	(a)
			Upper Salmon		39,000		34,500		1999	(a)
			Shoshone Falls		12,500		12,500		1999	(a)
			CJ Strike		89,000		82,800		2000	(a)
			Upper Malad		9,000		8,270		2004
			Lower Malad		15,000		13,500		2004
			Brownlee-Oxbow-Hells Canyon		1,398,000		1,166,900		2005
			Swan Falls		25,547		25,000		2010
			American Falls		112,420		92,340		2025
			Cascade		14,000		12,420		2031
			Milner		59,448		59,448		2038
			Twin Falls		54,300		52,737		2040
	Other Hydroelectric				10,400		11,300
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

(a) Licensed on a year-to-year 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.

At December 31, 2003, the composite average ages of the principal parts of IPC's system, based on dollar investment, were: production plant, 23 years; transmission system and substations, 21 years; and distribution lines and substations, 17 years. IPC considers its properties to be well maintained and in good operating condition.

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

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.

RELICENSING OF HYDROELECTRIC PROJECTS:

IPC, like other utilities that operate nonfederal hydroelectric projects, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years, depending on the size and complexity of the project. Currently, the licenses for five hydroelectric projects have expired. These projects continue to operate under annual licenses until the FERC issues a new multi-year license. Three more hydroelectric project licenses will expire by 2010.

IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years. IPC has filed applications with the FERC seeking new licenses for the Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls, Upper and Lower Malad, and the Hells Canyon Complex (Brownlee, Oxbow, and Hells Canyon) hydroelectric projects. The licenses for all but the Upper and Lower Malad and the Hells Canyon Complex (HCC) have expired and the projects are operating on annual licenses until new multi-year licenses are issued. The licenses for the Malad and HCC projects expire in July 2004 and July 2005, respectively. The license for the Swan Falls Project expires in 2010. IPC is currently engaged in procedures necessary to file a timely license application for the Swan Falls Project. Although various federal and state requirements and issues must be resolved through the license renewal process, IPC anticipates that it will relicense all of the projects for which applications have been filed.

Final Environmental Impact Statements (EIS) have been issued for the Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls projects. New FERC licenses for these projects are anticipated in 2004. While the actual environmental costs of protection, mitigation and enhancement (PM&E) measures and other costs associated with the relicensing of the projects will not be known until the new licenses are issued by the FERC, costs associated with these licenses (assuming 30-year licenses) are expected to total approximately $8 million during the first five years of the licenses and $28 million over the following 25 years.

A final EIS was issued in October 2002 for the CJ Strike project and a new FERC license is also expected in 2004. While the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC, costs associated with the license (assuming a 30-year license) are expected to total approximately $9 million during the first five years of the license and $38 million over the following 25 years.

The four Mid-Snake River projects (Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls) and the CJ Strike project, may affect five species of snails listed under the Endangered Species Act. See discussion in the Part II, Item 7 - "MD&A - LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened and Endangered Snails."

The Upper and Lower Malad project license expires in July 2004 and the new license application was filed in July 2002. The application is proceeding through the normal FERC licensing process. The application includes proposed PM&E measures estimated to total (assuming a 30-year license) approximately $1 million during the first five years of the license and $3 million over the following 25 years. However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.

The most significant relicensing effort is the HCC, which provides 68 percent of IPC's hydroelectric generation capacity and 40 percent of its total generating capacity. IPC developed its license application with the assistance of a collaborative team made up of individuals representing state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests. The application was filed with the FERC in July 2003. The FERC is reviewing the application and has given notice of its intent to prepare an EIS under the National Environmental Policy Act (NEPA). On October 20, 2003, the FERC issued Scoping Document 1 to provide interested parties with information on the project and to solicit written and verbal comments and suggestions on the preliminary list of issues and alternatives that the FERC should address in the EIS. This NEPA process is continuing. By letter dated December 1, 2003, the FERC advised IPC that the license application had been accepted for filing and conformed to applicable FERC regulations. On December 2, 2003 the FERC published notice of the acceptance of the application for filing and solicited motions to intervene and protests to the application. The intervention and protest period closed on February 2, 2004 and 18 separate parties either intervened or protested the IPC license application. IPC has responded to selected interventions and the FERC is now preparing a second Scoping Document as part of the NEPA process leading up to preparation of an EIS.

The HCC application includes proposed PM&E measures estimated to total (assuming a 30-year license) approximately $67 million during the first five years of the license and $79 million during the following 25 years. However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.

At December 31, 2003, $61 million of relicensing costs were included in Construction Work in Progress (CWIP) and $8 million of relicensing costs were included in Electric Plant in Service. The relicensing costs are recorded and held in CWIP until a new multi-year license or annual license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service. Relicensing costs and costs related to the new licenses, as discussed above, will be submitted to regulators for recovery through the rate-making process. The current Idaho general rate case filing includes $10 million of relicensing costs.

ITEM 3. LEGAL PROCEEDINGS

Please refer 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 REGISTRANTS

The names, ages and positions of all of the executive officers of IDACORP, Inc. and Idaho Power Company are listed below along with their business experience during the past five years. 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.

IDACORP, Inc.

Name, Age and Position	Business Experience During Past Five Years
Jan B. Packwood, 60 President and Chief Executive Officer	Appointed May 30, 1999. Mr. Packwood was President and Chief Operating Officer from February 2, 1998 to May 30, 1999.

J. LaMont Keen, 51 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, Senior Vice President-Administration, Chief Financial Officer and Treasurer from March 15, 1999 to May 5, 1999 and Vice President, Chief Financial Officer and Treasurer from February 2, 1998 to March 15, 1999.

*Darrel T. Anderson, 45 Vice President, Chief Financial Officer and Treasurer	Appointed March 1, 2002. Mr. Anderson was Vice President, Finance and Treasurer from May 5, 1999 to March 1, 2002.

*Bryan A. B. Kearney, 41 Vice President and Chief Information Officer	Appointed March 15, 2001.

*Gregory W. Panter, 55 Vice President - Public Affairs	Appointed April 1, 2001.

*Robert W. Stahman, 59 Vice President, General Counsel and Secretary	Appointed February 2, 1998.

*Daniel B. Minor, 46 Vice President - Administrative Services and Human Resources	Appointed November 20, 2003.

*These IDACORP, Inc. executive officers serve in the same capacities at Idaho Power Company. For these officers' business experience during the past five years, please refer to the following page.

Idaho Power Company

Name, Age and Position	Business Experience During Past Five Years

Jan B. Packwood, 60 Chief Executive Officer	Appointed March 1, 2002. Mr. Packwood was President and Chief Executive Officer from May 30, 1999 to March 1, 2002 and President and Chief Operating Officer from September 1, 1997 to May 30, 1999.

J. LaMont Keen, 51 President and Chief Operating Officer	Appointed March 1, 2002. Mr. Keen was Senior Vice President-Administration and Chief Financial Officer from May 5, 1999 to March 1, 2002, Senior Vice President-Administration, Chief Financial Officer and Treasurer from March 15, 1999 to May 5, 1999 and Vice President, Chief Financial Officer and Treasurer from March 14, 1996 to March 15, 1999.

James C. Miller, 49 Senior Vice President - Delivery	Appointed November 18, 1999. Mr. Miller was Vice President - Generation from July 10, 1997 to November 18, 1999.

Darrel T. Anderson, 45 Vice President, Chief Financial Officer and Treasurer	Appointed March 1, 2002. Mr. Anderson was Vice President-Finance and Treasurer from May 5, 1999 to March 1, 2002, Corporate Controller from January 25, 1999 to May 5, 1999, Executive Vice President of Finance and Operations at Applied Power Corp. from June 5, 1998 to January 25, 1999 and Corporate Controller from February 26, 1996 to June 5, 1998.

John R. Gale, 53 Vice President, Regulatory Affairs	Appointed March 15, 2001. Mr. Gale was General Manager of Pricing & Regulatory Services from November 28, 1998 to March 15, 2001.

Bryan A.B. Kearney, 41 Vice President and Chief Information Officer	Appointed November 18, 1999. Mr. Kearney was Vice President and Chief Technology Officer at Bear Creek Corp, a direct marketing, manufacturing and retail corporation, from October 1, 1998 to November 18, 1999.

Gregory W. Panter, 55 Vice President - Public Affairs	Appointed April 1, 2001. Mr. Panter was self-employed with Greg Panter Consulting, a lobby/government affairs business, from July 1, 1999 to April 1, 2001 and Westberg/Panter and Associates, a lobby/government affairs business, from November 1, 1989 to July 19, 1999.

John P. Prescott, 47 Vice President - Power Supply	Appointed November 18, 1999. Mr. Prescott was Vice President of Business Development for IDACORP Technologies, Inc. from August 19, 1999 to November 18, 1999, and President and Treasurer of Stellar Dynamics from October 5, 1995 to August 19, 1999.

Robert W. Stahman, 59 Vice President, General Counsel and Secretary	Appointed July 13, 1989.

Daniel B. Minor, 46 Vice President - Administrative Services and Human Resources	Appointed November 20, 2003. Mr. Minor was Vice President - Corporate Services from May 15, 2003 to November 20, 2003 and Director of Audit Services from July 19, 2001 to May 15, 2003. Mr. Minor was Executive Vice President and COO of Right Systems, Inc., a technology management services company, from September 8, 1998 to July 19, 2001.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

IDACORP, Inc.'s (IDACORP) common stock (without par value) is traded on the New York Stock Exchange and the Pacific Exchange. At December 31, 2003, there were 20,634 holders of record and the year-end stock price was $29.92 per share.

The outstanding shares of Idaho Power Company (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. This decreased rate is equivalent to a quarterly dividend of $0.30 per share. See further discussion of the dividend reduction in Part II, Item 7 - "MD&A - LIQUIDITY AND CAPTIAL 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 $65 million in 2003 and $70 million in 2002 and 2001.

The following table shows the reported high and low sales price of IDACORP's common stock and dividends paid for the years 2003 and 2002 as reported in the consolidated transaction reporting system.

		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

		2002 Quarters
Common Stock, without par value:		1^st	2^nd	3^rd	4^th
	High	$40.86	$40.99	$28.60	$26.60
	Low	37.26	25.71	21.58	20.87
	Dividends paid per share (cents)	46.5	46.5	46.5	46.5

ITEM 6. SELECTED FINANCIAL DATA

IDACORP, Inc.
SUMMARY OF OPERATIONS
(thousands of dollars except per share amounts)
					2003		2002		2001			2000				1999
OPERATING REVENUES:
Electric utility:
		General business			$	670,969	$	772,035		$	650,608		$	565,357	$		516,148
		Off-system sales				71,573		55,031			219,966			229,986			119,785
		Other revenues				40,178		41,974			43,627			41,663			24,226
			Total electric utility revenues			782,720		869,040			914,201			837,006			660,159
Energy marketing						19,916		46,410			348,663			190,116			40,157
Other						20,366		13,350			12,448			22,663			29,426
		Total operating revenues				823,002		928,800			1,275,312			1,049,785			729,742

OPERATING EXPENSES:
Electric utility:
		Purchased power				150,980		142,102			584,209			398,649			106,344
		Fuel expense				99,898		102,871			98,318			94,215			86,617
		Power cost adjustment				70,762		170,489			(175,925)			(120,688)			(502)
		Other operations and
				maintenance		220,983		207,355			210,763			194,870			196,036
		Depreciation				97,650		93,609			87,041			80,287			77,833
		Taxes other than income taxes				20,753		19,953			19,693			20,166			21,719
			Total electric utility expenses			661,026		736,379			824,099			667,499			488,047
Energy marketing:
		Cost of revenues				1,250		42,113			105,904			44,785			5,049
		Selling, administrative and
			general			24,349		30,427			66,047			50,811			13,424
		Net loss on legal disputes				12,072		-			-			-			-
Other						40,243		44,241			36,973			39,380			36,540
		Total operating expenses				738,940		853,160			1,033,023			802,475			543,060
Operating income						84,062		75,640			242,289			247,310			186,682
Other Income						24,412		19,218			33,600			42,265			22,819
Other Expense						18,083		15,388			10,306			11,948			5,325
Interest expense and other						64,932		68,945			75,723			66,926			67,155
Income tax (benefit) expense						(21,119)		(51,147)			64,646			70,818			45,672
Net income*					$	46,578	$	61,672		$	125,214		$	139,883	$		91,349
Dividends on common stock					$	64,726	$	70,178		$	69,782		$	69,850	$		69,863

FINANCIAL CONDITION:
Total assets					$	3,101,726	$	3,387,168		$	3,769,992		$	4,159,177	$		2,752,726
Capitalization ratios:
		Long-term debt				51%		49%			46%			48%			49%
		Preferred stock				3%		3%			6%			6%			6%
		Common stock equity				46%		48%			48%			46%			45%
Short-term borrowings outstanding					$	93,650	$	176,200		$	362,500		$	120,600	$		19,757

FINANCIAL STATISTICS:
Times interest charges earned:
		Before tax				1.37		1.16			3.52			4.33			3.18
		After tax				1.68		1.93			2.66			3.21			2.45
Market-to-book ratio						132%		108%			175%			225%			134%
Payout ratio						139%		114%			56%			50%			77%
Return on year-end common equity						5.4%		7.1%			14.4%			17.0%			12.1%

COMMON STOCK DATA:
Earnings per average share
	outstanding				$	1.22	$	1.63		$	3.35		$	3.72	$		2.43
Dividends declared per share					$	1.70	$	1.86		$	1.86		$	1.86	$		1.86
Book value per share					$	22.62	$	23.01		$	23.21		$	21.85	$		20.02
Average shares outstanding
	(000 omitted)					38,186		37,729			37,387			37,556			37,612
Common shareowners						20,634		20,088			22,512			21,886			23,758

* See "Wind Down of Energy Marketing" in Note 13 to IDACORP's Consolidated Financial Statements, "Legal
Proceedings - Overton Power District No. 5" in Note 8 to IDACORP's Consolidated Financial Statements and
"Tax Accounting Method Change" in Note 2 to IDACORP's Consolidated Financial Statements.

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

IDAHO POWER COMPANY
SUMMARY OF OPERATIONS
(thousands of dollars)
				2003		2002			2001			2000		1999
Operating revenues				$	780,382	$	867,047	$		912,312	$		835,662	$	658,336
Income from operations					121,510		132,540			90,020			169,636		172,458
Income from continuing operations					58,591		88,920			28,295			79,968		83,465
Earnings on common stock				$	55,161	$	84,333	$		72,838	$		131,559	$	91,956

At December 31,
		Total long-term debt			880,868		870,741			802,201			808,977		821,558
		Total assets			2,820,711		2,876,167			2,987,382			2,736,563		2,671,729

UTILITY CUSTOMER DATA:
General business data:
	Energy sales - MWh				12,980		12,894			13,031			14,598		13,766
	Number of customers at
			December 31		426,600		414,944			401,739			392,128		384,421
Residential customer data:
	Number of customers at
			December 31		354,704		344,447			335,285			327,983		319,956
	Average kWh use per customer				12,481		12,911			13,001			13,580		13,379
	Average rate per kWh (cents)				6.23		6.97			6.04			5.13		5.08

The above data should be read in conjunction with IPC's Consolidated Financial Statements and 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 as the parent of IPC and several other entities.

IPC is an electric utility with a service territory covering over 20,000 square miles, primarily in southern Idaho and eastern Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operating subsidiaries include:

IdaTech - developer of integrated fuel cell systems;
IDACORP Financial Services, Inc. (IFS) - affordable housing and other real estate investments;
Velocitus - commercial and residential Internet service provider;
IDACOMM - provider of telecommunications services;
Ida-West Energy (Ida-West) - developer and manager of independent power projects; and
IDACORP Energy (IE) - marketer of electricity and natural gas.

IE is in the late stages of winding down its operations. In 2003, IDACORP began winding down Ida-West's operations, as discussed in "RESULTS OF OPERATIONS - Ida-West" later in the MD&A.

While reading the MD&A, please refer to the Consolidated Financial Statements of IDACORP and IPC, which present the financial position at December 31, 2003 and 2002, and the results of operations and cash flows for each company for the years ended December 31, 2003, 2002 and 2001.

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, in presentations, in response to questions or otherwise. Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "will likely result," "will continue" or similar expressions) are not statements of historical facts and may be forward-looking. Forward-looking statements involve estimates, assumptions and uncertainties and are qualified in their entirety by reference to, and are accompanied by, the following important factors, which are difficult to predict, contain uncertainties, are beyond our control and may cause actual results to differ materially from those contained in forward-looking statements:

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, 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 resulting from the energy situation in the western United States;

Economic, geographic and political factors and risks;

Changes in and compliance with environmental and safety laws and policies;

Weather variations affecting customer energy usage;

Operating performance of plants and other facilities;

System conditions and operating costs;

Population growth rates and demographic patterns;

Pricing and transportation of commodities;

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

Changes in capacity, fuel availability and prices;

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

Changes in actuarial assumptions;

Adoption or changes in critical accounting policies or estimates;

Exposure to operational, market and credit risk;

Changes in operating expenses and capital expenditures;

Capital market conditions;

Rating actions by Moody's, Standard & Poor's and Fitch;

Competition for new energy development opportunities;

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

Natural disasters, acts of war or terrorism;

Increasing health care costs and the resulting effect on health insurance premiums paid for employees and on the obligation to provide postretirement health care benefits;

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

Legal and administrative proceedings, whether civil or criminal, and settlements that influence business and profitability; 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 important 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 significantly affect operating results. 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 Idaho Power Company's operations. Idaho Power Company experienced its fourth consecutive year of below normal water conditions in the 2002-2003 water year and while the 2003-2004 snowpack is near normal, streamflows are currently expected to remain below normal. 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 (fuel and purchased power less sales for resale) above the level included in its base rates. The Power Cost Adjustment recovery is on both a forecasted and deferred basis and is subject to the regulatory process. The balance of its fuel and purchased power expense is subject to periodic recovery from its Oregon and Federal Energy Regulatory Commission jurisdictional customers.

Changes in temperature can reduce power sales and affect operating results. Idaho Power Company experienced warmer than usual temperatures in its service territory in the winter months of 2003, which reduced sales. Warmer than normal winters or cooler than normal summers will reduce retail revenues from power sales.

Conditions that may be imposed in connection with hydroelectric license renewals may negatively affect earnings. Idaho Power Company is currently involved in renewing federal licenses for most of its hydroelectric projects. Idaho Power Company currently expects new licenses for five middle Snake River region hydroelectric plants to be issued in 2004. In addition, Idaho Power Company filed its license application on July 18, 2003 for the Hells Canyon Complex, which provides 40 percent of Idaho Power Company's total generating capacity. Conditions with respect to environmental, operating and other matters that may be imposed by the Federal Energy Regulatory Commission in connection with the renewal of these licenses could have a negative effect on Idaho Power Company's operations.

The cost of complying with environmental regulations can significantly affect operating results. 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 and additional requirements imposed in connection with the relicensing of Idaho Power Company's hydroelectric projects.

If the Idaho Public Utilities Commission does not grant requested rate relief, Idaho Power Company's earnings and cash flow will be negatively affected. Idaho Power Company is proceeding through its Idaho general rate case filed with the Idaho Public Utilities Commission on October 16, 2003, requesting $86 million in additional annual revenue, or an average 17.7 percent increase to base rates. Idaho Power Company has not had an overall base rate increase since 1995. Since that time, Idaho Power Company has invested more than $850 million in its electrical system, experienced an increase in normal operating costs due to inflation and added nearly 100,000 customers. If the Idaho Public Utilities Commission does not grant the requested rate relief, Idaho Power Company's earnings and cash flow will be negatively impacted and its credit ratings may be downgraded.

Terrorist threats and activities can significantly affect operating results. 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 lost revenues and increased costs.

Idaho Power Company and its affiliate, IDACORP Energy, are subject to potential liabilities as a result of energy marketing operations. As IDACORP Energy wound down its energy marketing operations, certain matters were identified that required resolution with the Federal Energy Regulatory Commission and the Idaho Public Utilities Commission. The Federal Energy Regulatory Commission matters have been resolved; however, certain compensation issues remain to be resolved with the Idaho Public Utilities Commission. In an Idaho Public Utilities Commission proceeding that has been underway since May 2001, Idaho Power Company, the Idaho Public Utilities Commission staff and several interested customer groups have been working to determine the appropriate compensation IDACORP Energy should provide to Idaho Power Company for certain transactions between the affiliates. The parties to the proceeding have executed a settlement agreement providing that an additional $5.5 million will be flowed through the Power Cost Adjustment mechanism to the Idaho retail customers from April 2003 through December 2005. This agreement was filed with the Idaho Public Utilities Commission on February 17, 2004 and is subject to its approval. This settlement should resolve all remaining compensation issues. It is possible that other proceedings may be commenced against Idaho Power Company or IDACORP Energy in connection with energy marketing.

IDACORP, Inc., IDACORP Energy and Idaho Power Company are subject to costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including those that may arise out of the California 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 energy crisis in California include efforts by certain public parties to reform or terminate contracts for the purchase of power from IDACORP Energy and show cause proceedings at the Federal Energy Regulatory Commission that consider whether certain trading practices constituted gaming or acting in concert in furtherance of a gaming strategy. To the extent the companies are required to make payments, earnings will be negatively affected. It is possible that additional proceedings related to the California energy crisis may be filed in the future against IDACORP, Inc., IDACORP Energy or Idaho Power Company.

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. Additionally, a significant portion of Idaho Power Company's facilities was 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.

A SUMMARY OF 2003 AND OUTLOOK FOR 2004:

This section presents an overview of the most critical issues that IDACORP and IPC are facing, and the significant items that affected IDACORP's and IPC's 2003 operating results.

Financial Results
IDACORP's earnings per share (EPS) of $1.22 was a $0.41 decrease from 2002's $1.63 per share. Several key factors impacted 2003's results:

IPC earned $1.44 per share in 2003. Below normal streamflow conditions continue to affect IPC's hydroelectric generation capability. Lower than normal hydroelectric generation, combined with unplanned outages at thermal plants, resulted in a greater reliance on market purchases of electricity to meet the needs of its service territory. These thermal outages, along with pension expense increases, were primary factors in a $13 million increase to utility operation and maintenance expenses. Additionally, IPC reached tax settlements with the IRS for the years 1998-2000, resulting in a $9 million decrease to income tax expense.

IDACORP Energy: Wind down activity continued at IE, which posted a net loss of $0.25 per share. Losses on the settlement of legal matters and other wind down costs were partially offset by a gain on the sale of the forward book of energy trading contracts.

IFS contributed $0.27 per share, principally from the generation of federal income tax credits and tax depreciation benefits.

IdaTech contributed $(0.04) per share, which is an improvement of $0.18 per share, due primarily to the successful resolution of existing contracts, including a $4 million settlement of a contract related to the design, production and delivery of fuel cell systems.

Ida-West wrote down its remaining investment in the Garnet project and two joint ventures and recorded a reserve on a note receivable, reducing EPS by $0.13.

General Rate Case Filing
IPC is proceeding through its Idaho general rate case that was originally filed with the IPUC on October 16, 2003. IPC requested approximately $86 million annually in additional revenue, or an average 17.7 percent increase to base rates. On February 20, 2004, the IPUC Staff and seven other intervenors filed their testimony with the IPUC. The testimony covered revenue requirement and rate design issues. The IPUC Staff's proposal of $15 million, a three-percent overall increase to base rates, was the lowest recommendation of any of the parties. Copies of the parties' testimony and exhibits can be viewed at the IPUC web site. IPC has until March 19, 2004 to prepare its rebuttal to these recommendations. Formal hearings are scheduled to begin on March 29, 2004, and a final order is expected from the IPUC on May 28, 2004, with a June 1, 2004 effective date.

IPC cannot predict what level of rate adjustment the IPUC will grant. Should the IPUC grant less than IPC's request, IPC might need to implement alternative strategies. These strategies could result in the deferral or elimination of certain capital expenditures, greater reliance on purchased power to meet customer needs, other cost containment measures and the filing of another rate request with the IPUC.

Hydroelectric Generation and Power Supply Costs
IPC relies on low-cost hydroelectric plants for a significant portion of its power supply. In 2003, IPC experienced its fourth consecutive year of below normal hydroelectric generating conditions, which necessitated increased reliance on higher-cost thermal generation and purchased power. Unplanned outages at thermal plants further increased the need to purchase power.

Increased reliance on purchased power and higher market prices for this power resulted in IPC absorbing approximately $25 million of power supply costs that were not recovered through its Power Cost Adjustment (PCA) mechanism. IPC absorbed approximately $25 million in 2002 and $76 million in 2001. With more normal generating conditions IPC would absorb lesser amounts of power supply costs.

There are early indications of some relief from depressed hydroelectric generating conditions. The most recent hydrological survey projects that conditions in 2004 will be improved over 2003, but remain below normal.

Strategy
During 2003, IDACORP refocused 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 revised 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 federal income tax credits, remains a key component of the revised corporate strategy.

Wind Down of Non-Utility Businesses
The wind down of IE neared completion as major milestones were reached in 2003:

Several major legal issues were resolved during the year;

The forward book of energy trading contracts was sold in August;

IE's workforce, once as high as 125, has been eliminated; and

$45 million of a note receivable from Overton Power District No. 5 was collected in December.

At December 31, there were still a number of legal matters outstanding, as discussed in "Legal and Environmental Issues" later in the MD&A.

The wind down of Ida-West began in the fourth quarter of 2003, after a review of the prospects for that business. IDACORP's revised strategic direction did not include the development or acquisition of merchant related generation, which had been Ida-West's focus. The fourth quarter of 2003 includes $8.6 million in impairment charges related to remaining site costs of the Garnet energy facility, investments in joint ventures and notes receivable.

Relicensing
On July 18, 2003, IPC filed its application with the FERC to relicense the company's three-dam Hells Canyon Complex (HCC). The current license for HCC will expire in 2005; however, the FERC requires applicants to file two years in advance of a license's expiration date. HCC is the largest in IPC's system of 17 hydroelectric generating plants and collectively, the HCC provides approximately two-thirds of IPC's total hydroelectric generation capacity.

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

Contract disputes with Truckee-Donner Public Utility District were settled, with no material impact on the companies;

A contract-related lawsuit filed by the Public Utility District No. 1 of Grays Harbor County, Washington was dismissed with prejudice on January 28, 2003. This matter has been appealed to the U.S. Court of Appeals for the Ninth Circuit;

A contract dispute with Overton Power District No. 5 was settled, resulting in a $21.5 million loss in the second quarter of 2003. In December 2003, IE received $45 million in final settlement of the contract;

In February 2003, the FERC resolved a matter related to the wind down of energy marketing, approving the assignment of certain wholesale power and transmission services agreements from IPC to IE;

In May 2003, the U.S. Bankruptcy Court approved a settlement agreement between the companies and Enron in connection with claims IE had submitted in the Enron bankruptcy proceeding for net pre-petition obligations owed by Enron to IE, primarily for power and energy delivered prior to the Enron bankruptcy; and

In February 2004, Vierstra Dairy was awarded approximately $17 million in damages for the alleged effect of electrical current on the health of Vierstra's dairy cows. IPC intends to appeal the jury decision.

CRITICAL ACCOUNTING POLICIES:

IDACORP 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. 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 $434 million of regulatory assets and $259 million of regulatory liabilities at December 31, 2003. While IPC expects to fully recover these regulatory assets or 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 it will be successful. If IPC has to write off a material amount of the regulatory assets, this will have a material adverse effect on IPC's operating results.

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 about 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 those used to develop the assumptions.

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 for 2004 pension expense will be reduced to 6.15 percent from the 6.75 percent used in 2003.

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 two percent inflation assumption is used in the asset modeling process.

Pension expense (income) for these plans totaled $12 million, $4 million and ($4 million) for the three years ended December 31, 2003, 2002 and 2001, respectively, including amounts allocated to capitalized labor costs. For 2004, 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 2003 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
	2004		2003		2004		2003
	(in millions of dollars)
Effect of 0.5% increase	$	(1.6)	$	(1.6)	$	(1.6)	$	(1.4)
Effect of 0.5% decrease		1.7		2.9		1.6		1.4

No cash contributions were made to the qualified plan in 2001 through 2003, and none are expected in 2004. Under the non-qualified plan, IPC makes payments directly to participants in the plan. Payments were approximately $2.5 million per year in 2001 though 2003, and a similar amount is anticipated in 2004.

Please also 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 those 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, reserves 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 2003 include the following:

Goodwill: IDACORP has $13 million of goodwill related to its investments in Velocitus, 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.

SWIP: IPC began developing the Southwest Intertie Project (SWIP) in 1988. This project covers the construction and operation of a 500-mile 500-kilovolt transmission line that would connect IPC's system with California and the Southwest. IPC's investment consists predominantly of rights-of-way over public lands in Idaho and Nevada. While no definitive action has taken place with SWIP in several years, discussions occur from time-to-time with parties interested in acquiring or joining with IPC in further development. Based on these discussions and management expectations about 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.

Garnet: During 2003, Ida-West wrote down its remaining investment in the Garnet energy facility, which was to be developed as a 273-MW gas-fired generation station. Originally, the Garnet facility had been selected by IPC to meet future energy needs based on IPC's 2000 Integrated Resource Plan (IRP) and IPC entered into a Power Purchase Agreement (PPA) to purchase the Garnet facility's output. Due to dramatic changes in the electric industry, financing the project on acceptable terms under the PPA became impractical and Ida-West wrote down its $8 million investment in equipment for the project in 2002. Approximately $3.6 million of costs related to the development of the Garnet site remained, as the site continued to be viable for future generation development.

In 2003, the PPA for Garnet was terminated and IPC issued a request for proposal (RFP) for development of additional generation capability in IPC's service territory. The RFP specifically prohibited affiliates of IPC, including Ida-West, from bidding. Accordingly, another project proposed by a party unaffiliated with IPC was selected, leading to management's determination that further development of the Garnet project was improbable. Based on this conclusion, the remaining $3.6 million investment in Garnet was written off in 2003.

Investments:IFS has affordable housing and other investments totaling $116 million at December 31, 2003, and Ida-West has investments in four joint ventures that own electric power generation facilities. 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 wind down Ida-West's activities, Ida-West had the intent and ability to hold the investments for a time 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 $2.4 million in 2003. The impairment amounts are based on the estimated fair value of the investments.

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 2003 are compared to 2002 and the results of 2002 are compared to 2001. The analysis is organized by operating segment, concentrating on the Utility Operations and Energy Marketing segments. Additional noteworthy information about the results of other segments is also included. The following table presents EPS broken down by operating segment:

EPS of common stock
	2003		2002		2001
Utility operations	$	1.44	$	2.24	$	0.60
Energy marketing		(0.25)		(0.39)		2.87
IFS		0.27		0.23		0.14
Ida-West		(0.13)		(0.14)		0.13
IdaTech		(0.04)		(0.22)		(0.22)
Other		(0.07)		(0.09)		(0.17)
Total EPS	$	1.22	$	1.63	$	3.35

Return on year end common equity		5.4%		7.1%		14.4%

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.

The decrease in EPS from utility operations in 2003 was primarily the result of the following factors:

EPS decreased $0.82 due to a change to the utility's tax accounting method for capitalized overhead costs. This change was adopted in 2002, and increased income $35 million that year and $4 million in 2003.

EPS decreased $0.21 per share in 2003 because operating and maintenance expenses increased $14 million in 2003, due mainly to a $5 million increase in pension expenses, a $4 million increase in thermal plant maintenance costs and a $3 million increase in transmission line maintenance.

EPS increased $0.18 per share in 2003 because in 2002 IPC wrote off $12 million of regulatory assets related to the 2001 Irrigation Load Reduction Program. The IPUC denied recovery of this amount in 2002.

The increase in EPS from utility operations in 2002 was primarily the result of the following factors:

EPS increased $0.92 due to a change adopted in 2002 to the utility's tax accounting method for capitalized overhead costs. This change increased net income $35 million in 2002. Of that amount, $31 million relates to the effect of adoption of the tax method on prior tax years.

EPS increased $0.82 because net power supply costs (fuel and purchased power less sales for resale) absorbed by the utility decreased $51 million.

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 (fuel and purchased power less sales for resale) that IPC incurs. Most, but not all, of the power supply costs are recovered through the rates charged to customers. Generally, lower hydroelectric generation increases power supply costs, thereby increasing the amount of these costs that IPC absorbs.

In 2003, IPC experienced its fourth consecutive year of below normal hydroelectric generating conditions, which increased reliance on higher-cost thermal generation and purchased power. Unplanned outages at thermal plants further increased the need to purchase power. The following table presents IPC's system generation for the last three years:

	MWh			% of total generation
			Total			Total
			system			system
	Hydroelectric	Thermal	generation	Hydroelectric	Thermal	generation
2003	6,149	6,914	13,063	47%	53%	100%
2002	6,069	7,286	13,355	45%	55%	100%
2001	5,638	7,622	13,260	43%	57%	100%
Normal^(a)	9,251	7,358	16,609	56%	44%	100%

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

The U.S. National Weather Service's Northwest River Forecast Center is predicting April-through-July 2004 inflow into Brownlee Reservoir will be 4.3 million acre-feet (maf). The normal 30-year average for inflow during that time is 6.3 maf. Based on the above snowpack, reservoir storage and forecasted inflows, IPC is expecting its fifth year of below normal water conditions. IPC currently plans to use wholesale purchases from the energy markets when necessary to meet its energy needs during 2004, which, as noted above, will result in increased expenses.

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

		Revenue						MWh
		2003		2002		2001		2003	2002	2001
Residential		$	275,920	$	305,827	$	260,251	4,427	4,387	4,307
Commercial			173,820		196,454		164,019	3,511	3,460	3,380
Industrial			128,620		176,648		154,318	3,206	3,226	3,925
Irrigation			92,609		93,106		72,020	1,836	1,821	1,419
	Total	$	670,969	$	772,035	$	650,608	12,980	12,894	13,031

The following factors influenced the change in general business revenue:

2003 vs. 2002:

Decreased average rates, resulting from the PCA, reduced revenue $79 million. The PCA is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs;"

A $28 million decrease in revenues due to the expiration in March 2003 of a take-or-pay contract with FMC/Astaris. 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;

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

Milder weather and other usage factors reduced revenues by approximately $10 million.

2002 vs. 2001:

Rate increases due to the annual PCA increased revenues approximately $94 million. The PCA is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs;"

Customer growth in IPC's service territory increased approximately 2.5 percent, resulting in a $13 million increase in revenues;

In 2001 many irrigation customers participated in a program to decrease their usage. This program was not in effect during 2002, resulting in increased sales to irrigation customers of $19 million; and

FMC/Astaris, previously IPC's largest volume customer, closed its Pocatello, Idaho manufacturing plant late in 2001. However, based on a take-or-pay contract with FMC/Astaris that requires payment for power regardless of delivery, IPC continued to receive payments from FMC/Astaris through March 2003. Because of this, revenues from FMC/Astaris changed minimally, despite the significant decrease in MWh sold.

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

	2003		2002		2001

Revenue	$	71,573	$	55,031	$	219,966
MWh sold		1,830		2,069		2,387
Revenue per MWh	$	39.11	$	26.60	$	92.14

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

2002 vs. 2001: In 2002, revenues from off-system sales decreased due to a 13 percent decrease in volumes sold and a 71 percent decrease in wholesale electricity prices, reflecting the return to a more normal wholesale energy market from what existed in 2001.

Purchased power:

		2003		2002		2001
Purchased power:
	Purchases	$	147,850	$	91,312	$	430,451
	Load reduction costs		3,130		50,790		153,758

MWh purchased			3,383		2,918		3,457
Cost per MWh purchased		$	43.70	$	31.29	$	124.53

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 in March 2003 of the FMC/Astaris Voluntary Load Reduction Program, which is discussed further in "REGULATORY ISSUES - FMC/Astaris Settlement Agreement."

2002 vs. 2001: Purchased power costs decreased primarily due to a 75 percent decline in average wholesale electricity prices, reflecting the return to a more normal wholesale energy market from what existed in 2001. Volumes purchased declined principally because of a similar decrease in sales volumes. Load reduction payments decreased $103 million due to expiration of the Irrigation Load Reduction Program and changes to the FMC/Astaris Voluntary Load Reduction Agreement.

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

	2003		2002		2001
Fuel expense	$	99,898	$	102,871	$	98,318
Thermal MWh generated		6,914		7,286		7,622
Cost per MWh	$	14.45	$	14.12	$	12.90

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 North Valmy Steam Electric Generating Plant (Valmy). 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 has been repaired and modernized controls and protection systems are in place. Additional maintenance was completed during the outage which should minimize the 2004 planned maintenance outage period for the unit. IPC owns 50 percent of Valmy and is not the plant operator.

2002 vs. 2001: Fuel expenses increased due to a nine percent increase in average coal prices, partially offset by a four percent decrease in thermal generation.

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." In 2003, 2002, and 2001, actual power supply costs (fuel and purchased power less sales for resale) 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:

		2003		2002		2001
Current year power supply cost deferral		$	(44,320)	$	(4,178)	$	(145,801)
FMC/Astaris and irrigation program costs (deferral)			(2,245)		(39,854)		(136,028)
Amortization of prior year authorized balances			117,279		200,941		94,358
Write-offs of disallowed costs			48		13,580		11,546
	Total power cost adjustment	$	70,762	$	170,489	$	(175,925)

Other Operations and Maintenance Expenses:
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 increased tree-trimming and pole maintenance costs of $1 million, and because of insurance proceeds received in 2002 related to a 2001 outage of $1 million.

2002 vs. 2001: Other operation and maintenance expenses decreased $3 million, due principally to the following:

IPC paid $5 million in 2001 to lease portable generation equipment to protect against electricity supply shortages. These costs were not incurred in 2002;

Costs at thermal plants decreased $4 million due to reduced unplanned outages; and

Qualified pension plan income decreased $5 million.

Energy Marketing
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 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. Since these announcements in 2002, IE has completed the major milestones outlined in the wind down of the business. These milestones include the sale of IE's forward book of electricity trading contracts to Sempra Energy Trading (SET) in August 2003, closing of the Denver, Houston and Boise operations and the final workforce termination in November 2003.

The sale of IE's forward book of electricity trading contracts to SET was approved by the FERC on September 26, 2003. To date, all but one of IE's counterparties have consented to the assignment of its contracts to SET. For that counterparty, IE still retains the credit risk. SET entered into transactions with IE that mirror the transactions of the counterparty that has not consented to the assignment. SET also agreed to service these remaining contracts for IE. The result of this agreement with SET is that IE was able to close down its day-to-day operations in November 2003.

As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with SET, 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 FASB Interpretation (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 the financial statements.

In 2002, IE incurred $5 million of involuntary termination benefit expenses and approximately $4 million of lease termination costs and other exit-related costs. As of December 31, 2002, IE paid $2 million of these costs with a remaining outstanding accrual of $7 million. In 2003, IE incurred an additional $4 million of involuntary termination benefit expenses and $1 million of lease termination costs and other exit related costs. During 2003, IE paid $8 million of these costs with a remaining outstanding accrual of approximately $5 million. The remaining termination benefit accrual will be paid out in 2004 and the remaining lease termination accrual will be paid out through 2008. 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 Selling, general and administrative expenses on the Consolidated Statements of Income and restructuring accruals are presented as Other Liabilities on the Consolidated Balance Sheets.

In connection with the wind down of energy marketing, certain matters were identified that required resolution with the FERC and the IPUC. The FERC matters have been resolved by the issuance of two FERC orders and the parties to the IPUC proceeding have executed a settlement agreement. This agreement was filed with the IPUC on February 17, 2004 and is subject to its approval. These matters are discussed in more detail in Note 13 to IDACORP's Consolidated Financial Statements.

IE reported an $18 million operating loss in 2003 compared to a $26 million of 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.

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 presented as a Net loss on legal disputes on the Consolidated Statement of Income.

The following table presents IE's energy marketing revenues and volumes for the last three years:

							2002-2003				2001-2002
							Increase				Increase
			2003		2002		(Decrease)		2001		(Decrease)
Net operating revenues:
	Electricity		$	19,267	$	42,304	$	(23,037)	$	330,793	$	(288,489)
	Gas			649		4,106		(3,457)		17,870		(13,764)
		Total	$	19,916	$	46,410	$	(26,494)	$	348,663	$	(302,253)

Operating volumes (settled):
	Electricity (MWh)			13,045,863		39,526,630		(26,480,767)		34,936,951		4,589,679
	Gas (MMbtu)			2,255,881		35,895,039		(33,639,158)		97,327,432		(61,432,393)

The decline in revenues and volumes between 2002 and 2003 was a result of the decision to wind down IE's power and gas marketing operations and the sale of its forward book of electricity trading contracts to SET in August 2003. The decision to wind down IE also affected the decline in revenues and volumes between 2001 and 2002, along with a sharp decline in regional prices, volatility and the decreasing number of creditworthy counterparties in 2002.

Selling, General and Administrative Expenses: Total selling, general and administrative (SG&A) expenses decreased $6 million in 2003 as a result of the wind down of operations. SG&A expenses decreased $36 million in 2002 due primarily to decreased allowance for bad debt and compensation expense compared to 2001. Allowance for bad debt expense decreased in 2002 due to unusually high bad debt expense in 2001 associated with reserves related to trading activities conducted with California entities in 2000. Compensation expense declined due to a reduction in profit-related incentives and a reduction in workforce related to the wind down of operations.

Ida-West
In 2003, IDACORP made the decision to wind down Ida-West's operations. This decision resulted from the development of IDACORP's new corporate strategy. The new strategy does not include the development or acquisition of merchant generation, which had been Ida-West's focus. IDACORP will either sell Ida-West or retain its remaining properties and manage them with a smaller staff.

Impairment charges, as discussed below, negatively affected Ida-West's earnings in both 2003 and 2002. In 2001, Ida-West reported a $5 million gain on the early redemption by the Friant Power Authority of bonds held by Ida-West.

Garnet impairment: In 2001, Garnet, a wholly owned subsidiary of Ida-West, entered into a PPA with IPC to provide energy to be produced by Garnet's proposed natural gas-fired plant. Due to dramatic changes in the electricity industry, financing of the project on acceptable terms under the PPA 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 PPA was mutually terminated. Also in 2003, IPC issued a formal RFP seeking bids for the construction of up to 200-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 PPA, the results of the RFP process and the decision to wind down operations, Ida-West determined that its remaining $3.6 million investment in the Garnet site development costs was uncertain of recovery 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. As a result, a total of $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 expenses.

In addition, a $2.6 million bad debt reserve was established 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.

Income Taxes
Audit Settlements: In 2003, IDACORP settled substantially all issues related to the Internal Revenue Service's examination of its federal income tax returns for the years 1998 through 2000. The settlement resulted in a benefit of $9 million, as the deficiencies assessed were less than previously accrued. Management believes that adequate provision for income taxes has been made for the open years 2001 and after and for any unsettled issues prior to 2001. Of this settlement benefit amount, $6 million was recorded in the fourth quarter.

In 2002, IPC settled income tax deficiencies related to its partnership investment in the Bridger Coal Company, covering the years 1991 through 1998. The settlement resulted in deficiencies that were less than previously accrued, enabling IPC to decrease income tax expense by approximately $3 million.

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 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. Net reductions in consolidated income taxes related to IFS tax credits were $20 million, $21 million and $13 million for the years 2003, 2002 and 2001, respectively.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's and IPC's operating cash flows in 2003 were $311 million and $185 million, respectively.

IPC's operating cash flows have decreased $182 million from 2002's level, which had been bolstered by tax refunds and the collection from electricity customers of power supply expenditures that had been incurred during prior years. Net income tax-related cash inflows of $18 million in 2002 changed to outflows of $100 million in 2003 and cash received from electric customers was approximately $65 million less in 2003 than in 2002. The tax refunds received in 2002 totaled approximately $90 million and related to the change in tax accounting method for capitalized overhead costs and net operating loss carrybacks associated with IPC's 2001 power supply costs.

IDACORP's consolidated cash flows from operations decreased $37 million in 2003, resulting from the IPC items mentioned above, offset by cash generated during the wind down of the energy marketing. Net operating cash flows from IE were $92 million in 2003, an improvement of $122 million over 2002, with the largest contributions being $40 million from the sale of the book of forward energy trading contracts and $45 million collected on notes receivable from Overton Power District No. 5. IE's future cash flows are expected to be limited. Its only significant remaining asset is $48 million in receivables, including $44 million from California entities, the collection of which is uncertain and for which reserves of $42 million have been established. The resolution of the other legal and regulatory matters discussed later in MD&A could also impact IE's future cash flows.

Working Capital
The wind down of energy marketing has been the primary influence on changes in IDACORP's working capital items during the year.

Energy marketing assets and liabilities reflect the fair value of energy marketing contracts as of the reporting date. The fair value of these contracts is unrealized and therefore does not necessarily indicate a current source or use of funds. The decreases in the net energy marketing assets and liabilities from 2002 to 2003 are a reflection of the wind down of the energy marketing business and sale of IE's book of forward electricity trading contracts.

Pension expense (income) totaled $12 million, $4 million and ($4 million) for the three years ended December 31, 2003, 2002 and 2001, respectively, including amounts allocated to capitalized labor costs. For 2004, pension expense is expected to total approximately $10 million, which takes into account a reduction of the discount rate from the 6.75 percent used in 2003 to 6.15 percent and returns on plan assets in 2003 that exceeded actuarial estimates. No changes were made to the other key assumptions used in the actuarial calculation.

Insurance Expenses
IPC's medical expenses for current and retired employees increased approximately $3 million from 2002 to 2003. This increase reflects the overall trends in health care costs and resulting health insurance premiums. In addition, IPC's property and liability insurance expense increased approximately $2 million from 2002 to 2003, reflecting higher premiums to insure power plants and other utility property. IPC forecasts that its 2004 insurance costs will continue to increase, but more moderately than in 2003.

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. IPC's capital expenditures from 2004 to 2006 are expected to total $643 million, significantly more than the $433 million expended in 2001 through 2003. IPC's construction program is discussed in more detail later in "Capital Requirements." The dividend reduction was also made to strengthen financial position, 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	2004	2005-2006	2007-2008	Thereafter
Long-term debt - IPC (a)				$930,945	$50,077	$60,161	$82,344	$738,363
Long-term debt - Other (a)				82,715	17,846	32,708	23,936	8,225
Capital lease obligations - Other (f)				97	-	97	-	-
Operating leases - IPC				4,316	1,465	2,692	86	73
Operating leases - Other (f)				1,776	616	987	173	-
Purchase obligations - IPC:
	Cogeneration and small power production			634,910	39,360	78,551	78,391	438,608
	Fuel swap			2,053	1,657	396	-	-
	Fuel supply agreements			128,134	34,810	56,294	19,807	17,223
	Purchased power & transmission			39,705	15,958	9,978	9,160	4,609
	Maintenance & service agreements (b)			48,960	20,745	12,314	5,823	10,078
	Other (c)			110,168	48,663	21,717	10,478	29,310
		Total IPC purchase obligations		963,930	161,193	179,250	123,659	499,828
Purchase obligations - Other (f)				1,584	1,235	304	30	15
Restructuring charges - Other (d)				4,595	2,746	1,137	712	-
Other long-term liabilities - IPC (e)				2,327	658	549	320	800
Total IDACORP				$1,992,285	$235,836	$277,885	$231,260	$1,247,304
Total IPC				$1,901,518	$213,393	$242,652	$206,409	$1,239,064

(a) For additional information, please see Note 5 to IDACORP's Consolidated Financial Statements.
(b) Approximately $27 million of the obligations included in the detail of the IPC maintenance and service agreements can be cancelled without
			penalty. Additionally, approximately $21 million of the contracts do not specify terms related to expiration. As these contracts will continue
			indefinitely, 10 years of information, estimated based on the current contract terms, has been included in the table for presentation purposes.
(c) Approximately $37 million of the contracts for the obligations included in the detail of IPC other purchase obligations do not specify terms
			related to expiration. As these contracts will continue indefinitely, 10 years of information, estimated based on the current contract terms,
			has been included in the table for presentation purposes.
(d) Restructuring charges relate to the wind down of IE. For additional information, please see Note 15 to IDACORP's Consolidated Financial
			Statements.
(e) Other Long-term liabilities reflected on the balance sheet under GAAP include Credit Facilities, Human Resources Information
			System (HRIS) license fee and lobbying agreements. The HRIS obligation of approximately $2 million can be cancelled without penalty.
			Additionally, as the contract does not specify terms related to the contract expiration, 10 years of information, estimated based on current
			contract terms, has been included in the table for presentation purposes.
(f) Includes the obligation of the subsidiaries of IDACORP with the exception of IPC, which is shown separately.

Off-Balance Sheet Arrangements
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, 2003. 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.

In August 2003, IE sold its forward book of electricity trading contracts to SET. As part of the sale of the forward book of electricity contracts IE entered into an Indemnity Agreement with SET, guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The impact of this guarantee on the consolidated financial statements was minimal.

Credit Ratings
On October 3, 2003, S&P changed its rating outlook for IDACORP and IPC to stable from positive. S&P stated that the stable rating outlook reflected the belief that overall financial ratios will only meet expectations for an A-rating over the next two to three years. S&P also changed the IDACORP business risk profile to a 4 from a 5 on a 10-point scale, where a 1 is the least risky. IPC's business risk profile remains a 4.

Access to capital markets at a reasonable cost is determined in large part by credit quality. The following outlines the current S&P, Moody's and Fitch ratings of IDACORP's and IPC's securities:

	Standard and Poor's		Moody's		Fitch
	IPC	IDACORP	IPC	IDACORP	IPC	IDACORP
Corporate Credit Rating	A-	A-	A3	Baa 1	None	None
Senior Secured Debt	A	None	A2	None	A	None
Senior Unsecured Debt	BBB+	BBB+	A3	Baa 1	A-	BBB+
Preferred Stock	BBB	None	Baa 2	None	BBB+	None
Trust Preferred Stock	None	None	None	Baa 2	None	BBB
Commercial Paper	A-2	A-2	P-1	P-2	F-1	F-2
Rating Outlook	Stable	Stable	Negative	Negative	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 2004 through 2006:

					2004		2005-2006
					(millions of dollars)
IPC Utility capital expenditures:
	Construction Expenditures (excluding AFDC):
		Generating facilities:
			Hydro		$	21	$	88
			Thermal			66		72
				Total generating facilities		87		160
		Transmission lines and substations				34		95
		Distribution lines and substations				56		130
		General				30		51
			Total construction expenditures (excluding AFDC)			207		436
	Long-term debt maturities					50		60
	Other					6		9
		Total IPC Utility				263		505

IFS capital expenditures						20		51
IFS long-term debt maturities						18		38
Other						7		12
	Total IDACORP				$	308	$	606

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.

IDACORP forecasts indicate that internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2004 through 2006. 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. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and externally financed capital.

Utility Construction Program: Construction expenditures were $148 million in 2003, $128 million in 2002 and $157 million in 2001. However, 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 (BMPP), which is currently estimated to cost $61 million. BMPP is discussed in more detail later in the MD&A in "Regulatory Issues".

IPC's aging hydroelectric facilities require continuing upgrade and component replacement. In addition, costs related to relicensing hydroelectric facilities are expected to increase substantially. The three-year construction program anticipates $41 million of upgrades to existing hydroelectric facilities and $56 million of costs associated with relicensing of hydroelectric facilities.

Continuing load growth also requires that IPC add to its transmission and distribution facilities system 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.

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 tax liability.

Financing Programs
IDACORP's consolidated capital structure fluctuated slightly during the three-year period, with common equity ending at 46 percent, preferred stock of IPC at three percent and long-term debt at 51 percent at December 31, 2003.

Credit facilities: IDACORP has a $175 million facility that expires on March 17, 2004 and a $140 million facility that expires on March 25, 2005. Under these facilities IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued up to the amounts supported by the bank credit facilities.

IPC has a $200 million facility that expires March 17, 2004. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC's corporate credit rating. IPC's commercial paper may be issued up to the amount supported by the bank credit facilities. At December 31, 2003, IPC had regulatory authority to incur up to $250 million of short-term indebtedness.

IDACORP and IPC plan to renew their credit facilities that expire in March 2004. IDACORP plans to replace its current $175 million 364-day facility, and its $140 million 3-year facility, with a reduced $150 million 3-year facility resulting from lower liquidity requirements at IDACORP. IPC plans to replace its current $200 million 364-day facility with a similar sized $200 million 3-year facility.

Short-term financings: At December 31, 2003, IPC had no short-term borrowings compared to $11 million at December 31, 2002. At December 31, 2003, IDACORP's short-term borrowing totaled $94 million, compared to $166 million at December 31, 2002. IDACORP's short-term borrowings decreased in 2003 due to lower liquidity requirements as a result of the 2002 decision to exit the power and natural gas trading and marketing business.

Long-term financings: IDACORP currently has two shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At December 31, 2003, none had been issued.

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, 2003, the auction rate was 1.15 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%.

On November 15, 2002, IPC issued $200 million of secured medium-term notes in two series; $100 million First Mortgage Bonds 4.75% Series due 2012 and $100 million First Mortgage Bonds 6.00% Series due 2032. Proceeds were used to pay down IPC short-term borrowings.

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 maturity and payment 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. At December 31, 2003, $160 million remained available to be issued on this shelf registration statement.

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, 2003, IPC could issue under the mortgage approximately $945 million of additional first mortgage bonds based on unfunded property additions and $342 million of additional first mortgage bonds based on retired first mortgage bonds. At December 31, 2003, unfunded property additions, which consist of electric property, were approximately $1 billion.

In August 2001, $25 million of First Mortgage Bonds 9.52% Series due 2031 were redeemed early using short-term borrowings. Also, in March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.

IPC redeemed its auction rate preferred stock in August 2002 for $50 million using short-term borrowings.

IPC plans to refund its $50 million First Mortgage Bonds 8.00% Series due March 15, 2004 with additional first mortgage bonds.

The following tax credit notes were issued by IFS during 2003:

	Issue Date
	March 12, 2003		July 15, 2003
Series		2003-1		2003-2
Principal Amount	$	25,475	$	15,000
Interest Rate		5.00%		3.98%
Maturity		2003-2010		2003-2009
Outstanding at December 31, 2003	$	20,305	$	13,550

Additionally, IFS borrowed $25 million from a corporate lender on July 25, 2003 at an interest rate of 3.65 percent. This debt matures from 2003-2008. At December 31, 2003, the amount outstanding was $23 million.

Proceeds from the issuance of these debt instruments were primarily used by IFS to pay intercompany notes to IDACORP, which then used these proceeds to reduce short-term borrowings. The debt for Series 2003-1 is non-recourse to both IFS and IDACORP. The debt for the remaining two issuances is recourse only to IFS.

Debt Covenants: IDACORP and IPC are subject to several debt covenants and restrictions. Under the terms of the Indenture relating to IPC's First Mortgage Bonds, net earnings must be at least two times the annual interest on all bonds and other equal or senior debt. At December 31, 2003, net earnings were 5.43 times.

Additionally, the credit facilities require IDACORP and IPC to maintain a ratio of debt to total capitalization (leverage ratio) of no more than 65 percent. At December 31, 2003, IDACORP's and IPC's leverage ratios were 55 percent and 52 percent, respectively. IDACORP is also required to maintain an interest coverage ratio of at least 2.75 to one. At December 31, 2003, IDACORP was in compliance with this requirement.

LEGAL AND ENVIRONMENTAL ISSUES:

Legal and Other Proceedings
Vierstra Dairy v. Idaho Power Company: On August 11, 2000, Mike and Susan Vierstra, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs sought monetary damages in the amount of approximately $8 million for negligence and nuisance (allegedly allowing electrical current to flow in the earth and adversely affect the health of plaintiffs' dairy cows) and punitive damages in the amount of approximately $40 million.

On February 10, 2004, a jury verdict in favor of the plaintiffs was entered, awarding approximately $7 million in compensatory damages and $10 million in punitive damages. IPC intends to appeal this decision.

IPC is unable to predict the outcome of this matter; however, based upon the information provided to date, IPC's insurance carrier has confirmed coverage. IPC has previously expensed the full amount of its self-insured retention. With coverage, this matter will not have a material adverse effect on IPC's consolidated financial position, results of operations or cash flows.

California Energy Proceedings at the FERC:
IE and IPC are involved in a number of FERC proceedings arising out of the California energy situation. 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 (SCE) default and later by the Pacific Gas & Electric Company (PG&E) default. FERC has ordered the CalPX to rescind all chargeback actions related to the SCE and PG&E 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 (FPA). The FERC issued an order on refund liability on March 26, 2003 which multiple parties, including IE, sought rehearing on. On October 16, 2003, FERC denied the requests for rehearing and required the California Independent System Operator (Cal ISO) to make a compliance filing regarding refund amounts by August 2004. At December 31, 2003, 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, 2003, 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 operation or cash flows; (3) in the Pacific Northwest refund proceedings 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 have been appealed to the Court of Appeals for the Ninth Circuit. The Company is unable to predict the outcome of this matter; and (4) two cases which result from a ruling of the United States Court of Appeals for 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 (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. The order approving the "gaming" settlement is subject to rehearing requests for 30 days. The FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. The Company has submitted all data and information requested by the FERC and is awaiting FERC action, and IDACORP and IPC believe that any potential penalties imposed by the FERC would not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

These matters are discussed in 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
U.S. Commodity Futures Trading Commission Investigations Regarding Trading Practices: On October 2, 2002, the U.S. Commodity Futures Trading Commission (CFTC) issued a subpoena to IPC requesting, among other things, all records related to all natural gas and electricity trades by IPC involving "round trip trades," also known as "wash trades" or "sell/buyback trades" including, but not limited to those made outside the Western Systems Coordinating Council region. The subpoena applies to both IE and IPC. By letter from the CFTC dated October 7, 2002, the Division of Enforcement agreed to hold in abeyance until a later date all items requested in the subpoena with the exception of one paragraph which related to three trades on a certain date with a specific party. The companies provided the requested information.

On January 14, 2003, IPC received a request from the CFTC, pursuant to the October 2002 subpoena, for documents related to "round trip" or "wash trades" and information supplied to energy industry publications. The request applies to both IPC and IE. The companies stated in their response to the CFTC that they did not engage in any "round trip" or "wash trade" transactions and that they believe the only information provided to energy industry publications was actual transaction data. The companies have provided the requested information and have heard nothing further from the CFTC.

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 five of the right-of-way permits for the transmission lines, which have stated permit expiration dates between 1996 and 2003. IPC has filed applications with the United States Department of the Interior, Bureau of Indian Affairs, to renew the five 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). The Tribes have not agreed to renew the rights-of-way and have demanded a substantially greater payment of $19 million, including an up-front payment of $4 million with the remainder to be paid over the 25 year term of the permits, or in the alternative $11 million including an up-front payment of $4 million with the remainder paid over the first three years of the permits. This is based on an "opportunity cost" methodology, which calculates the value of the rights-of-way as a percentage of the cost to IPC of relocating the transmission lines off the Reservation. Both parties have discussed potential legal action regarding renewal of the rights-of-way, but no such action has been taken to date. The probable cost of renewing the rights-of-way is difficult to ascertain due to the lack of definitive legal guidelines for the renewals. IPC believes that the amount payable for 25-year rights-of-way should not exceed $11 million, which represents the approximate present value of the offers communicated to date by the Tribe. IPC plans to obtain IPUC approval for the recovery of any renewal payment in its utility rates as a prerequisite to any settlement of the right-of-way renewals with the Tribe.

Environmental Issues
Threatened and Endangered Snails: In December 1992, the United States Fish and Wildlife Service (USFWS) listed five species of snails that inhabit the middle Snake River as threatened or endangered species under the Endangered Species Act (ESA). In 1995, in preparation for the FERC relicensing of certain of IPC's hydroelectric projects, IPC obtained a permit from the USFWS to study the listed snails. Since that date, IPC has been collecting field data and conducting studies in an effort to determine the status of the listed snails and how they may be affected by a variety of factors, including hydroelectric production, water quality and irrigation practices.

Based upon the studies initiated by IPC in 1995, in July and October of 2002, IPC, in cooperation with the State of Idaho, filed petitions with the USFWS to remove the Bliss Rapids snail and Idaho springsnail from the federal list of threatened and endangered wildlife. Due to the pending relicensing proceedings at the FERC and the ESA consultation between the FERC and the USFWS on the potential effect of project operations on ESA listed snails, IPC submitted the petitions, and the studies upon which they were based, to the FERC for inclusion in the Mid-Snake and CJ Strike relicensing proceedings.

On December 13, 2002, because of inconsistencies discovered between the field data collected by IPC since 1995, the macro invertebrate database into which the field data were entered and the use of that database in the preparation of the studies used to support the pending petitions, IPC notified the USFWS and the FERC that it was withdrawing the petitions. IPC then retained an independent scientist to review the snail studies. This review was completed in April 2003 and IPC submitted the report to the FERC on April 30, 2003.

The report identified discrepancies in the annual snail survey reports (1995-2001) that were used to support the petitions to delist the Bliss Rapids snail and Idaho springsnail. These discrepancies included: errors in summarization of field data and the entry of the data into the macro invertebrate database; errors in compiling data for analysis; calculation or extrapolation errors; and the lack of a standard measure for expressing snail relative abundance data. While the report concluded that annual snail surveys were unreliable because of these discrepancies, it also concluded that the primary or underlying data that were used to prepare the annual survey reports appeared to be complete and, as a consequence, could be used to correct any errors in the annual reports.

Due to the importance of these snail data to issues pending in the relicensing of IPC's hydroelectric projects and the pending ESA consultation between the FERC and the USFWS, IPC retained the independent scientist that conducted the review to analyze the primary data used to prepare the 1995-2001 snail survey reports and to prepare new and corrected annual reports. In October and November 2003, IPC provided the FERC and the USFWS with revised annual reports for 1995-2001.

By letters dated August 5, 2003, IPC and the USFWS advised the FERC that they initiated efforts to reach a cooperative resolution of outstanding fish and wildlife issues associated with the relicensing of the Mid-Snake and CJ Strike projects, including issues relating to threatened and endangered snails and advised the FERC that they hoped to complete these efforts within 90 days of August 5, 2003. On August 14, 2003, the FERC responded to IPC advising it would not take action on the licenses prior to the expiration of the 90-day period. In subsequent progress reports to the FERC on IPC and the USFWS efforts, IPC and the USFWS requested an additional 90days to complete their discussions. On December 3, 2003, FERC advised IPC and the USFWS that it would take no action on the pending applications prior to the expiration of the 90-day period. On February 12, 2004, IPC, on behalf of itself and the USFWS, presented an Offer of Settlement, including a signed Settlement Agreement and attached Appendices, to the FERC addressing issues associated with the ESA listed threatened and endangered snails and the relicensing of the Mid-Snake and CJ Strike projects. Pursuant to FERC regulations, participants in the licensing proceeding and other interested persons have until March 3, 2004 to comment on the proposed settlement. If the proposed settlement is approved by the FERC, it is expected that the FERC and the USFWS will complete ESA consultation on the projects and the FERC will thereafter issue new licenses for the projects.

Environmental Regulation Costs: IPC anticipates $14 million in annual operating costs for environmental facilities during 2004. Hydroelectric facility expenses account for $9 million of this total and $5 million is related to thermal plant operating expenses. From 2005 through 2006, total environmental related operating costs are estimated to be $28 million. Anticipated expenses related to the hydroelectric facilities account for $18 million and thermal plant expenses are expected to total $10 million during this period.

REGULATORY ISSUES:

General Rate Case
IPC filed an application with the IPUC on October 16, 2003 to increase its general rates an average of 17.7 percent. If approved, IPC's revenues would increase $86 million annually based on the proposed 11.2 percent return on equity. An additional component of the filing was a request for interim rate relief of $20 million. The IPUC turned down IPC's request for interim rate relief in Order No. 29403 on December 22, 2003 noting that the denial of interim rate relief was not an indication of the ultimate merits of the case.

In addition, IPC has proposed extensive rate design changes including seasonal rates for most customers, increased fixed charges for smaller customer classes and time of day rates for industrial customers. If approved, the price IPC charges its customers from June to August would reflect IPC's seasonably higher costs of producing or purchasing power. The change would result in summer and non-summer base rates. In connection with the seasonal pricing proposal, IPC recommended the annual PCA rate changes be implemented June 1 each year instead of May 16. If approved, this change would eliminate the need for back-to-back rate changes and the PCA recovery period would be June 1 through May 31.

the parties' increase in base rates testimony and exhibits can be viewed at the IPUC web site. IPC has until March 19, 2004 to prepare its rebuttal to these recommendations.

IPC's proposal requests revenue recovery for certain costs of serving its customers, such as increased operating expenses and substantial demands for infrastructure improvements, increased capital costs for the PM&E requirements of new licenses at most of its hydroelectric projects, for the cost of new sources of power and continued expansion of its transmission and distribution network. Because the Idaho jurisdiction does not allow assets that have not been placed in service to be included in the rate base, BMPP and relicensing costs included in Construction Work in Process (CWIP) are not included in this filing. IPC is requesting an 11.2 percent return on equity and an overall rate of return of 8.4 percent. The success of this rate case is dependent on the IPUC review and approval, which could take up to seven months from the filing date. IPC is unable to predict what rate relief the IPUC will grant.

Deferred Power Supply Costs
IPC's deferred power supply costs consist of the following at December 31, 2003 and 2002:

			2003		2002
Oregon deferral			$	13,620	$	14,172
Idaho PCA current year power supply cost deferrals:
	Deferral for 2003-2004 rate year			44,664		-
	Deferral for 2002-2003 rate year			-		8,910
	Astaris load reduction agreement			-		27,160
Idaho PCA true-up awaiting recovery:
	Irrigation and small general service deferral for recovery in
		the 2003-2004 rate year		-		12,049
	Industrial customer deferral for recovery in the 2003-2004 rate year			-		3,744
	Remaining true-up authorized May 2002			-		74,253
	Remaining true-up authorized May 2003			13,646		-
	Total deferral		$	71,930	$	140,288

Idaho: IPC has a PCA mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments, which take effect in May, are based on forecasts of net power supply costs (fuel and purchased power less sales for resale) 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 a true-up, is then included in the calculation of the next year's PCA adjustment.

On April 15, 2003, IPC filed its 2003-2004 PCA with the IPUC, and, with a small adjustment to the filing, the rates were approved by the IPUC and became effective on May 16, 2003. As approved, IPC's rates have been adjusted to collect $81 million above 1993 base rates, a $114 million reduction from the 2002-2003 PCA.

So far in the 2003-2004 PCA rate year, actual power supply costs have exceeded those anticipated in the forecast, due principally to greater reliance on, and higher market prices for, purchased power. Below normal water conditions also continue to negatively impact forecasted and actual power supply costs.

On May 13, 2002, the IPUC issued Order No. 29026 related to the 2002-2003 PCA rate filing. The order granted recovery of $255 million of excess power supply costs, while it denied recovery of $12 million of lost revenues resulting from the Irrigation Load Reduction Program, and $2 million of other costs IPC sought to recover.

The IPUC had previously issued Order No. 28992 on April 15, 2002 disallowing the lost revenue portion of the Irrigation Load Reduction Program. IPC believes that this IPUC order is 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 still believes it should be entitled to receive recovery of this amount and argued its position before the Idaho Supreme Court on December 5, 2003. If successful, IPC would record any amount recovered as revenue.

In the May 2001 PCA filing, IPC requested recovery of $227 million of power supply costs. The IPUC subsequently issued Order No. 28772 authorizing recovery of $168 million, but deferring recovery of $59 million pending further review. The approved amount resulted in an average rate increase of 31.6 percent. After conducting hearings on the remaining $59 million, the IPUC, in Order No. 28552, authorized recovery of $48 million plus $1 million of accrued interest, beginning in October 2001. The remaining $11 million not recovered in rates from the PCA filing was written off in September 2001.

In October 2001, IPC filed an application with the IPUC for an order approving inclusion in the 2002-2003 PCA of costs incurred for the Irrigation Load Reduction Program and the FMC/Astaris Load Reduction Agreement. These two programs were implemented in 2001 to reduce demand and were approved by the IPUC and the OPUC. The costs incurred in 2001 for these two programs were $70 million for the Irrigation Load Reduction Program and $62 million for the FMC/Astaris Load Reduction Agreement. The IPUC subsequently issued Order No. 28992 authorizing IPC to include direct costs it has accrued in the programs, subject to later adjustments in the 2002-2003 PCA year. As mentioned earlier, the IPUC also denied IPC's request to recover lost revenues experienced from the Irrigation Load Reduction Program.

Oregon: IPC also filed applications with the OPUC to recover calendar year 2001 extraordinary power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC approved rate increases totaling six percent, which is the maximum annual rate of recovery allowed under Oregon state law. These increases are recovering approximately $2 million annually. The Oregon deferred balance was $14 million as of December 31, 2003. During the 2003 Oregon legislative session, the maximum annual rate of recovery was raised to ten percent under certain circumstances. IPC expects to request the higher recovery percentage in the spring of 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 (VLR) Agreement between IPC and FMC/Astaris. This VLR Agreement amended the Electric Service Agreement (ESA) 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 (Agreement) with the IPUC and on June 10, 2002, the IPUC approved the Agreement in Order No. 29050 which included the following provisions:

The VLR 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 ESA.

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 ESA.

Integrated Resource Plan
Every two years, IPC is required to file with both the IPUC and OPUC an IRP, a comprehensive analysis of IPC's present and future demands for electricity and the plan for meeting that demand. The 2002 IRP identified the need for additional resources to address potential electricity shortfalls within IPC's utility service territory by mid-2005. Originally, the Garnet plant was selected as the resource to meet future needs. However, the Garnet plant did not prove to be financially viable and the 2002 IRP action plan was modified, as explained below.

On February 11, 2003, the IPUC issued Order No. 29189, which accepted and acknowledged IPC's 2002 IRP as modified, and directed IPC to implement certain changes in its 2004 IRP related to both the public process and the evaluation of demand-side options. The accepted IRP indicated the purchase of 100-MW from the wholesale market for IPC's retail customers during June, July, November and December.

PPL Montana Power Purchase Agreement: During May 2003, IPC and PPL Montana, LLC (PPLM) entered into a firm wholesale PPA under which IPC will purchase energy from PPLM to address increased demand during June, July and August from 2004 through 2009. With the exception of the month of August 2004, in which the quantity of energy to be purchased is 26 MW per hour, during each month of the PPA IPC will purchase 83 MW per hour from PPLM at a price of $44.50 per MWh. After deducting transmission losses, IPC will receive approximately 80 MW per hour. The IPUC approved this PPA on July 8, 2003.

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 BMPP, a 160-MW gas-fired generating plant near Mountain Home, Idaho. TR2 has 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 fully tested and operational.

IPC filed an application with the IPUC on September 26, 2003 for a Certificate of Public Convenience and Necessity for the BMPP. On October 30, 2003, the IPUC issued Order No. 29370 placing the case on Modified Procedure. The IPUC approved the certificate to BMPP through Order No. 29410 and Order No. 29422.

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 (AMR) as soon as practicable, subject to updated analysis showing AMR to be cost effective for customers. As ordered by the IPUC, IPC submitted an updated analysis on May 9, 2003. A workshop with 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 AMR 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. IPC will include these costs in future rate filings.

Relicensing of Hydroelectric Projects
IPC, like other utilities that operate nonfederal hydroelectric projects, obtains licenses for its hydroelectric projects from the FERC. These licenses last for 30 to 50 years depending on the size and complexity of the project. Currently, the licenses for five hydroelectric projects have expired. These projects continue to operate under annual licenses until the FERC issues a new multi-year license. Three more of IPC's hydroelectric project licenses will expire by 2010.

IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years. The current status of IPC's relicensing efforts is summarized in the table below:

Projects	Current status
Bliss, Upper Salmon Falls, Lower Salmon	Annual licenses issued under terms and conditions of the expired
Falls, Shoshone Falls and CJ Strike	multi-year license. Final Environmental Impact Statements have
	been issued. FERC licenses anticipated in 2004.

Upper Malad and Lower Malad	License expires in 2004. New license application filed in July 2002.

Brownlee-Oxbow-Hells Canyon (HCC)	License expires in 2005. New license application filed in July 2003.

The most significant relicensing effort is the HCC, which provides approximately two-thirds of IPC's hydroelectric generation capacity and 40 percent of its total generating capacity. IPC developed the license application for the HCC through a collaborative process involving representatives of state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests. The license application for the HCC was filed in July 2003. The application includes existing and proposed PM&E measures estimated to total (assuming a 30-year license) approximately $106 million in the first five years of the license and $218 million over the following 25 years. However, the actual costs of the PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC. The current license for the project expires in July 2005. IPC will thereafter operate the project under annual licenses issued by the FERC until the new multi-year license is issued.

The four Mid-Snake River projects (Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls) and the CJ Strike projects may affect five species of snails listed under the ESA. See previous discussion in "LEGAL AND ENVIRONMENTAL ISSUES - Environmental Issues - Threatened and Endangered Snails."

At December 31, 2003, $61 million of relicensing costs were included in CWIP and $8 million of relicensing costs were included in Electric Plant in Service. The relicensing costs are recorded and held in CWIP until a new multi-year license or annual license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service. Relicensing costs and costs related to the new licenses, as discussed above, will be submitted to regulators for recovery through the rate-making process. The current Idaho general rate case filing includes $10 million of relicensing costs.

American Rivers Petition: On May 1, 2003, American Rivers and Idaho Rivers United petitioned the United States 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 (NMFS) on the effects of the ongoing operations of IPC's HCC on four species of Snake River salmon and steelhead trout that are listed as threatened or endangered under the ESA. American Rivers contends that consultation is necessary because the operations of the HCC have a current, adverse impact on the listed anadromous fish.

IPC contested the 1997 petition before the FERC on several bases: first, that there is no evidence to support the American Rivers contention that the operations of the HCC have an adverse impact on ESA listed species; and second, that neither the ESA nor the FPA grant the FERC the type of discretionary federal control that constitutes the consultation-triggering federal action required under Section 7(a)(2) of the ESA. Since 1997, the FERC has taken no action on the pending petition, but has been engaged in informal discussions with IPC and the NMFS on issues associated with the effect of HCC operations on fishery resources below the HCC. Some of these discussions have occurred in the context of the Snake River Basin Adjudication mediation, which is subject to a court imposed confidentiality order.

On June 30, 2003, the FERC filed a response to the Petition for Mandamus. The FERC opposed the petition, first, because there was no federal action before the FERC to trigger a consultation responsibility under ESA Section 7(a)(2); second, because there was no evidence to substantiate the allegations of the petitioners that the ESA listed species have continued to decline since the filing of the original petition with the FERC in 1997; and lastly, because there were no grounds to support the allegations of unreasonable delay given the ongoing interaction between the FERC, IPC and other interested parties with regard to issues associated with the ESA listed species and the HCC. IPC filed a brief in support of the FERC's position on July 3, 2003. The petitioners filed a reply in support of the Petition for Mandamus with the court on July 8, 2003. The court granted IPC intervention and set the matter for oral argument on March 16, 2004.

Regional Transmission Organizations
In December 1999, the FERC, in its landmark Order No. 2000, said that all companies with transmission assets must file to form Regional Transmission Organizations (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 seeks to further facilitate the formation of efficient, competitive wholesale electricity markets.

These FERC filings represent a portion of the filings necessary to form RTO West. Additional filings will be necessary to include the tariff and integration agreements associated with the new entity. State approvals also need to be obtained. In September 2002, the FERC issued an order granting in part RTO West's Stage Two request for a declaratory order, approving with modification the majority of the proposed plan for development of a RTO by ten utilities in the northwest and Canada, including the Bonneville Power Administration (BPA). IPC is one of the filing utilities. With further development of detail and some modification, the FERC stated that the proposal "will satisfy not only the Order No. 2000 requirements, but can also provide a basic framework for standard market design for the West". Further development of the RTO West proposal by the filing utilities continues.

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

In late summer and fall 2003, task groups from the RRG focused on developing different option packages to address the region's transmission problems and opportunities. As this effort proceeded, however, many regional parties felt it would be preferable to work toward a single proposal that could gain broad regional support. To further this goal, the RRG formed a small task team to take into account all of the various perspectives, priorities and concerns that regional parties had identified during the course of discussions since June 2003, and, working on behalf of the RRG as a whole, to develop the best proposal it could in view of these considerations.

In April 2003, the FERC issued its "White Paper: Wholesale Market Platform," and "Appendix A: Comparison of the Proposed Wholesale Market Platform with the RTO Requirements of Order No. 2000." The Wholesale Market Platform (WMP) White Paper set forth the FERC's then-current thinking on issues under consideration in the Standard Market Design (SMD) proceeding. It focused in particular on the elements that must be in place for well-functioning wholesale markets. Appendix A provided a comparison of Order No. 2000's existing requirements for RTOs with the proposed requirements of the WMP that would apply to RTOs and independent system operators (ISOs). The Commission 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 SMD proceeding. Among other things, the White Paper:

Set forth the FERC's assessment of how best to move forward in the electric industry and how the FERC intended to change its proposed rulemaking on the SMD issued in 2002 based on concerns that were raised with respect to the proposed rule;

Stated the FERC's intent to eliminate the proposed requirement that public utilities create or join an Independent Transmission Provider and, instead, to require public utilities to join an RTO or an ISO;

Called for phase-in implementation and sequencing tailored to each region allowing for modifications to benefit customers within each region;

Indicated that the FERC would not require implementation of a feature of the market platform if the costs outweighed its benefits for a particular RTO or ISO;

Called for the inclusion of market power mitigation measures but not divestiture of vertically integrated utilities; and

Launched the commencement of technical conferences in the various regions.

The FERC's existing timetable for finalization requires that jurisdictional utilities must file open-access transmission tariffs with any remaining revisions and be operating under the SMD by September 30, 2004.

OTHER MATTERS:

New Accounting Pronouncement
FIN 46: In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation (FIN) 46, "Consolidation of Variable Interest Entities." In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R provides guidance related to identifying variable interest entities (VIEs, previously known as special purpose entities or SPEs) and determining whether such entities should be consolidated. Certain disclosures are required if it is reasonably possible that a company will consolidate or disclose information about a VIE when it initially applies FIN 46R. FIN 46 was required to be applied immediately to VIEs created or obtained after January 31, 2003. During 2003, IDACORP and IPC did not participate in the creation of, or obtain a new variable interest in, any VIE. For those VIEs created or obtained on or before January 31, 2003, IDACORP and IPC must apply the provisions of FIN 46R in the first quarter of 2004.

IDACORP and IPC are in the final stages of their analysis of FIN 46R and the majority of their investments, principally IFS' affordable housing investments are not expected to meet the criteria for consolidation included in FIN 46R. IDACORP and IPC do not expect the adoption of this standard to have a material effect on their financial statements.

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, 2003.

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, 2003, IDACORP and IPC had $151.6 million and $118.7 million, respectively, in variable 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, 2003, interest rate expense would increase and pre-tax earnings would decrease by approximately $1.5 million for IDACORP and $1.2 million for IPC.

Fixed Rate Debt: As of December 31, 2003, IDACORP and IPC had outstanding fixed rate debt of $893.6 million and $810.9 million, respectively. The fair market value of this debt was $920.8 million and $835.2 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 $65.9 million for IDACORP and $63.9 million for IPC if interest rates were to decline by one percentage point from their December 31, 2003 levels.

Commodity Price Risk
Utility: IPC is exposed to changes in commodity prices related to the purchases and sales of electricity as part of its ongoing utility operations. IPC is exposed to this risk to the extent that a portion of the electric energy it is required to sell to its customers at fixed rates may be purchased at wholesale electric market prices, which can be higher than the fixed sales rate received. IPC's exposure to this risk is offset to some extent by the previously discussed PCA mechanism in place in Idaho. The objective of IPC's market price risk management program is to mitigate the risk associated with the purchase and sale of electricity, while balancing this risk against system reliability and cost considerations.

IPC has adopted a risk management policy to address commodity price risk. The Risk Management Committee (RMC), comprised of IPC officers and other senior staff, oversees the risk management program. On a regular basis, the RMC reviews multiple system resource and load projections and evaluates the potential impacts of changes in four key variables: wholesale prices, system loads, system resources and streamflow conditions. The RMC controls the risk by assessing the impact of changes in the variables on power supply cost and projected volumetric surplus and deficit data, and by reviewing forward price curves for electricity and gas. The RMC then orders an appropriate risk mitigating action. Actions may be undertaken only with creditworthy counterparties.

On August 1, 2002, due to the wind down of energy marketing, all utility-related wholesale energy and gas transaction processes were returned to IPC. These activities are focused on meeting system requirements and capitalizing on system-related opportunities that can be risk managed.

Energy Trading: The sale of IE's forward book of electricity trading contracts to SET 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 SET, 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 the 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, 2003, 2002 and 2001		50
Consolidated Balance Sheets as of December 31, 2003 and 2002		51-52
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001		53
Consolidated Statement of Shareholders' Equity for the Years Ended December 31, 2003, 2002
	and 2001	54
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2003,
	2002 and 2001	55
Notes to the Consolidated Financial Statements		56-86
Independent Auditors' Report		87

Idaho Power Company
Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001		88
Consolidated Balance Sheets as of December 31, 2003 and 2002		89-90
Consolidated Statements of Capitalization as of December 31, 2003 and 2002		91
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001		92
Consolidated Statement of Retained Earnings for the Years Ended December 31, 2003, 2002
	and 2001	93
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2003,
	2002 and 2001	93
Notes to the Consolidated Financial Statements		94-98
Independent Auditors' Report		99

Supplemental Financial Information and Consolidated Financial Statement Schedules
Supplemental Financial Information (Unaudited)		100

Financial Statement Schedules for the Years Ended December 31, 2003, 2002 and 2001:
Schedule II-Consolidated Valuation and Qualifying Accounts-IDACORP, Inc.		110
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho Power Company		111

IDACORP, Inc.
Consolidated Statements of Income

				Year Ended December 31,
				2003		2002		2001
				(thousands of dollars except for per share amounts)
OPERATING REVENUES:
	Electric utility:
		General business		$	670,969	$	772,035	$	650,608
		Off-system sales			71,573		55,031		219,966
		Other revenues			40,178		41,974		43,627
			Total electric utility revenues		782,720		869,040		914,201
	Energy marketing				19,916		46,410		348,663
	Other				20,366		13,350		12,448
		Total operating revenues			823,002		928,800		1,275,312

OPERATING EXPENSES:
	Electric utility:
		Purchased power			150,980		142,102		584,209
		Fuel expense			99,898		102,871		98,318
		Power cost adjustment			70,762		170,489		(175,925)
		Other operations and maintenance			220,983		207,355		210,763
		Depreciation			97,650		93,609		87,041
		Taxes other than income taxes			20,753		19,953		19,693
			Total electric utility expenses		661,026		736,379		824,099
	Energy marketing:
		Cost of revenues			1,250		42,113		105,904
		Selling, general and administrative			24,349		30,427		66,047
		Net loss on legal disputes			12,072		-		-
	Other				40,243		44,241		36,973
			Total operating expenses		738,940		853,160		1,033,023

OPERATING INCOME (LOSS):
	Electric utility				121,694		132,661		90,102
	Energy marketing				(17,755)		(26,130)		176,712
	Other				(19,877)		(30,891)		(24,525)
		Total operating income			84,062		75,640		242,289

OTHER INCOME					24,412		19,218		33,600

OTHER EXPENSE					18,083		15,388		10,306

INTEREST EXPENSE AND OTHER:
	Interest on long-term debt				58,670		54,147		55,783
	Other interest				2,832		10,211		14,540
	Preferred dividends of Idaho Power Company				3,430		4,587		5,400
		Total interest expense and other			64,932		68,945		75,723

INCOME BEFORE INCOME TAXES					25,459		10,525		189,860

INCOME TAX (BENEFIT) EXPENSE					(21,119)		(51,147)		64,646

NET INCOME				$	46,578	$	61,672	$	125,214

AVERAGE COMMON SHARES
	OUTSTANDING (000's)				38,186		37,729		37,387

EARNINGS PER SHARE OF COMMON
	STOCK (basic and diluted)			$	1.22	$	1.63	$	3.35

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets

			December 31,
			2003		2002
ASSETS			(thousands of dollars)

CURRENT ASSETS:
	Cash and cash equivalents		$	75,159	$	42,736
	Receivables:
		Customer		93,599		176,846
		Allowance for uncollectible accounts		(43,210)		(43,311)
		Employee notes		3,347		3,240
		Other		8,209		5,691
	Energy marketing assets			4,176		85,138
	Accrued unbilled revenues			30,869		35,714
	Materials and supplies (at average cost)			21,351		22,812
	Fuel stock (at average cost)			6,228		6,943
	Prepayments			27,779		34,872
	Regulatory assets			6,269		17,147
		Total current assets		233,776		387,828

INVESTMENTS				204,474		206,348

PROPERTY, PLANT AND EQUIPMENT:
	Utility plant in service			3,220,228		3,086,965
	Accumulated provision for depreciation			(1,239,604)		(1,157,287)
		Utility plant in service - net		1,980,624		1,929,678
	Construction work in progress			96,091		96,209
	Utility plant held for future use			2,438		2,335
	Other property, net of accumulated depreciation			9,166		15,950
		Property, plant and equipment - net		2,088,319		2,044,172

OTHER ASSETS:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,624		35,299
	Energy marketing assets - long-term			14,358		64,733
	Regulatory assets			427,760		482,159
	Long-term receivables			3,106		75,915
	Employee notes			4,775		4,615
	Other			57,949		54,514
		Total other assets		575,157		748,820

		TOTAL	$	3,101,726	$	3,387,168

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets

				December 31,
				2003		2002
LIABILITIES AND SHAREHOLDERS' EQUITY				(thousands of dollars)

CURRENT LIABILITIES:
	Current maturities of long-term debt			$	67,923	$	89,592
	Notes payable				93,650		176,200
	Accounts payable				60,916		130,930
	Energy marketing liabilities				4,317		59,917
	Taxes accrued				35,580		46,566
	Interest accrued				13,741		13,639
	Deferred income taxes				5,639		21,203
	Other				25,557		35,118
		Total current liabilities			307,323		573,165

OTHER LIABILITIES:
	Deferred income taxes				554,715		595,820
	Energy marketing liabilities - long-term				14,393		51,761
	Regulatory liabilities				258,524		251,921
	Other				104,290		87,605
		Total other liabilities			931,922		987,107

LONG-TERM DEBT					945,834		898,676

COMMITMENTS AND CONTINGENT LIABILITIES

PREFERRED STOCK OF IDAHO POWER COMPANY					52,366		53,393

SHAREHOLDERS' EQUITY:
	Common stock, no par value (shares authorized 120,000,000;
		38,341,358 and 38,152,436 shares issued, respectively)			473,904		470,361
	Retained earnings				397,167		415,315
	Accumulated other comprehensive income (loss)				(2,630)		(7,109)
	Treasury stock (134,737 and 134,667 shares at cost, respectively)				(4,160)		(3,740)
		Total shareholders' equity			864,281		874,827

			TOTAL	$	3,101,726	$	3,387,168

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Cash Flows

					Year Ended December 31,
					2003		2002		2001
					(thousands of dollars)
OPERATING ACTIVITIES:
	Net income				$	46,578	$	61,672	$	125,214
	Adjustments to reconcile net income to net cash provided by
		(used in) operating activities:
			Other than temporary decline in market value of investments			1,948		980		-
			Net loss on legal disputes			12,072		-		-
			Impairment of long-lived asset			3,498		8,064		-
			Allowance for uncollectible accounts			2,538		782		19,450
			Unrealized (gains) losses from energy marketing activities			42,517		65,965		(92,803)
			Gain on sales of assets			-		-		(1,605)
			Depreciation and amortization			129,070		122,831		109,976
			Deferred taxes and investment tax credits			(61,985)		(110,666)		152,938
			Accrued PCA costs			68,358		164,201		(184,584)
			Change in:
				Receivables and prepayments		91,991		27,749		31,470
				Accrued unbilled revenues		4,845		1,687		7,425
				Materials and supplies and fuel stock		2,175		3,645		-
				Accounts payable and other accrued liabilities		(70,342)		(145,868)		3,914
				Taxes receivable/accrued		(10,986)		98,970		(66,821)
				Other current assets		-		-		(46,893)
				Other current liabilities		(6,412)		40,614		(2,180)
				Long-term receivable		51,394		-		(73,706)
				Other assets		(8,080)		869		6,300
				Other liabilities		12,065		6,921		3,315
			Net cash provided by (used in) operating activities			311,244		348,416		(8,590)
INVESTING ACTIVITIES:
	Additions to property, plant and equipment					(149,149)		(134,223)		(179,056)
	Investments in affordable housing projects					-		(43,939)		-
	Proceeds from sales of assets					-		-		11,261
	Other assets					(1,358)		(5,332)		1,046
	Other liabilities					(3,074)		(3,834)		(3,469)
			Net cash used in investing activities			(153,581)		(187,328)		(170,218)
FINANCING ACTIVITIES:
	Proceeds from issuance of first mortgage bonds					140,000		200,000		120,000
	Proceeds from issuance of other long-term debt					65,492		-		-
	Proceeds from issuance of pollution control bonds					49,800		-		-
	Retirement of first mortgage bonds					(160,000)		(77,000)		(130,000)
	Retirement of pollution control bonds					(49,800)		-		-
	Retirement of other long-term debt					(20,203)		(12,403)		(14,454)
	Retirement of preferred stock of Idaho Power Company					(860)		(50,994)		(679)
	Dividends on common stock					(64,726)		(70,178)		(69,782)
	Increase (decrease) in short-term borrowings					(82,550)		(186,300)		241,900
	Common stock issued					4,123		15,770		618
	Acquisition of treasury shares					(799)		(998)		(7,968)
	Distributions of treasury shares					-		-		2,575
	Other assets					(5,141)		(2,360)		(3,375)
	Other liabilities					(576)		(577)		(134)
			Net cash (used in) provided by financing activities			(125,240)		(185,040)		138,701
Net increase (decrease) in cash and cash equivalents						32,423		(23,952)		(40,107)
Cash and cash equivalents beginning of period						42,736		66,688		106,795
Cash and cash equivalents at end of period					$	75,159	$	42,736	$	66,688

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,
	2001		37,612	$	453,102	$		370,126	$		(921)	44	$		(1,496)	$	820,811

Net income			-		-			125,214			-	-			-		125,214
Common stock dividends
		($1.86 per share)	-		-			(69,782)			-	-			-		(69,782)
Issued			17		618			-			-	(292)			11,527		12,145
Acquired			-		-			-			-	314			(12,857)		(12,857)
Other			-		477			(1,209)			-	-			-		(732)
Unrealized loss on
	securities (net of tax)		-		-			-			(1,770)	-			-		(1,770)
Minimum pension
	liability adjustment
	(net of tax)		-		-			-			(1,028)	-			-		(1,028)

Balance at December 31,
	2001		37,629		454,197			424,349			(3,719)	66			(2,826)		872,001

Net income			-		-			61,672			-	-			-		61,672
Common stock dividends
		($1.86 per share)	-		-			(70,178)			-	-			-		(70,178)
Issued			523		15,770			-			-	(6)			338		16,108
Acquired			-		-			-			-	75			(1,252)		(1,252)
Other			-		394			(528)			-	-			-		(134)
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		470,361			415,315			(7,109)	135			(3,740)		874,827

Net income			-		-			46,578			-	-			-		46,578
Common stock dividends
		($1.70 per share)	-		-			(64,726)			-	-			-		(64,726)
Issued			189		4,123			-			-	(39)			509		4,632
Acquired			-		-			-			-	39			(929)		(929)
Other			-		(580)			-			-	-			-		(580)
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	$	473,904	$		397,167	$		(2,630)	135	$		(4,160)	$	864,281

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Comprehensive Income

				Year Ended December 31,
				2003		2002		2001
				(thousands of dollars)

NET INCOME				$	46,578	$	61,672	$	125,214

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains on securities:
		Unrealized holding gains (losses) arising during the period,
			net of tax of $2,963, ($1,840) and ($992)		4,982		(2,991)		(1,690)
		Reclassification adjustment for (gains) losses included
			in net income, net of tax of ($111), $1,007 and ($52)		(173)		1,560		(80)
			Net unrealized losses (gains)		4,809		(1,431)		(1,770)
	Minimum pension liability adjustment, net of tax of ($191),
		($1,265) and ($649)			(330)		(1,959)		(1,028)

TOTAL COMPREHENSIVE INCOME				$	51,057	$	58,282	$	122,416

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 formed in 1998 whose principal operating subsidiary is Idaho Power Company (IPC). IPC is regulated by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon and is engaged in the generation, transmission, distribution, sale and purchase of electric energy. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other operating subsidiaries include:

IdaTech - - developer of integrated fuel cell systems;

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

Velocitus - - commercial and residential Internet service provider;

IDACOMM - - provider of telecommunications services;

Ida-West Energy (Ida-West) - developer and manager of independent power projects; and

IDACORP Energy (IE) - marketer of electricity and natural gas.

IE is in the late stages of winding down its operations. In 2003, IDACORP decided that Ida-West would also wind down its operations.

Principles of Consolidation
The consolidated financial statements include the accounts of IDACORP and wholly-owned or controlled subsidiaries. All significant intercompany balances have been eliminated in consolidation. Investments in business entities in which IDACORP and its subsidiaries do not have control, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method.

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 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 3.03 percent in 2003, 3.00 percent in 2002 and 2.98 percent in 2001.

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.

Allowance for Funds Used During Construction
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 2003, 2002 and 2001 were 8.3 percent, 4.3 percent and 5.4 percent, respectively. IPC's reductions to interest expense for AFDC were $3 million, $2 million and $4 million, and other income included $3 million, $0.3 million and $1 million for 2003, 2002 and 2001, 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 electric customers. These adjustments, which take effect annually in May, are based on forecasts of net power supply expenses (fuel and purchased power less sales for resale) 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 a true-up, is then included in the calculation of the next year's PCA adjustment.

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).

The State of Idaho allows a three-percent investment tax credit (ITC) on qualifying plant additions. ITCs 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 including potentially dilutive shares related to stock-based compensation awards. The diluted EPS calculation includes immaterial amounts of potentially dilutive shares for the periods presented.

The diluted EPS computation excluded 721,800 common stock options in 2003, 849,000 in 2002 and 274,000 in 2001 because the options' exercise prices were greater than the average market price of the common stock during the years. These options expire from 2010 to 2013, and were still outstanding at the end of 2003.

Stock-Based Compensation
At December 31, 2003, two stock-based employee compensation plans existed, which are described more fully in Note 9. These plans are 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 restricted stock are reflected in net income based on the market value at the award date, or the year-end price for shares not yet vested. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

The following table illustrates the effect on net income and EPS if the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) 123, "Accounting for Stock-Based Compensation," had been applied to stock-based employee compensation:

			2003		2002		2001
			(thousands of dollars except for per share amounts)

Net income, as reported			$	46,578	$	61,672	$	125,214
Add: Stock-based employee compensation expense
	included in reported net income, net of related
	tax effects			(76)		(9)		442
Deduct: Total stock-based employee compensation
	expense determined under fair value based
	method for all awards, net of related tax effects			1,169		1,958		1,579
		Pro forma net income	$	45,333	$	59,705	$	124,077
Earnings per share:
	Basic and diluted - as reported		$	1.22	$	1.63	$	3.35
	Basic and diluted - pro forma			1.19		1.58		3.32

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.

Investments
Investments in marketable 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. 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.

Additionally, these investments are evaluated to determine whether they have experienced a decline in market value that is considered other than temporary. Other than temporary declines in market value are included in Other Income in the Consolidated Statements of Income.

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

	2003			2002
	Gross	Gross		Gross	Gross
	Unrealized	Unrealized	Fair	Unrealized	Unrealized	Fair
	Gain	Loss	Value	Gain	Loss	Value
Available for sale equity securities (IPC)	2,665	276	22,408	370	2,159	18,336
Held to maturity debt securities	-	-	17,221	-	-	8,299

IFS invests in affordable housing developments that are accounted for in accordance with Emerging Issues Task Force (EITF) Issue No. 94-1, "Accounting for Tax Benefits Resulting from Investments in Affordable Housing Projects," and are presented as Investments on the Consolidated Balance Sheets. IFS accounts for these investments using the equity method. All projects are reviewed periodically for impairment. At December 31, 2003 and 2002, the net affordable housing developments included in Investments were $116 million and $126 million, respectively.

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 ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as 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 liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).

Comprehensive Income
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 income balance at December 31:

		2003		2002
		(thousands of dollars)
Unrealized holding (gains) losses on securities		$	(3,676)	$	1,133
Minimum pension liability adjustment			6,306		5,976
	Total	$	2,630	$	7,109

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.

As required by SFAS 142, the annual impairment tests have been completed on IDACORP's $13 million goodwill balance, which is related to the acquisitions of IdaTech and Velocitus. Velocitus' test was performed as of June 30, 2003 and IdaTech's as of September 30, 2003. 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.

The following table presents IDACORP's net income and EPS, adjusted to exclude goodwill amortization expense, for the three years ended December 31:

	2003		2002		2001
	(thousands of dollars except for per share amounts)
Reported net income	$	46,578	$	61,672	$	125,214
Add back goodwill amortization		-		-		2,049
Adjusted net income	$	46,578	$	61,672	$	127,263

Basic and diluted earnings per share:
Reported earnings per share	$	1.22	$	1.63	$	3.35
Add back goodwill amortization		-		-		0.05
Adjusted earnings per share	$	1.22	$	1.63	$	3.40

Adopted Accounting Pronouncements
SFAS 143: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 ARO's. The adoption of SFAS 143 required IPC to redesignate these removal costs as regulatory liabilities. As of December 31, 2003, IPC had $143 million of such costs recorded as regulatory liabilities on the Consolidated Balance Sheet. Prior year amounts were reclassified to conform to current year presentation.

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.

If the requirements of SFAS 143 had been applied to prior reporting periods, IDACORP's and IPC's liability for AROs would have been $7 million at December 31, 2002 and $6 million at December 31, 2001.

SFAS 149: In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS 133, "Accounting for Derivative Instruments and Hedging Activities."

SFAS 149 amended SFAS 133 for decisions made:

As part of the Derivatives Implementation Group process that effectively required amendments to SFAS 133;

In connection with other FASB projects dealing with financial instruments; and

Regarding implementation issues raised in relation to the application of the definition of a derivative, particularly regarding the meaning of an "underlying" and the characteristics of a derivative that contains financing components.

SFAS 149 was effective for contracts entered into or modified after June 30, 2003, except as noted below, and for hedging relationships designated after June 30, 2003. The guidance was to be applied prospectively. The provisions of SFAS 149 that relate to SFAS 133 Implementation Issues that were effective for fiscal quarters that began prior to June 15, 2003 continue to be applied in accordance with their respective effective dates. The adoption of SFAS 149 did not have a material effect on IDACORP's or IPC's financial statements.

SFAS 150: In May 2003, the FASB issued SFAS 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS 150 requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 did not have a material effect on IDACORP's or IPC's financial statements.

FIN 45: In November 2002 the FASB issued Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this Interpretation were applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The disclosure requirements in this Interpretation were effective for financial statements of interim or annual periods ending after December 15, 2002. The adoption of this Interpretation did not have a material effect on IDACORP's and IPC's financial statements.

EITF Issue No. 02-3: IETF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," reached a consensus to rescind EITF 98-10, the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS 133. In addition, effective on January 1, 2003, all energy trading contracts previously accounted for at fair value under EITF 98-10 must be adjusted to historical cost unless those contracts meet the definition of a derivative under SFAS 133. The rescission of EITF 98-10 did not have a material effect on IDACORP or IPC's financial statements, as substantially all of their energy trading contracts meet the definition of a derivative under SFAS 133.

New Accounting Pronouncement
FIN 46: In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities." In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R provides guidance related to identifying variable interest entities (VIEs, previously known as special purpose entities or SPEs) and determining whether such entities should be consolidated. Certain disclosures are required if it is reasonably possible that a company will consolidate or disclose information about a VIE when it initially applies FIN 46R. FIN 46 was required to be applied immediately to VIEs created or obtained after January 31, 2003. During 2003, IDACORP and IPC did not participate in the creation of, or obtain a new variable interest in, any VIE. For those VIEs created or obtained on or before January 31, 2003, IDACORP and IPC must apply the provisions of FIN 46R in the first quarter of 2004.

IDACORP and IPC are in the final stages of their analysis of FIN 46R and the majority of their investments, principally IFS' affordable housing investments, are not expected to meet the criteria for consolidation included in FIN 46R. IDACORP and IPC do not expect the adoption of this standard to have a material effect on their financial statements.

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 2003 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:

		2003		2002		2001
		(thousands of dollars)
Federal income tax expense at 35% statutory rate		$	8,911	$	3,684	$	66,451
Change in taxes resulting from:
	AFDC		(2,343)		(948)		(1,571)
	Investment tax credits		(3,397)		(3,179)		(3,169)
	Repair allowance		(2,450)		(2,450)		(2,800)
	Capitalized overhead costs		(3,658)		(3,500)		-
	Tax accounting method change		-		(31,162)		-
	Settlement of prior years tax returns		(8,911)		(2,971)		(1,530)
	State income taxes, net of federal benefit		1,357		514		8,506
	Depreciation		10,237		8,940		9,790
	Affordable housing and historic tax credits		(20,345)		(20,863)		(13,080)
	Preferred dividends of IPC		1,200		1,606		1,890
	Other, net		(1,720)		(818)		159
Total income tax (benefit) expense		$	(21,119)	$	(51,147)	$	64,646
	Effective tax rate		(83.0%)		(486.0%)		34.2%

The items comprising income tax expense are as follows:

			2003		2002		2001
			(thousands of dollars)
Income taxes currently payable (receivable):
	Federal		$	30,666	$	50,522	$	(69,557)
	State			10,200		8,997		(18,735)
		Total		40,866		59,519		(88,292)
Income taxes deferred:
	Federal			(49,248)		(99,166)		124,949
	State			(12,966)		(11,044)		26,023
		Total		(62,214)		(110,210)		150,972
Investment tax credits:
	Deferred			3,627		2,722		5,135
	Restored			(3,398)		(3,178)		(3,169)
		Total		229		(456)		1,966
Total income tax (benefit) expense			$	(21,119)	$	(51,147)	$	64,646

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

			2003		2002
			(thousands of dollars)
Deferred tax assets:
	Regulatory liabilities		$	41,024	$	41,013
	Advances for construction			4,162		3,759
	Other			21,638		21,524
		Total		66,824		66,296
Deferred tax liabilities:
	Property, plant and equipment			238,602		230,935
	Other regulatory assets			330,833		327,933
	Conservation programs			8,310		10,426
	PCA			27,529		53,324
	Net energy trading assets			-		45,711
	Other			21,904		14,990
		Total		627,178		683,319
Net deferred tax liabilities			$	560,354	$	617,023

Status of Audit Proceedings
Federal income tax returns for years through 2000 have been examined by the Internal Revenue Service and substantially all issues have been settled. Settlements resulted in deficiencies that were less than previously accrued, enabling IDACORP to decrease income tax expense by $9 million (principally in the fourth quarter) in 2003 and $3 million in 2002. Management believes that adequate provision for income taxes has been made for the open years 2001 and after, and any unsettled issues prior to 2001.

Tax Credits
As of December 31, 2003, IDACORP had $4 million of general business credit carryforward for federal income tax purposes. Additionally, IDACORP had $6 million of Idaho ITC carryforward. The general business credit carryforward period expires in 2023 and the Idaho ITC expires from 2015 to 2017. 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 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.

3. COMMON STOCK:

At December 31, 2003 and 2002, common stock was reserved for the following purposes:

		2003	2002
Contingently issuable in connection with business combinations		23,989	50,732
Dividend reinvestment and stock purchase plan and employee
	savings plan	6,062,314	3,751,236
Restricted stock plan		314,114	314,114
Long-term incentive and compensation plan		2,050,000	2,050,000
	Total	8,450,417	6,166,082

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. IDACORP has issued 242,371 shares to the shareholders of the acquired entity. Of the remaining acquired shares, 71,755 have been issued, primarily in connection with its Dividend Reinvestment Program (DRIP).

IDACORP has issued shares of common stock for its DRIP and Employee Savings Plan (ESP) (see Note 10). In 2003, IDACORP issued 122,990 shares for the DRIP and 65,932 shares for the ESP. In 2002, IDACORP issued 321,236 shares for the DRIP and 202,281 shares for the ESP. In 2001, IDACORP issued 16,568 shares for the ESP.

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 10^th 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 any voting or other rights as shareholders to their holders. The terms of the Rights may be amended without the approval of any holders of the Rights until an Acquiring Person obtains a 20 percent or greater position, and then may be amended as long as the amendment is not adverse to the interests of the holders of the Rights.

4. PREFERRED STOCK OF IDAHO POWER COMPANY:

The number of shares of IPC preferred stock outstanding at December 31, 2003 and 2002 were as follows:

			Shares Outstanding at
			December 31,		Call Price
			2003	2002	Per Share
Preferred stock:
Cumulative, $100 par value:
	4% preferred stock (authorized 215,000 shares)		123,664	133,927	$104.00
	Serial preferred stock, 7.68% Series (authorized
		150,000 shares)	150,000	150,000	$102.97
Serial preferred stock, cumulative, without par
	value, total of 3,000,000 shares authorized:
	7.07% Series, $100 stated value (authorized
		250,000 shares)	250,000	250,000	$100.354 - $103.535
		Total	523,664	533,927

During 2003, 2002 and 2001, IPC reacquired and retired 10,263, 9,945 and 6,784 shares of 4% preferred stock, respectively. As of December 31, 2003, the overall effective cost of all outstanding preferred stock was 6.54 percent.

The voting rights of IPC's common stock and preferred stock are as follows:

Each share of common stock, $2.50 par value, is entitled to one vote;

Each share of 4% Preferred Stock, $100 par value, is entitled to 20 votes;

Each share of 7.68% Series, Serial Preferred Stock, $100 par value, is entitled to one vote; and

Holders of shares of 7.07% Series, Serial Preferred Stock, without par value, are not entitled to vote.

5. LONG-TERM DEBT:

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

			2003		2002
			(thousands of dollars)
First mortgage bonds:
	6.40% Series due 2003		$	-	$	80,000
	8 % Series due 2004			50,000		50,000
	5.83% Series due 2005			60,000		60,000
	7.38% Series due 2007			80,000		80,000
	7.20% Series due 2009			80,000		80,000
	6.60% Series due 2011			120,000		120,000
	4.75% Series due 2012			100,000		100,000
	4.25% Series due 2013			70,000		-
	7.50% Series due 2023			-		80,000
	6 % Series due 2032			100,000		100,000
	5.50 % Series due 2033			70,000		-
		Total first mortgage bonds		730,000		750,000
Pollution control revenue bonds :
	8.30% Series 1984 due 2014 (a)			-		49,800
	Variable Auction Rate Series 2003 due 2024 (a)			49,800		-
	6.05% Series 1996A due 2026			68,100		68,100
	Variable Rate Series 1996B due 2026			24,200		24,200
	Variable Rate Series 1996C due 2026			24,000		24,000
	Variable Rate Series 2000 due 2027			4,360		4,360
		Total pollution control revenue bonds		170,460		170,460
REA notes				1,105		1,185
American Falls bond guarantee				19,885		19,885
Milner Dam note guarantee				11,700		11,700
Unamortized premium/discount - net				(2,205)		(2,405)
Debt related to investments in affordable housing				82,715		37,428
Other subsidiary debt				97		15
	Total			1,013,757		988,268
Current maturities of long-term debt				(67,923)		(89,592)
		Total long-term debt	$	945,834	$	898,676
(a) Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds.

At December 31, 2003, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):

	2004		2005		2006		2007		2008		Thereafter

IPC	$	50,077	$	60,079	$	82	$	81,228	$	1,116	$	738,363
Other subsidiary debt		17,846		17,229		15,576		13,723		10,213		8,225
Total	$	67,923	$	77,308	$	15,658	$	94,951	$	11,329	$	746,588

IDACORP currently has two shelf registration statements totaling $800 million that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock. At December 31, 2003, none had been issued.

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, 2003 the auction rate was 1.15 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%.

On November 15, 2002, IPC issued $200 million of secured medium-term notes in two series: $100 million First Mortgage Bonds 4.75% Series due 2012 and $100 million First Mortgage Bonds 6.00% Series due 2032. Proceeds were used to pay down IPC short-term borrowings.

In August 2001, $25 million First Mortgage Bonds 9.52% Series due 2031 were redeemed early using short-term borrowings. Also, in March 2002, $50 million First Mortgage Bonds 8.75% Series due 2027 were redeemed early using short-term borrowings.

At December 31, 2003 and 2002, the overall effective cost of all outstanding first mortgage bonds and pollution control revenue bonds was 5.71 percent and 6.51 percent, respectively.

At December 31, 2003, IFS had $83 million of debt with interest rates ranging from 3.65 percent to 8.59 percent due 2004 to 2010. This debt is collateralized by investments in affordable housing developments with a net book value of $116 million at December 31, 2003.

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 and other property are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.

	December 31, 2003				December 31, 2002
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
Assets:
Notes receivable	$	11,576	$	11,590	$	13,654	$	11,863
Investment and other property		39,376		39,630		28,302		28,700

Liabilities:
Long-term debt	$	1,015,962	$	1,043,116	$	989,673	$	1,054,193

7. NOTES PAYABLE:

At December 31, 2003, IDACORP had a $175 million credit facility that expires March 17, 2004, and a $140 million credit facility that expires March 25, 2005. Under these facilities IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its corporate credit rating. Commercial paper may be issued up to the amounts supported by the bank credit facilities.

IPC has a $200 million credit facility that expires March 17, 2004. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on IPC's corporate credit rating. IPC's commercial paper may be issued up to the amounts supported by the bank credit facilities. At December 31, 2003, IPC had regulatory authority to incur up to $250 million of short-term indebtedness.

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

	IDACORP				IPC
	2003		2002		2003		2002
Balance	$	93,650	$	176,200	$	-	$	10,500
Effective interest rate		1.21%		1.83%		-		1.65%

8. COMMITMENTS AND CONTINGENT LIABILITIES:

As of December 31, 2003, IPC had signed agreements to purchase energy from 69 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 654,131 MWh at a cost of $38 million in 2003 and 692,414 Megawatt-hour (MWh) at a cost of $44 million in 2002.

IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Company, a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at December 31, 2003. 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 (SET). As part of the sale of the forward book of electricity contracts IE entered into an Indemnity Agreement with SET, 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 the 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
Vierstra Dairy v. Idaho Power Company: On August 11, 2000, Mike and Susan Vierstra, dairy operators from Twin Falls, Idaho, brought suit against IPC in Idaho State District Court, Fifth Judicial District, Twin Falls County. The plaintiffs sought monetary damages in the amount of approximately $8 million for negligence and nuisance (allegedly allowing electrical current to flow in the earth and adversely affect the health of plaintiffs' dairy cows) and punitive damages in the amount of approximately $40 million.

United Systems, Inc., f/k/a Commercial Building Services, Inc.: On March 18, 2002, United Systems, Inc. (United Systems) filed a complaint in Idaho State District Court in and for the County of Ada against IDACORP Services Co., an inactive subsidiary of IDACORP, dba IDACORP Solutions. United Systems is a heating, ventilation, refrigeration and plumbing contracting company that entered into a contract with IDACORP Services in December 2000.

Under the terms of the contract, IDACORP Services authorized United Systems to do business as "IDACORP Solutions." The contract was to be effective from January 2001 through December 2005.

In November 2001, IDACORP Services Co. notified United Systems that IDACORP Services Co. was terminating the contract for convenience. The contract allowed for such termination but required the terminating party to compensate the other party for all costs incurred in preparation for, and in performance of the contract, and for reasonable net profit for the remaining term of the contract. United Systems claimed $7 million in net profits lost and costs incurred.

IDACORP Services Co. asserted that termination related compensation owed to United Systems, if any, was substantially less than the amount claimed by United Systems.

On August 8, 2002, United Systems filed an amended complaint adding IDACORP, IE and IPC as additional defendants claiming they should be held jointly and severally liable for any judgment entered against IDACORP Services Co. On October 4, 2002, United Systems filed a Motion for Partial Summary Judgment as to its damages. On July 9, 2003, the Court denied Plaintiff's Motion for Partial Summary Judgment and granted Defendants' Motion to Bifurcate. On October 29, 2003, IDACORP agreed to pay $712,500 to settle this dispute with United Systems in return for dismissal of the proceeding with prejudice. The settlement was finalized on November 26, 2003. An Order of Dismissal with Prejudice as to All Defendants was entered on December 2, 2003.

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.

IDACORP, IPC and IE had this action removed from the state court to the United States 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 Federal 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 (FPA) 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 United States Court of Appeals for the Ninth Circuit. Briefing on the appeal was completed in August 2003, but the court has yet to set a date for oral argument. The companies intend to vigorously defend their position on appeal 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 United States 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 law and the Racketeering Influenced and Corrupt Organization 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 (the same judge who heard the Public Utility District No. 1 of Snohomish County, Washington case).

All defendants, including IPC and IDACORP, have moved to dismiss the complaint in lieu of answering it. The motions are all 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. Briefing on these motions was completed in early February 2004. A hearing on the motion to dismiss is scheduled for March 26, 2004. 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 (AG) 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 AG against various sellers of power in the California market, seeking civil penalties pursuant to California's unfair competition law - - California Business and Professions Code Section 17200. Section 17200 defines unfair competition as any "unlawful, unfair or fraudulent business act or practice. . ." The AG alleges that IPC engaged in unlawful conduct by violating the FPA in two respects: (1) by failing to file its rates with the FERC as required by the FPA; and (2) charging unjust and unreasonable rates in violation of the FPA. The AG 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 AG 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 AG filed a motion to remand back to state court. On March 25, 2003, the court denied the AG'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 AG filed a Notice of Appeal, appealing the court's final judgment dismissing the action to the United States Court of Appeals for the Ninth Circuit. The briefing on the appeal was completed on October 31, 2003. The Court has yet to set a date for oral argument. IPC intends to vigorously defend its position on appeal and believes this matter will not have a material adverse effect on its consolidated financial positions, results of operations or cash flows.

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, including California Lieutenant Governor Cruz Bustamante and California legislator Barbara Matthews in their personal capacities. 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., 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 California Antitrust Law (the Cartwright Act), Business & Professions Code Section 16720, et seq., and California's Unfair Competition Law, Business & Professions Code Section 17200, et seq. Among the acts complained of are bid rigging, information exchanges, withholding of power, and various other wrongful acts. These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint (PMC) in San Diego Superior Court on March 8, 2002.

On April 22, 2002, more than a year after the initial complaints had been 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 PMC. 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 PMC. Reliant has also asserted a claim against IPC for alleged violations of the California Unfair Competition Law, Business and Professions Code Section 17200, et seq. 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 PMC 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 Federal 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 Ninth Circuit has 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. The court has yet to set a date for oral argument, and a decision by the Ninth Circuit is expected in mid-2004. As a result of the various motions, no trial date is set. 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.

Class Action Complaints Relating to Trades on the New York Mercantile Exchange: On August 18, 2003, Cornerstone Propane Partners, L.P. (Cornerstone), on behalf of itself and others who allegedly purchased and sold natural gas futures and options contracts on the New York Mercantile Exchange from January 1, 2000 to December 31, 2002, filed a class action complaint in the United States District Court for the Southern District of New York against more than 30 defendants, including IDACORP and IPC. On November 14, 2003, an individual, Dominick Viola (Viola), filed a substantively similar complaint in the United States District Court for the Southern District of New York, on behalf of himself and others allegedly similarly situated, against more than 30 defendants, including IDACORP and IPC. The Cornerstone and Viola actions have been consolidated. The complaints claim that the defendants reported inaccurate trading information to various trade publications that compile and publish indices of natural gas prices and that the defendants engaged in various improper trades on the Enron Online internet-based trading platform, the alleged purpose of which was to improperly inflate the prices of natural gas. The plaintiffs seek class action certification and damages for alleged violations of the Commodity Exchange Act and for aiding and abetting such violations.

IDACORP and IPC provided the plaintiffs with information that refutes all of the allegations contained in the complaints. The plaintiffs agreed to dismiss the actions against IDACORP and IPC, without prejudice to resume the actions if additional information is learned in the course of the actions still pending against other defendants. IDACORP and IPC are no longer named as defendants in the actions.

California 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 exchange defaulted on a payment to the exchange, the other participants were required to pay their allocated share of the default amount to the exchange. 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 (SCE) payment default of $215 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated the participation agreement. On February 8, 2001, the CalPX sent a further invoice for $5 million, due February 20, 2001, as a result of alleged payment defaults by SCE, Pacific Gas and Electric Company (PG&E) and others. However, because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8th invoice. IPC essentially discontinued energy trading with 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 charge back methodology and provides for further oversight in the CalPX's implementation of its default mitigation procedures.

A preliminary injunction was granted by a federal judge in the Federal District Court for the Central District of California enjoining the CalPX from declaring any CalPX participant in default under the terms of the CalPX Tariff. On March 9, 2001, the CalPX filed for Chapter 11 protection with the United States Bankruptcy Court, Central District of California.

In April 2001, PG&E filed for bankruptcy. The CalPX and the Cal ISO were among the creditors of PG&E. To the extent that PG&E's bankruptcy filing affects the collectibility of the receivables from the CalPX and 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 PG&E's and SCE's liabilities. Shortly after that time, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claims it is awaiting further orders of 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 (ALJ) 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.

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 its June 19, 2001 order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the FPA. 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 ALJ 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. As to potential refunds, if any, IE believes its exposure is likely to be offset by amounts due from California entities. Multiple parties have filed requests for rehearing and petitions for review. The latter, more than 60, have been consolidated by the United States Court of Appeals for the Ninth Circuit and held in abeyance while the FERC continues its deliberations. The Ninth Circuit also directed the FERC to permit the parties to adduce additional evidence respecting market manipulation. See "Market Manipulation" below.

On March 20, 2002, the AG 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 rates violate the FPA, and, even if market-based rate requirements are valid, that the quarterly transaction reports filed by sellers do not contain the transaction-specific information mandated by the FPA 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 AG appealed the FERC's decision to the United States Court of Appeals for the Ninth Circuit. The AG 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 heard oral arguments on October 9, 2003, but has not specified the date on which it will issue a decision. The companies cannot predict the outcome of this matter.

This case had been further complicated by an August 13, 2002 FERC Staff (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 (MMCP) to calculate refunds with other published indices for producing basin prices plus a transportation allowance. The 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. 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 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 ALJ 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 ALJ. However, the FERC changed a component of the formula the ALJ 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 ALJ, 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.

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 MMCPs 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 Commission granted additional time. In a February 10, 2004 report to the Commission, the Cal ISO asserted its belief that it will 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 Commission disposition of a number of pending issues. The Cal ISO is required to update the Commission on its progress monthly. After that time, the FERC will consider cost-based filings from sellers to reduce their refund exposure. On December 2, 2003 IDACORP petitioned for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. They have not yet been consolidated with one another or with the petitions for review of earlier FERC California refund orders already pending. Certain parties also sought further rehearing before the FERC. These latter applications remain pending before the FERC. The Ninth Circuit has 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.

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, 2003, 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, 2003, 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 positions, results of operations or cash flows.

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 California Public Utilities Commission) 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 - the overwhelming majority of the claims of the California Parties related to claims respecting 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 (October 2, 2000) with a MMCP, 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 previously, the FERC declined to generically apply its refund determinations across the board 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 Staff on the two orders commonly referred to as the "gaming" and "partnership" show cause orders. Regarding the gaming order, the 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 Staff submitted a motion to the FERC to dismiss the proceeding because materials submitted by IPC demonstrated that IPC did not use the "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 and is subject to rehearing requests for 30 days. The motion to dismiss the "partnership" proceeding was approved by the FERC in an order issued January 23, 2004 and rehearing of that order was not sought within the time allowed by statute.

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 will review evidence of alleged economic withholding of generation. The FERC has 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 will be considered prima facie evidence of economic withholding. The FERC has issued data requests in this investigation to over 60 market participants including IPC. If it is determined that IPC engaged in improper bidding, the FERC has indicated that sanctions may include disgorgement of alleged profits and other non-monetary actions, including possible revocation of market-based rate authority and/or additional required provisions in codes of conduct. IPC received some information regarding these matters from the Cal ISO and on July 24, 2003, IPC responded to the FERC's data requests. Based on the information received to date from the Cal ISO, IDACORP and IPC believe that any potential penalties imposed by the FERC would not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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 ALJ submitted recommendations and findings to the FERC on September 24, 2001. The ALJ 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 ALJ's decision is a recommendation to the commissioners of the FERC. Multiple parties have submitted comments to the FERC respecting the ALJ's recommendations. The ALJ'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, has 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 the company. The company submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and Seattle City Light 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 having received incorrectly 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 required that no refunds be paid. The Commission denied rehearing on November 10, 2003. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General and Puget Sound Energy Inc. filed petitions for review in the Ninth Circuit within the time permitted. These petitions have not yet 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. In addition, the California Parties sought further rehearing of aspects of the FERC's orders. The FERC's order remains subject to rehearing by the FERC and review by appellate courts. The companies are unable to predict the outcome of these matters.

Nevada Power Company: In February and April of 2001, IPC entered into two transactions under the Western Systems Power Pool (WSPP) Agreement whereby IPC agreed to deliver to Nevada Power Company (NPC) 25 MW during the third quarter of 2002. NPC agreed to pay IPC $250 per MWh for heavy load deliveries and $155 per MWh for light load deliveries. IPC assigned the contracts to IE with NPC's consent and the assignment was subsequently approved by the FERC. Based upon the uncertain financial condition of NPC, and pursuant to the terms of the WSPP Agreement, IE requested NPC to provide assurances of its ability to pay for the power if IE made the deliveries. NPC failed to provide appropriate credit assurances; therefore, in accordance with the WSPP Agreement procedures, IE terminated all WSPP Agreement transactions with NPC effective July 8, 2002. Pursuant to the WSPP Agreement, IE notified NPC of the liquidated damages amount and NPC responded with a letter, which described their view of rights under the WSPP Agreement and suggested a negotiated resolution. IE and NPC unsuccessfully attempted to mediate a resolution to this dispute.

IE filed a complaint against NPC on April 25, 2003, in Idaho State District Court in and for the County of Ada. This complaint was served on NPC on May 14, 2003. IE asked the Idaho State District Court for damages in excess of $9 million pursuant to the contracts. On June 17, 2003, NPC filed a motion to dismiss IE's complaint alleging, among other things, that: the Idaho State District Court lacks jurisdiction over NPC; a separate complaint seeking declaratory judgment was filed in the United States District Court, District of Nevada on May 14, 2003 by NPC against IPC, IE and IDACORP involving the same subject matter as the complaint filed by IE against NPC; IE does not have standing to maintain certain claims against NPC; Idaho is not a convenient forum to adjudicate the matter; and IE filed the action in Idaho State District Court in violation of the WSPP Agreement. NPC's motion to dismiss was heard on December 2, 2003. The parties await the Court's ruling. NPC has never served IE with the complaint for declaratory judgment filed in the United States District Court in Nevada.

On September 23, 2003, NPC filed and served IE, IPC, and IDACORP with a Declaratory Action filed with the Nevada State Court in and for the County of Clark concerning the same subject matter of the pending Idaho State District Court action filed by IE on April 25, 2003. NPC seeks declaratory judgment on the following issues: that the assignment of the February and April 2001 energy supply contracts from IPC to IE is void or voidable; that IE did not comply with the WSPP Agreement when requesting reasonable assurances; and that NPC is relieved of its obligations to pay under the contracts by reason of force majeure. IE filed a motion to dismiss NPC's Nevada State Court claims. That motion was heard, and denied, on November 17, 2003.

IE intends to vigorously prosecute the action it filed in Idaho State District Court. Furthermore, IPC, IE and IDACORP intend to vigorously defend against NPC's claims filed in the State of Nevada.

At December 31, 2003, IE had a $4 million receivable related to the NPC contracts.

Overton Power District No. 5: IE filed a lawsuit on November 30, 2001 in Idaho State District Court in and for the County of Ada against Overton Power District No. 5 (Overton), a Nevada electric improvement district, based on Overton's breach of its power contracts with IE. The contract provided for Overton to purchase 40-MW of electrical energy per hour from IE at $88.50 per MWh from July 1, 2001 through June 30, 2011.

IE asked the Idaho District Court for damages pursuant to the contract, for a declaration that Overton is not entitled to renegotiate or terminate the contract and for injunctive relief requiring Overton to raise rates as stipulated in the contract.

On April 10, 2003, IE and Overton reached an agreement to settle the case. On April 30, 2003, IE and Overton entered into a Settlement Agreement which provided that Overton would pay IE $52.5 million as follows: (a) $5.5 million on May 1, 2003 and (b) $47 million over ten years, in equal installments to be paid quarterly beginning October 1, 2003. There was no prepayment penalty. The Settlement Agreement terminated the July contract. IE received the $5.5 million on May 1, 2003 and the first quarterly installment payment of $1.6 million on October 1, 2003. IE agreed to accept a final payment of $45 million on December 29, 2003. The settlement resulted in a loss on legal disputes of $23 million which includes a $1 million loss associated with the final payment. The settlement of this dispute and the subsequent payments relieved the $74 million long-term receivable on IE's books at December 31, 2002.

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 five of the right-of-way permits for the transmission lines, which have stated permit expiration dates between 1996 and 2003. IPC has filed applications with the United States Department of the Interior, Bureau of Indian Affairs, to renew the five 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). The Tribes have not agreed to renew the rights-of-way and have demanded a substantially greater payment of $19 million, including an up-front payment of $4 million with the remainder to be paid over the 25-year term of the permits, or in the alternative $11 million including an up-front payment of $4 million with the remainder paid over the first three years of the permits. This is based on an "opportunity cost" methodology, which calculates the value of the rights-of-way as a percentage of the cost to IPC of relocating the transmission lines off the Reservation. Both parties have discussed potential legal action regarding renewal of the rights-of-way, but no such action has been taken to date. The probable cost of renewing the rights-of-way is difficult to ascertain due to the lack of definitive legal guidelines for the renewals. IPC believes that the amount payable for 25-year rights-of-way should not exceed $11 million, which represents the approximate present value of the offers communicated to date by the Tribe. IPC plans to obtain IPUC approval for the recovery of any renewal payment in its utility rates as a prerequisite to any settlement of the right-of-way renewals with the Tribe.

9. STOCK-BASED COMPENSATION:

IDACORP has two stock-based compensation plans that are intended to align employee and shareholder objectives related to its long-term growth.

The 2000 Long-Term Incentive Compensation Plan (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 2003, 2002 and 2001, IDACORP issued 429,000, 355,000 and 274,000 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:

		2003			2002			2001
			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		849,000	$	38.50	494,000	$	37.79	220,000	$	35.81
	Granted	429,000		23.01	355,000		39.50	274,000		39.37
	Exercised	-		-	-		-	-		-
	Forfeited	(127,200)		38.55	-		-	-		-
Outstanding, end of year		1,150,800	$	32.72	849,000	$	38.50	494,000	$	37.79

Exercisable		266,600	$	37.91	120,800	$	37.20	36,000	$	35.81

The outstanding options have a range of exercise prices from $22.92 to $40.31. As of December 31, 2003, the weighted average remaining contractual life is 8.1 years.

IDACORP also has a restricted stock plan for key employees. Each grant made under this plan has a three-year restricted period, and the final award amounts depend on the attainment of cumulative EPS performance goals. At December 31, 2003, there were 145,314 remaining shares available under this plan.

Restricted stock awards are compensatory awards and IDACORP accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 2003, 2002 and 2001, total compensation accrued under the plan was less than $1 million annually.

The following table summarizes restricted stock activity for the years 2003, 2002 and 2001:

		2003		2002		2001
Shares outstanding - beginning of year		87,669		63,551		60,195
Shares granted		52,517		44,832		23,748
Shares forfeited		(6,679)		(132)		(474)
Shares issued		(39,144)		(20,582)		(19,918)
Shares outstanding - end of year		94,363		87,669		63,551
Weighted average fair value of current year stock grants
	on grant date	$	23.01	$	38.58	$	38.16

For purposes of the pro forma calculations in Note 1, the estimated fair value of the options and restricted stock are amortized to expense over the vesting period. The fair value of the restricted stock is the market price of the stock on the date of grant. Expense related to forfeited options is reversed in the period in which the forfeit occurs.

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

	2003	2002	2001
Stock dividend yield	8.09%	4.71%	4.72%
Expected stock price volatility	28%	32%	29%
Risk-free interest rate	3.94%	4.92%	5.18%
Expected option lives	7 years	7 years	7 years
Weighted average fair value of options granted	$ 3.90	$10.54	$ 9.86

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 but not more than the maximum amount deductible for income tax purposes. IPC was not required to contribute to the plan in 2003, 2002 and 2001, and does not expect to make a contribution in 2004. 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 shows the components of net periodic benefit cost for these plans:

	Pension Plan							Deferred Compensation Plan
	2003		2002		2001		2003			2002		2001
	(in thousands of dollars)

Service cost	$	10,173	$	9,548	$	7,978	$		1,212	$	944	$	624
Interest cost		19,463		18,684		17,634			2,414		2,108		2,039
Expected return on assets		(23,445)		(28,797)		(30,117)			-		-		-
Recognized net actuarial (gain) loss		361		-		(3,179)			744		498		281
Amortization of prior service cost		729		729		708			(345)		(353)		(345)
Amortization of transition asset		(263)		(263)		(263)			613		613		613
Net periodic pension cost (benefit)	$	7,018	$	(99)	$	(7,239)	$		4,638	$	3,810	$	3,212

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

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

Change in benefit obligation:
	Benefit obligation at January 1	$	294,881	$	273,208	$	35,792	$	30,405
	Service cost		10,173		9,548		1,212		944
	Interest cost		19,463		18,684		2,415		2,108
	Actuarial loss (gain)		27,420		6,823		1,785		4,490
	Benefits paid		(13,345)		(13,382)		(2,369)		(2,507)
	Plan amendments		529		-		35		352
	Benefit obligation at December 31	$	339,121	$	294,881	$	38,870	$	35,792
Change in plan assets:
	Fair value at January 1		282,531		326,266		-		-
	Actual return on plan assets		66,043		(30,353)		-		-
	Employer contributions		-		-		-		-
	Benefit payments		(13,345)		(13,382)		-		-
	Fair value at December 31	$	335,229	$	282,531	$	-	$	-

Funded status			(3,892)		(12,350)		(38,870)		(35,792)
Unrecognized actuarial loss (gain)			18,577		34,116		13,547		12,505
Unrecognized prior service cost			6,660		6,860		1,010		630
Unrecognized net transition liability			(389)		(652)		923		1,536
Net amount recognized		$	20,956	$	27,974	$	(23,390)	$	(21,121)
Amounts recognized in the statement of
	financial position consist of:
Prepaid (accrued) pension cost		$	20,956	$	27,974	$	(35,676)	$	(33,120)
Intangible asset			-		-		1,933		2,166
Accumulated other comprehensive income			-		-		10,353		9,833
Net amount recognized		$	20,956	$	27,974	$	(23,390)	$	(21,121)
Accumulated benefit obligation		$	284,910	$	248,074	$	35,676	$	33,120

Changes in the Deferred Compensation Plan minimum liability increased other comprehensive income by $0.5 million and $3.2 million in 2003 and 2002, respectively.

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

		2004		2005		2006		2007		2008		2009-2013
Pension Plan	$	13,675	$	13,941	$	14,347	$	15,075	$	16,085	$	102,911
Deferred Compensation Plan		2,353		2,546		2,571		2,600		2,691		15,637

Plan Asset Allocations: IPC's pension plan and postretirement benefit plan weighted average asset allocations at December 31, 2003 and 2002, by asset category are as follows:

		Pension		Postretirement
		Plan		Benefits
Asset Category		2003	2002	2003	2002
Equity securities		69%	63%	0%	0%
Debt securities		21	25	2	2
Real estate		9	11	0	0
Other (a)		1	1	98	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	14.0%	International Growth Stocks	6.0%
Large-Cap Core Stocks	10.0%	International Value Stocks	6.0%
Large-Cap Value Stocks	14.0%	Intermediate-Term Bonds	20.0%
Small-Cap Growth Stocks	7.5%	Core Real Estate	10.0%
Small-Cap Value Stocks	7.5%	Venture Capital	1.0%
Cash and Cash Equivalents	4.0%

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% S&P 500 stocks and a 40% 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 2% 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.

Investment managers for the plan are selected based on their expertise in a given asset class. Investment managers engaged by the portfolio are subjected to rigorous ongoing due diligence to ensure that investment performance guidelines are adhered to and that the investment professionals and investment processes remain intact.

Postretirement Benefits
IPC maintains a defined benefit postretirement plan (consisting of health care and death benefits) that covers all employees who were enrolled in the active group plan at the time of retirement, their spouses and qualifying dependents. 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.

IPC's postretirement plan includes a health care plan that provides prescription drug benefits. IPC is utilizing the one-time election prescribed in FASB Staff Position 106-1 to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). Therefore, the measures of the net periodic postretirement benefit cost and accumulated benefit obligation do not reflect the effects of the Act on the plan. Authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require IPC to change previously reported information. In addition, IPC may need to amend the postretirement plan in order to benefit from the new legislation.

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

		2003		2002		2001
Service cost		$	1,207	$	927	$	831
Interest cost			4,017		3,648		3,589
Expected return on plan assets			(1,930)		(2,320)		(2,343)
Amortization of unrecognized transition
	obligation		2,040		2,040		2,040
Amortization of prior service cost			(563)		(563)		(563)
Recognized actuarial (gain)/loss			1,402		487		-
Net periodic postretirement benefit		$	6,173	$	4,219	$	3,554

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

		2003		2002
Change in accumulated benefit obligation:
	Benefit obligation at January 1	$	57,267	$	53,650
	Service cost		1,207		927
	Interest cost		4,017		3,648
	Actuarial loss		8,780		2,029
	Benefits paid		(4,181)		(2,987)
	Benefit obligation at December 31	$	67,090	$	57,267

Change in plan assets:
	Fair value of plan assets at January 1		22,522		25,184
	Actual (loss) return on plan assets		4,081		(3,837)
	Employer contributions		3,961		4,262
	Benefits paid		(3,961)		(3,087)
	Fair value of plan assets at December 31	$	26,603	$	22,522

Funded status			(40,487)		(34,745)
Unrecognized prior service cost			(5,047)		(5,610)
Unrecognized actuarial loss (gain)			23,854		18,627
Unrecognized transition obligation			18,360		20,400
Accrued benefit obligations included with other deferred credits		$	(3,320)	$	(1,328)

The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan is 6.75% in 2003 and 2002. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of dollars):

	1-Percentage		1-Percentage
	-Point		-Point
	increase		decrease

Effect on total of cost components	$	187	$	(146)
Effect on accumulated postretirement benefit obligation	$	1,883	$	(1,533)

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
	2003	2002	2003	2002
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)	-	-	12	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
	2003	2002	2003	2002
Discount rate	6.75%	7.0%	6.75%	7.0%
Expected long-term rate of return on assets	8.5	9.0	8.5	9.0
Rate of compensation increase	4.5	4.5	-	-
Medical trend rate	-	-	6.75	6.75
Expected working lifetime (years)	-	-	12	12

Employee Savings Plan
IPC has an ESP which complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. IPC matches specified percentages of employee contributions to the plan. Matching contributions amounted to $3 million in 2003 and $4 million in each of 2002 and 2001.

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 is being amortized over the ten years ending February 2005

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

	2003		2002
Included with regulatory assets	$	403	$	774
Included with other deferred credits	$	(4,079)	$	(3,686)

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 2003 and 2002 (in thousands of dollars):

		2003			2002
		Balance		Avg Rate	Balance		Avg Rate

Production		$	1,456,954	2.71%	$	1,433,627	2.63%
Transmission			526,887	2.21		485,349	2.30
Distribution			952,979	3.25		902,985	3.31
General and Other			283,408	6.51		265,004	6.16
	Total in service		3,220,228	3.03%		3,086,965	3.00%
Accumulated provision for depreciation			(1,239,604)			(1,157,287)
	In service - net	$	1,980,624		$	1,929,678

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, are as follows at December 31, 2003:

		Utility		Construction		Accumulated
		Plant In		Work in		Provision for
Name of Plant	Location	Service		Progress		Depreciation		%	MW
		(thousands of dollars)
Jim Bridger Units 1-4	Rock Springs, WY	$	424,482	$	4,906	$	243,622	33	707
Boardman	Boardman, OR		64,966		355		42,450	10	55
Valmy Units 1 and 2	Winnemucca, NV		308,211		2,373		174,194	50	261

IPC's wholly owned subsidiary, Idaho Energy Resources Company, is a joint venturer in Bridger Coal Company, which operates the mine supplying coal for the Jim Bridger steam generation plant. Coal purchased by IPC from the joint venture amounted to $44 million in 2003, $44 million in 2002 and $43 million in 2001.

IPC has contracts to purchase the energy from four Public Utilities Regulatory Policy Act (PURPA) Qualified Facilities that are 50 percent owned by Ida-West. Power purchased from these facilities amounted to $7 million both in 2003 and 2002 and $6 million in 2001.

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. INDUSTRY SEGMENT INFORMATION:

IDACORP has identified three reportable operating segments: utility operations, energy marketing 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.

The energy marketing segment reflects the results of IE's electricity and natural gas marketing operations. See Note 13 - Regulatory Matters, for discussion on the wind down of energy marketing.

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

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

	Utility		Energy											Consolidated
	Operations		Marketing		IFS			Other			Eliminations			Total
	(thousands of dollars)
2003
Revenues	$	782,720	$	19,916	$	-	$		20,366	$		-	$		823,002
Operating income (loss)		121,694		(18,099)		(796)			(18,737)			-			84,062
Other income (expense)		14,678		2,320		(9,930)			2,820			(3,559)			6,329
Interest expense (income) and other		59,483		53		5,821			3,134			(3,559)			64,932
Income (loss) before income taxes		76,889		(15,832)		(16,547)			(19,051)			-			25,459
Income tax expense (benefit)		21,728		(6,269)		(26,951)			(9,627)			-			(21,119)
Net income (loss)		55,161		(9,563)		10,404			(9,424)			-			46,578
Total assets		2,820,711		50,802		141,286			158,547			(69,620)			3,101,726
Expenditures for long-lived assets		148,494		-		3			1,447			-			149,944

2002
Revenues	$	869,040	$	46,410	$	-	$		13,350	$		-	$		928,800
Operating income (loss)		132,661		(23,739)		(923)			(32,359)			-			75,640
Other income (expense)		11,607		(1,199)		(11,778)			12,187			(6,987)			3,830
Interest expense (income) and other		62,529		(345)		7,147			6,601			(6,987)			68,945
Income (loss) before income taxes		81,739		(24,593)		(19,848)			(26,773)			-			10,525
Income tax expense (benefit)		(2,594)		(9,710)		(28,680)			(10,163)			-			(51,147)
Net income (loss)		84,333		(14,883)		8,832			(16,610)			-			61,672
Total assets		2,876,167		381,690		157,018			198,309			(226,016)			3,387,168
Expenditures for long-lived assets		129,132		2,713		44,064			6,527			-			182,436

2001
Revenues	$	914,201	$	348,663	$	-	$		12,448	$		-	$		1,275,312
Operating income (loss)		90,102		176,712		(756)			(23,769)			-			242,289
Other income (expense)		20,631		1,795		(6,232)			13,788			(6,688)			23,294
Interest expense (income) and other		67,883		220		5,837			8,471			(6,688)			75,723
Income (loss) before income taxes		42,850		178,287		(12,825)			(18,452)			-			189,860
Income tax expense (benefit)		19,955		71,068		(18,177)			(8,200)			-			64,646
Net income (loss)		22,895		107,219		5,352			(10,252)			-			125,214
Total assets		2,987,382		717,659		123,723			81,937			(140,709)			3,769,992
Expenditures for long-lived assets		163,045		6,749		10			8,952			-			178,756

13. REGULATORY MATTERS:

In addition, IPC has proposed extensive rate design changes including seasonal rates for most customers, increased fixed charges for smaller customer classes and time of day rates for industrial customers. If approved, the price IPC charges its customers from June to August would reflect IPC's seasonably higher costs of producing or purchasing power. The change would result in summer and non-summer base rates. The seasonal pricing proposal necessitated IPC to recommend the annual PCA rate changes be implemented June 1 each year instead of May 16. If approved this change would eliminate the need for back-to-back rate changes and the PCA recovery period would be June 1 through May 31.

On February 20, 2004, the IPUC Staff and seven other intervenors filed their testimony with the IPUC. The testimony covered revenue requirement and rate design issues. The IPUC Staff's proposal of $15 million, a three percent overall increase to base rates, was the lowest recommendation of any of the parties. Copies of the parties' increase in base rates testimony and exhibits can be viewed at the IPUC web site. IPC has until March 19, 2004 to prepare its rebuttal to these recommendations.

IPC's proposal requests revenue recovery for certain costs of serving its customers, such as increased operating expenses and substantial demands for infrastructure improvements, increased capital costs for the Protection, mitigation and Enhancement (PM&E) requirements of new licenses at most of its hydroelectric projects, for the cost of new sources of power and continued expansion of its transmission and distribution network. Because the Idaho jurisdiction does not allow assets that have not been placed in service to be included in the rate base, Bennett Mountain Power Plant (BMPP) and relicensing costs included in Construction Work in Progress (CWIP) are not included in this filing. IPC is requesting an 11.2 percent return on equity and an overall rate of return of 8.4 percent. The success of this rate case is dependent on the IPUC's review and approval, which could take up to seven months from the filing date. IPC is unable to predict what rate relief the IPUC will grant.

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 and the IPUC. The FERC matters have been resolved; however, compensation issues remain to be resolved with the IPUC.

In an IPUC proceeding that has been underway since May 2001, IPC, the IPUC staff and several interested customer groups have been working 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. In the same order, the IPUC directed IPC to present a resolution or a status report to the IPUC on additional compensation due to the utility for the use of its transmission system and other capital assets by IE and any remaining transfer pricing issues. Status reports were filed with the IPUC on December 20, 2002, March 20, 2003 and May 13, 2003 and settlement discussions were initiated. The $5.8 million in benefits related to the FERC settlement have been included in the 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 is being 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 is subject to their approval.

Deferred Power Supply Costs
IPC's deferred power supply costs consist of the following at December 31, 2003 and 2002 (in thousands of dollars):

			2003		2002
Oregon deferral			$	13,620		$	14,172
Idaho PCA current year power supply cost deferrals:
	Deferral for 2003-2004 rate year			44,664			-
	Deferral for 2002-2003 rate year			-			8,910
	Astaris load reduction agreement			-			27,160
Idaho PCA true-up awaiting recovery:
	Irrigation and small general service deferral for recovery in
		the 2003-2004 rate year		-			12,049
	Industrial customer deferral for recovery in the 2003-2004 rate year			-			3,744
	Remaining true-up authorized May 2002			-			74,253
	Remaining true-up authorized May 2003			13,646			-
	Total deferral		$	71,930		$	140,288

So far in the 2003-2004 PCA rate year, actual power supply costs have exceeded those anticipated in the forecast, due principally to greater reliance on, and higher market prices for, purchased power. Below normal water conditions also continues to negatively impact forecasted and actual power supply costs.

Oregon: IPC also filed applications with the Oregon Public Utilities Commission (OPUC) to recover calendar year 2001 extraordinary power supply costs applicable to the Oregon jurisdiction. In two separate 2001 orders, the OPUC has approved rate increases totaling six percent, which is the maximum annual rate of recovery allowed under Oregon state law. These increases are recovering approximately $2 million annually. The Oregon deferred balance was $14 million as of December 31, 2003. During the 2003 Oregon legislative session, the maximum annual rate of recovery was raised to ten percent under certain circumstances. IPC expects to request the higher percentage in Spring 2004.

Regulatory Assets and Liabilities
The following is a breakdown of IPC's regulatory assets and liabilities for the years 2003 and 2002 (in thousands of dollars):

		2003				2002
		Assets		Liabilities		Assets		Liabilities
Income taxes		$	330,833	$	41,024	$	327,934	$	41,013
Conservation			21,108		5,288		24,450		4,402
Employee benefits			993		-		1,909		-
PCA deferral and amortization			58,310		-		126,116		-
Oregon deferral and amortization			13,620		-		14,172		-
Derivatives			125		-		91		-
Asset retirement obligations			6,456		-		-		-
Asset removal costs			-		142,595		-		137,674
Other			2,584		1,828		4,634		1,272
Deferred investment tax credits			-		67,789		-		67,560
	Total	$	434,029	$	258,524	$	499,306	$	251,921

The regulatory assets related to income taxes, AROs and derivatives do not earn a current return on investment. For further information on the ARO amounts, please refer to Note 1. Additionally, at December 31, 2003, $2 million of other regulatory assets were not earning a return. These assets consist of reorganization costs and employee benefits related to SFAS 112, "Employer Accounting for Post-employment Benefits." The remaining amortization periods of these regulatory assets are one and two years, respectively.

In the event that recovery of costs through rates becomes unlikely or uncertain, SFAS 71 would no longer apply. If IPC were to discontinue application of SFAS 71 for some or all of 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 and EITF 02-3. 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):

			2003		2002		2001
Gross Margin:
	Realized or otherwise settled		$	61,183	$	70,262	$	149,956
	Unrealized			(42,517)		(65,965)		92,803
		Total	$	18,666	$	4,297	$	242,759

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. Since these announcements in 2002, IE has completed the major milestones outlined in the wind down of the business. These milestones include the sale of IE's forward book of electricity trading contracts to SET 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 Selling, general and administrative 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 charge accruals 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		978		-		5,357
	Amounts paid		(6,594)		(708)		(162)		(7,464)
	Amounts reversed		(149)		-		-		(149)
Balance at December 31, 2003		$	1,807	$	2,755	$	33	$	4,595

16. SUPPLEMENTAL CASH FLOW INFORMATION:

Selected cash payments and non-cash activities were as follows (in thousands of dollars):

		Year Ended December 31,
		2003		2002		2001
Cash paid (received) during the period for:
	Income taxes	$	52,882	$	(39,678)	$	(17,766)
	Interest (net of amount capitalized)	$	58,931	$	62,665	$	70,052
Distribution of treasury shares for acquisition		$	237	$	-	$	7,532

INDEPENDENT AUDITORS' REPORT

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

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries as of December 31, 2003 and 2002, 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, 2003. Our audits also included the consolidated financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of IDACORP, Inc. and subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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.

As discussed in Note 1 to the consolidated financial statements, in 2002 the Company changed its method of accounting for goodwill to conform to Statement of Financial Accounting Standards No. 142. Also, as discussed in Note 1, the Company changed its method of accounting and presentation of asset retirement obligations in 2003 in accordance with Statement of Financial Accounting Standards No. 143.

DELOITTE & TOUCHE LLP

Boise, Idaho
February 27, 2004

Idaho Power Company
Consolidated Statements of Income

				Year Ended December 31,
				2003		2002		2001
				(thousands of dollars)
OPERATING REVENUES:
	General business			$	670,969	$	772,035	$	650,608
	Off-system sales				71,573		55,031		219,966
	Other revenues				37,840		39,981		41,738
		Total operating revenues			780,382		867,047		912,312
OPERATING EXPENSES:
	Operation:
		Purchased power			150,980		142,102		584,209
		Fuel expense			99,898		102,871		98,318
		Power cost adjustment			70,762		170,489		(175,925)
		Other			156,030		150,884		153,079
	Maintenance				62,799		54,599		55,877
	Depreciation				97,650		93,609		87,041
	Taxes other than income taxes				20,753		19,953		19,693
		Total operating expenses			658,872		734,507		822,292

INCOME FROM OPERATIONS					121,510		132,540		90,020

OTHER INCOME:
	Allowance for equity funds used during construction				3,385		333		752
	Other income				19,803		19,271		25,485
	Other expense				8,326		7,876		5,638
		Total other income			14,862		11,728		20,599

INTEREST CHARGES:
	Interest on long-term debt				54,645		51,127		55,704
	Other interest				4,718		9,190		10,402
	Allowance for borrowed funds used during
		construction			(3,310)		(2,375)		(3,737)
		Total interest charges			56,053		57,942		62,369

INCOME BEFORE INCOME TAXES					80,319		86,326		48,250

INCOME TAX EXPENSE (BENEFIT)					21,728		(2,594)		19,955

INCOME FROM CONTINUING OPERATIONS					58,591		88,920		28,295

DISCONTINUED OPERATIONS
	Income from operations of energy marketing
			transferred to parent (net of tax of $33,574)		-		-		49,943

NET INCOME					58,591		88,920		78,238

	Dividends on preferred stock				3,430		4,587		5,400

EARNINGS ON COMMON STOCK				$	55,161	$	84,333	$	72,838

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets

Assets

				December 31,
				2003		2002
				(thousands of dollars)

ELECTRIC PLANT:
	In service (at original cost)			$	3,220,228	$	3,086,965
	Accumulated provision for depreciation				(1,239,604)		(1,157,287)
		In service - Net			1,980,624		1,929,678
	Construction work in progress				96,086		92,481
	Held for future use				2,438		2,335

			Electric plant - Net		2,079,148		2,024,494

INVESTMENTS AND OTHER PROPERTY					49,739		42,272

CURRENT ASSETS:
	Cash and cash equivalents				4,031		12,699
	Receivables:
		Customer			43,694		56,947
		Allowance for uncollectible accounts			(1,466)		(1,566)
		Notes			3,186		2,809
		Employee notes			3,347		3,240
		Related parties			1,143		27,905
		Other			4,848		2,702
	Accrued unbilled revenues				30,869		35,714
	Materials and supplies (at average cost)				19,755		21,458
	Fuel stock (at average cost)				6,228		6,943
	Prepayments				26,835		32,818
	Regulatory assets				6,269		17,147

			Total current assets		148,739		218,816

DEFERRED DEBITS:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,624		35,299
	Regulatory assets				427,760		482,159
	Employee notes				4,775		4,615
	Other				43,341		36,927

			Total deferred debits		543,085		590,585

	TOTAL			$	2,820,711	$	2,876,167

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets

Capitalization and Liabilities

				December 31,
				2003		2002
					(thousands of dollars)
CAPITALIZATION:
	Common stock equity:
		Common stock, $2.50 par value (50,000,000 shares
			authorized; 39,150,812 and 37,612,351 shares outstanding,
			respectively)	$	97,877	$	94,031
		Premium on capital stock			398,231		361,948
		Capital stock expense			(2,686)		(2,710)
		Retained earnings			320,735		330,300
		Accumulated other comprehensive income (loss)			(2,630)		(7,109)

			Total common stock equity		811,527		776,460

	Preferred stock				52,366		53,393

	Long-term debt				880,868		870,741

			Total capitalization		1,744,761		1,700,594

CURRENT LIABILITIES:
	Long-term debt due within one year				50,077		80,084
	Notes payable				-		10,500
	Accounts payable				45,529		52,676
	Notes and accounts payable to related parties				75		52
	Taxes accrued				55,383		89,090
	Interest accrued				12,893		12,399
	Deferred income taxes				6,179		17,056
	Other				20,985		22,906

			Total current liabilities		191,121		284,763

DEFERRED CREDITS:
	Deferred income taxes				546,205		574,233
	Regulatory liabilities				258,524		251,921
	Other				80,100		64,656

			Total deferred credits		884,829		890,810

COMMITMENTS AND CONTINGENT LIABILITIES

			TOTAL	$	2,820,711	$	2,876,167

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization

				December 31,
				2003		%		2002		%
				(thousands of dollars)
COMMON STOCK EQUITY:
	Common stock			$	97,877			$	94,031
	Premium on capital stock				398,231				361,948
	Capital stock expense				(2,686)				(2,710)
	Retained earnings				320,735				330,300
	Accumulated other comprehensive income (loss)				(2,630)				(7,109)
		Total common stock equity			811,527		47		776,460		46

PREFERRED STOCK:
	4% preferred stock				12,366				13,393
	7.68% Series, serial preferred stock				15,000				15,000
	7.07% Series, serial preferred stock				25,000				25,000
		Total preferred stock			52,366		3		53,393		3

LONG-TERM DEBT:
	First mortgage bonds:
		6.40% Series due 2003			-				80,000
		8 % Series due 2004			50,000				50,000
		5.83% Series due 2005			60,000				60,000
		7.38% Series due 2007			80,000				80,000
		7.20% Series due 2009			80,000				80,000
		6.60% Series due 2011			120,000				120,000
		4.75% Series due 2012			100,000				100,000
		4.25% Series due 2013			70,000				-
		7.50% Series due 2023			-				80,000
		6 % Series due 2032			100,000				100,000
		5.50% Series due 2033			70,000				-
			Total first mortgage bonds		730,000				750,000
		Amount due within one year			(50,000)				(80,000)
			Net first mortgage bonds		680,000				670,000

	Pollution control revenue bonds:
		8.30% Series 1984 due 2014			-				49,800
		6.05% Series 1996A due 2026			68,100				68,100
		Variable Rate Series 1996B due 2026			24,200				24,200
		Variable Rate Series 1996C due 2026			24,000				24,000
		Variable Rate Series 2000 due 2027			4,360				4,360
		Variable Auction Rate Series 2003 due 2024			49,800				-
			Total pollution control revenue bonds		170,460				170,460

	REA notes				1,105				1,185
		Amount due within one year			(77)				(84)
			Net REA notes		1,028				1,101

	American Falls bond guarantee				19,885				19,885
	Milner Dam note guarantee				11,700				11,700
	Unamortized premium/discount - Net				(2,205)				(2,405)
			Total long-term debt		880,868		50		870,741		51

TOTAL CAPITALIZATION				$	1,744,761		100	$	1,700,594		100

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Cash Flows

				Year Ended December 31,
				2003		2002		2001
				(thousands of dollars)
OPERATING ACTIVITIES:
	Net income			$	58,591	$	88,920	$	78,238
	Adjustments to reconcile net income to net cash provided by
	(used in) operating activities:
		Other than temporary decline in market value of investments			(408)		980		-
		Allowance for uncollectible accounts			(40)		66		20,277
		Unrealized gains from energy marketing activities			-		-		(100,653)
		Depreciation and amortization			110,228		104,948		99,565
		Deferred taxes and investment tax credits			(44,221)		(81,511)		103,423
		Accrued PCA costs			68,358		164,201		(184,584)
		Change in:
			Accounts receivable and prepayments		24,487		(2,587)		(19,912)
			Accrued unbilled revenue		4,845		1,687		7,425
			Materials and supplies and fuel stock		2,418		3,605		(2,216)
			Accounts payable		(7,147)		(23,009)		(26,142)
			Taxes receivable/accrued		(33,707)		97,335		(21,227)
			Other current liabilities		(1,427)		5,980		(2,081)
		Other assets			(6,972)		(589)		(5,903)
		Other liabilities			10,118		6,720		(4,883)
		Net cash provided by (used in) operating activities			185,123		366,746		(58,673)

INVESTING ACTIVITIES:
	Additions to utility plant				(148,246)		(128,318)		(156,787)
	Note receivable payment from parent				19,282		11,859		42,743
	Other assets				(622)		(4,265)		(776)
		Net cash used in investing activities			(129,586)		(120,724)		(114,820)

FINANCING ACTIVITIES:
	Issuance of first mortgage bonds				140,000		200,000		120,000
	Issuance of pollution control revenue bonds				49,800		-		-
	Retirement of first mortgage bonds				(160,000)		(77,000)		(130,000)
	Retirement of pollution control revenue bonds				(49,800)		-		-
	Retirement of preferred stock				(860)		(50,994)		-
	Proceeds from sale of common stock to parent				39,987		-		-
	Dividends on common stock				(64,726)		(70,178)		(69,782)
	Dividends on preferred stock				(3,430)		(4,587)		(5,400)
	Increase (decrease) in short-term borrowings				(10,500)		(271,500)		222,300
	Other assets				(4,187)		(2,094)		(3,375)
	Other liabilities				(489)		(10)		(704)
		Net cash provided by (used in) financing activities			(64,205)		(276,363)		133,039

Net decrease in cash and cash equivalents					(8,668)		(30,341)		(40,454)
Cash and cash equivalents at beginning of period					12,699		43,040		83,494

Cash and cash equivalents at end of period				$	4,031	$	12,699	$	43,040

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Retained Earnings

		Year Ended December 31,
		2003		2002		2001
		(thousands of dollars)

RETAINED EARNINGS, BEGINNING OF YEAR		$	330,300	$	316,856	$	313,800

NET INCOME			58,591		88,920		78,238

DIVIDENDS:
	Common stock		(64,726)		(70,178)		(69,782)
	Preferred stock		(3,430)		(4,587)		(5,400)

PREFERRED STOCK REDEMPTION			-		(711)		-

RETAINED EARNINGS, END OF YEAR		$	320,735	$	330,300	$	316,856

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income

						Year Ended December 31,
						2003		2002		2001
						(thousands of dollars)

NET INCOME						$	58,591	$	88,920	$	78,238

OTHER COMPREHENSIVE INCOME (LOSS):
	Unrealized gains on securities:
			Unrealized holding gains (losses) arising during the period,
					net of tax of $2,963, ($1,840) and($992)		4,982		(2,991)		(1,690)
			Reclassification adjustment for (gains) losses included
					in net income, net of tax of ($111), $1,007and ($52)		(173)		1,560		(80)
					Net unrealized losses (gains)		4,809		(1,431)		(1,770)
		Minimum pension liability adjustment, net of tax of ($191),
				($1,265) and ($649)			(330)		(1,959)		(1,028)

TOTAL COMPREHENSIVE INCOME						$	63,070	$	85,530	$	75,440

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 2003 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 Contingent Liabilities

Note 10 - Benefit Plans

Note 11 - Property, Plant and Equipment and Jointly-Owned Projects

Note 13 - Regulatory Matters

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stock-Based Compensation
At December 31, 2003, two stock-based employee compensation plans existed, which are described more fully in Note 9. These plans are accounted for under the recognition and measurement principles of APB Opinion 25, "Accounting for Stock Issued to Employees," and related interpretations. Grants of restricted stock are reflected in net income based on the market value at the award date, or the year-end price for shares not yet vested. No stock-based employee compensation cost is reflected in net income for stock options, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

The following table illustrates the effect on net income if the fair value recognition provisions of SFAS 123, "Accounting for Stock-Based Compensation," had been applied to stock-based employee compensation:

			2003		2002		2001
			(thousands of dollars)
Net income, as reported			$	58,591	$	88,920	$	78,238
Add: Stock-based employee compensation expense included
	in reported net income, net of related tax effects			(56)		(10)		403
Deduct: Total stock-based employee compensation expense
	determined under fair value based method for all awards,
	net of related tax effects			1,073		1,837		1,603
		Pro forma net income	$	57,462	$	87,073	$	77,038

2. INCOME TAXES:

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

		2003		2002		2001
		(thousands of dollars)
Federal income tax expense at 35% statutory rate		$	28,112	$	30,214	$	46,118
Change in taxes resulting from:
	AFDC		(2,343)		(948)		(1,571)
	Investment tax credits		(3,397)		(3,179)		(3,169)
	Repair allowance		(2,450)		(2,450)		(2,800)
	Capitalized overhead costs		(3,658)		(3,500)		-
	Tax accounting method change		-		(31,162)		-
	Settlement of prior years tax returns		(8,908)		(2,600)		-
	State income taxes, net of federal benefit		3,973		3,946		4,313
	Depreciation		10,237		8,940		9,790
	Other, net		162		(1,855)		848
Total income tax expense (benefit)		$	21,728	$	(2,594)	$	53,529
	Effective tax rate		27.1%		(3.0)%		40.6%

The items comprising income tax expense are as follows:

			2003		2002		2001
			(thousands of dollars)
Income taxes currently payable (receivable):
	Federal		$	55,034	$	70,318	$	(37,352)
	State			10,915		8,599		(12,544)
		Total		65,949		78,917		(49,896)
Income taxes deferred:
	Federal			(35,166)		(75,600)		84,372
	State			(9,284)		(5,455)		17,087
		Total		(44,450)		(81,055)		101,459
Investment tax credits:
	Deferred			3,627		2,722		5,135
	Restored			(3,398)		(3,178)		(3,169)
		Total		229		(456)		1,966
Total income tax expense (benefit)			$	21,728	$	(2,594)	$	53,529

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

			2003		2002
			(thousands of dollars)
Deferred tax assets:
	Regulatory liabilities		$	41,024	$	41,013
	Advances for construction			4,162		3,759
	Other			16,151		19,800
		Total		61,337		64,572
Deferred tax liabilities:
	Property, plant and equipment			238,602		230,935
	Regulatory assets			330,833		327,933
	Conservation programs			8,310		10,426
	PCA			27,529		53,324
	Other			8,447		33,243
		Total		613,721		655,861

Net deferred tax liabilities			$	552,384	$	591,289

3. COMMON STOCK:

In December 2003, IPC issued 1,538,461 shares of $2.50 par value common stock to IDACORP for $40 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.

	December 31, 2003				December 31, 2002
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
Assets:
Notes receivable	$	10,145	$	10,159	$	9,646	$	10,063
Investments and other property		22,408		22,408		20,401		20,401

Liabilities:
Long-term debt	$	933,150	$	957,399	$	953,230	$	1,015,612

9. STOCK-BASED COMPENSATION:

The 2000 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 2003, 2002 and 2001, IDACORP issued to IPC employees 343,000, 230,000 and 144,000 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:

		2003			2002			2001
			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		594,000	$	38.33	364,000	$	37.59	220,000	$	35.81
	Granted	343,000		22.95	230,000		39.50	144,000		40.31
	Exercised	-		-	-		-	-		-
	Forfeited	(47,200)		36.42	-		-	-		-
Outstanding end of year		889,800	$	32.50	594,000	$	38.33	364,000	$	37.59

Exercisable		211,600	$	37.84	100,800	$	37.10	36,000	$	35.81

The outstanding options have a range of exercise prices from $22.92 to $40.31. As of December 31, 2003, the weighted average remaining contractual life is 8.0 years.

IDACORP also has a restricted stock plan for key employees including those of IPC. Each grant made under this plan has a three-year restricted period, and the final award amounts depend on the attainment of cumulative EPS performance goals. At December 31, 2003 there were 145,314 IDACORP shares remaining available under this plan.

Restricted stock awards are compensatory awards and IPC accrues compensation expense (which is charged to operations) based upon the market value of the granted shares. For the years 2003, 2002 and 2001, total compensation accrued under the plan was less than $1 million annually.

The following table summarizes restricted stock activity for the years 2003, 2002 and 2001:

		2003		2002		2001
Shares outstanding - beginning of year		77,192		58,024		56,836
Shares granted		41,945		38,752		20,540
Shares forfeited		(1,889)		(132)		(474)
Shares issued		(36,794)		(19,452)		(18, 878)
Shares outstanding - end of year		80,454		77,192		58,024
Weighted average fair value of current year stock
	grants on grant date	$	22.95	$	38.64	$	38.02

16. SUPPLEMENTAL CASH FLOW INFORMATION:

Selected cash payments and non-cash activities were as follows (in thousands of dollars):

		Year Ended December 31,
		2003		2002		2001
Cash paid (received) during the period for:
	Income taxes paid to (received from) parent	$	99,879	$	(17,974)	$	(28,510)
	Interest (net of amount capitalized)		54,911		56,167		61,600
Net assets transferred to parent for notes receivable			-		-		76,250

17. DISCONTINUED OPERATIONS:

Effective June 11, 2001, IPC transferred its non-utility wholesale electricity marketing operations ("Energy Marketing") to IE.

Energy Marketing net assets transferred consist primarily of energy trading contracts and trading accounts receivable and accounts payable. The results of operations of Energy Marketing were previously reported on IPC's Statements of Income as "Energy marketing activities - net." For 2001, Energy Marketing is reported as a discontinued operation.

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.

In September 2002, IPC borrowed $100 million from IDACORP in order to repay a like amount of floating rate notes. This amount was repaid, with interest, on November 15, 2002.

IDACORP Energy
In 2002 and 2001, IPC paid IE approximately $2 million annually under the Electricity Supply Management Services Agreement. In August 2002, IPC and IE terminated the Electricity Supply Agreement eliminating all payments under that agreement. The FERC has given 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:

	2003		2002		2001
	(thousands of dollars)
Sales to IE	$	2,268	$	27,182	$	21,288
Purchases from IE		-		13,665		34,843

IDACOMM
IPC provides project management and engineering services to IDACOMM. IDACOMM also pays joint use fees to IPC. The following table presents the fees charged to IDACOMM:

	2003		2002		2001
	(thousands of dollars)
Project management	$	72	$	809	$	10
Engineering		141		73		-
Joint use		61		176		-
Total	$	274	$	1,058	$	10

Ida-West
IPC purchases all of the power generated by four of Ida-West's hydroelectric projects. IPC paid $7 million in both 2003 and 2002 and $6 million in 2001 for this power.

INDEPENDENT AUDITORS' REPORT

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 as of December 31, 2003 and 2002, 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, 2003. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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.

As discussed in Note 1, the Company changed its method of accounting and presentation of asset retirement obligations in 2003 in accordance with Statement of Financial Accounting Standards No. 143.

DELOITTE & TOUCHE LLP

Boise, ID
February 27, 2004

SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA:

The following unaudited information is presented for each quarter of 2003 and 2002 (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

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

2002
Revenues	$	239,593	$	209,832	$	259,576	$	219,798
Income from operations		47,257		7,743		16,620		14,476
Income tax expense (benefit)		9,329		(9,329)		(38,527)		(12,620)
Net income (loss)*		24,696		3,077		36,908		(3,008)
Earnings (loss) per share of common stock		0.66		0.08		0.98		(0.08)

*See "Wind down of Energy Marketing" in Note 13 to IDACORP's Consolidated Financial Statements,
"Legal Proceedings - Overton Power District No. 5" in Note 8 to IDACORP's Consolidated Financial
Statements and "Tax Accounting Method Change" in Note 2 to IDACORP's Consolidated Financial
Statements.

Idaho Power Company:

	Quarter Ended
	March 31		June 30		September 30		December 31

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

2002
Revenues	$	214,586	$	209,068	$	237,251	$	206,143
Income from operations		45,186		32,687		22,036		32,631
Income tax expense (benefit)		13,805		9,149		(31,129)		5,580
Net income		22,886		13,834		39,355		12,846
Dividends on preferred stock		1,362		1,298		919		1,008
Earnings on common stock		21,524		12,536		38,436		11,838

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of disclosure controls and procedures:

The Chief Executive Officer and Chief Financial Officer of IDACORP, Inc., based on their evaluation of IDACORP, Inc.'s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2003, have concluded that IDACORP, Inc.'s disclosure controls and procedures are effective.

The Chief Executive Officer and Chief Financial Officer of Idaho Power Company, based on their evaluation of Idaho Power Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2003, have concluded that Idaho Power Company's disclosure controls and procedures are effective.

(b) Changes in internal control over financial reporting:

There has been no change in IDACORP, Inc.'s or Idaho Power Company's internal control over financial reporting identified in connection with the evaluation required by Exchange Act Rule 13a-15(d) that occurred during IDACORP, Inc.'s or Idaho Power Company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect IDACORP, Inc.'s or Idaho Power Company's internal control over financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

The portion of our joint definitive proxy statement appearing under the captions "Election of Directors - IDACORP and Idaho Power Nominees For Election - Terms Expire 2007," "IDACORP and Idaho Power Continuing Directors - Terms Expire 2006," "IDACORP and Idaho Power Continuing Directors - Terms Expire 2005," "The Boards of Directors and Committees - Committees - Audit Committees" and "Corporate Governance - Process for Shareholders to Recommend Nominees for Directors," to be filed pursuant to Regulation 14A for the 2004 Annual Meeting of Shareholders to be held on May 20, 2004 is hereby incorporated by reference.

Idaho Power has had for many years a Code of Business Conduct and Ethics, which applied to all directors, officers and employees of Idaho Power, including the principal executive officer and senior financial and accounting officers. IDACORP adopted a new Code of Business Conduct and Ethics in July 2003, which applies to all directors, officers, including the chief executive officer, principal financial and accounting officers, and employees of IDACORP and its subsidiaries. The Code of Conduct may be accessed at the IDACORP website at http://www.idacorpinc.com/CorpGov/conduct_ethics.cfm. Printed copies may be obtained without charge by writing to the Corporate Secretary, IDACORP, 1221 West Idaho Street, Boise, Idaho 83702.

Amendments to the Code or waivers of the Code as required by Regulation S-K, Item 406 or the New York Stock Exchange listing standards will be posted on the IDACORP website referred to above.

ITEM 11. EXECUTIVE COMPENSATION

The portion of our joint 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 2004 Annual Meeting of Shareholders to be held on May 20, 2004 is hereby incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The portion of our joint definitive proxy statement appearing under the captions "Principal Shareholders" and "Security Ownership of Directors and Executive Officers" to be filed pursuant to Regulation 14A for the 2004 Annual Meeting of Shareholders to be held on May 20, 2004 is hereby incorporated by reference.

Equity Compensation Plan Information:

The following table includes information as of December 31, 2003 with respect to equity compensation plans where equity securities of IDACORP may be issued. There are no plans where equity securities of IPC may be issued. These plans are the 1994 Restricted Stock Plan (RSP), the IDACORP 2000 Long Term Incentive and Compensation Plan (LTICP) and the Director Compensation Plan (DCP).

		(a)	(b)	(c)
				Number of securities
				remaining available for
		Number of securities to	Weighted-average	future issuance under
		be issued upon exercise	exercise price of	equity compensation
		of outstanding options,	outstanding options,	plans (excluding securities
Plan Category		warrants and rights	warrants and rights	reflected in column (a))
Equity compensation
plans approved by
shareholders (1)		1,150,800	$32.72	1,044,514(2)(3)
Equity compensation
plans not approved by
shareholders (4)		-	-	83,101
Total		1,150,800	$32.72	1,127,615
(1)	Consists of the RSP and the LTICP.
(2)	In addition to being available for future issuance upon exercise of options, 899,200 shares under the
	LTICP may instead be issued in connection with stock appreciation rights, restricted stock, restricted
	stock units, performance units, performance shares or other equity-based awards.
(3)	145,314 shares remain available for future issuance under the RSP.
(4)	Consists of the DCP.

Equity Compensation Plans Not Approved by IDACORP Shareholders

The DCP was adopted by the IDACORP Board of Directors effective May 17, 1999, and provided for an annual stock grant in June of each year valued at $6,000. The purpose of the DCP is to increase director's stock ownership through stock based director compensation. The DCP was amended again effective April 1, 2002 to increase the annual grant to stock valued at $16,000. This increase offset the termination of the directors' non-qualified deferred compensation plan. Because the IDACORP and IPC Boards of Directors are comprised of the same members, IPC non-employee directors do not receive an additional grant. The plan provides for a total of 100,000 shares that may be granted from treasury stock or stock purchased on the open market.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

N/A

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The portion of our joint definitive proxy statement appearing under the caption "Independent Accountant Billings" and "Audit Committee Policy for Pre-Approval of Independent Auditor Services" in Exhibit B to the proxy statement to be filed pursuant to Regulation 14A for the 2004 Annual Meeting of Shareholders to be held on May 20, 2004 is hereby incorporated by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 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.

(b) Reports on SEC Form 8-K. The following Reports on Form 8-K were filed for the three months ended December 31, 2003.

Items Reported	Date of Report	Filed by
Item 5 - Other Events and Regulation FD Disclosure	November 13, 2003	IDACORP, Inc. and
		Idaho Power Company

*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 10-Q for the quarter ended 6/30/00	3(a)(iii)	Articles of Amendment to Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 15, 2000.

*3(b)	1-3198 Form 10-Q for the quarter ended 3/31/03	3(b)	By-laws of IPC amended on March 20, 2003, 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)	333-104254	4(e)	Amended Bylaws of IDACORP, Inc. amended on March 20, 2003, 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)	1-11465 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	1-3198 Form 10-K for 1996	10(n)(iv)	The Revised Security Plan for Senior Management Employees - a non-qualified, deferred compensation plan effective August 1, 1996.

10(h)(ii) 1			IDACORP, Inc. 2003 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-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)(v) 1	1-14465 1-3198 Form 10-K for 2002	10(h)(v)	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan as of May 17, 1999, as amended.

*10(h)(vi)	1-14465 Form 10-Q for the quarter ended 9/30/99	10(h)	Agreement between IDACORP, Inc. and Jan B. Packwood, J. LaMont Keen, James C. Miller, Darrel T. Anderson, Bryan Kearney and Robert W. Stahman.


1 Compensatory plan

*10(h)(vii) 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(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.)

12(c)			Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IDACORP, Inc.)

12(d)			Statement Re: Computation of Ratio of Earnings to Fixed Charges. (IPC)

12 (e)			Statement Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC)

12(f)			Statement Re: Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC)


1 Compensatory plan

12(g)			Statement Re: Computation of Supplemental Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements. (IPC)

21			Subsidiaries of IDACORP, Inc. and IPC.

23			Independent Auditors' Consent.

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.

IDACORP, Inc.
SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2003, 2002 and 2001

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)

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				2,491		167		(227)			-				2,431

2002:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	42,529	$	5,415	$	-	$		4,633	$			43,311
Other Reserves:
	Rate refunds				-		-		-			-				-
	Injuries and damages reserve				1,500		(255)		719			28				1,936
	Miscellaneous operating reserves				3,551		418		(442)			1,036				2,491

2001:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	23,079	$	27,469	$	-	$		8,019	$			42,529
Other Reserves:
	Rate refunds				-		-		-			-				-
	Injuries and damages reserve				1,500		-		-			-				1,500
	Miscellaneous operating reserves				4,656		107		(11)			1,201				3,551

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, 2003, 2002 and 2001

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)

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				2,491		167		(227)			-			2,431

2002:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	1,500	$	4,699	$	-	$		4,633	$		1,566
Other Reserves:
	Rate refunds				-		-		-			-			-
	Injuries and damages reserve				1,500		(255)		719			28			1,936
	Miscellaneous operating reserves				3,551		418		(442)			1,036			2,491

2001:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	23,079	$	3,607	$	(21,682)	$		3,504	$		1,500
Other Reserves:
	Rate refunds				-		-		-			-			-
	Injuries and damages reserve				1,500		-		-			-			1,500
	Miscellaneous operating reserves				4,656		107		(11)			1,201			3,551

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 4, 2004

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 4, 2004
		Jon H. Miller


By:	/s/	Jan B. Packwood		/s/	President and Chief Executive	"
		Jan B. Packwood			Officer and Director

By:	/s/	Darrel T. Anderson		/s/	Vice President, Chief Financial	"
		Darrel T. Anderson			Officer and Treasurer
					(Principal Financial Officer)
					(Principal Accounting Officer)

By:	/s/	Rotchford L. Barker	By:	/s/	Peter S. O'Neill	"
		Rotchford L. Barker			Peter S. O'Neill
		Director			Director

By:			By:	/s/	Richard G. Reiten	"
		Christopher L. Culp			Richard G. Reiten
		Director			Director

By:	/s/	Jack K. Lemley	By:	/s/	Robert A. Tinstman	"
		Jack K. Lemley			Robert A. Tinstman
		Director			Director

By:	/s/	Gary G. Michael
		Gary G. Michael
		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 4, 2004

By:/s/J. LaMont Keen
J. LaMont Keen
President and Chief Operating Officer

By:	/s/	Jon H. Miller		/s/	Chairman of the Board	March 4, 2004
		Jon H. Miller


By:	/s/	Jan B. Packwood		/s/	Chief Executive Officer	"
		Jan B. Packwood			and Director


By:	/s/	J. LaMont Keen		/s/	President and Chief Operating	"
By:		J. LaMont Keen			Officer


By:	/s/	Darrel T. Anderson		/s/	Vice President, Chief Financial	"
		Darrel T. Anderson			Officer and Treasurer
					(Principal Financial Officer)
					(Principal Accounting Officer)

By:	/s/	Rotchford L. Barker	By:	/s/	Peter S. O'Neill	"
		Rotchford L. Barker			Peter S. O'Neill
		Director			Director

By:			By:	/s/	Richard G. Reiten	"
		Christopher L. Culp			Richard G. Reiten
		Director			Director

By:	/s/	Jack K. Lemley	By:	/s/	Robert A. Tinstman	"
		Jack K. Lemley			Robert A. Tinstman
		Director			Director

By:	/s/	Gary G. Michael
		Gary G. Michael
		Director

EXHIBIT INDEX


Exhibit Number

10(h)(ii) 1		IDACORP, Inc. 2003 Executive Incentive Plan

12		Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IDACORP, Inc.)

12(a)		Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges.
		(IDACORP, Inc.)

12(b)		Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and
		Preferred Dividend Requirements. (IDACORP, Inc.)

12(c)		Statements Re: Computation of Supplemental Ratio of Earnings to Combined Fixed
		Charges and Preferred Dividend Requirements. (IDACORP, Inc.)

12(d)		Statements Re: Computation of Ratio of Earnings to Fixed Charges. (IPC)

12(e)		Statements Re: Computation of Supplemental Ratio of Earnings to Fixed Charges. (IPC)

12(f)		Statements Re: Computation of Ratio of Earnings to Combined Fixed Charges and
		Preferred Dividend Requirements. (IPC)

12(g)		Statements Re: Computation of Supplemental Ratio of Earnings to Combined Fixed
		Charges and Preferred Dividend Requirements. (IPC)

21		Subsidiaries of IDACORP, Inc. and IPC.

23		Independent Auditors' Consent.

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.


1 Compensatory plan

		Exact name of registrants as specified in
Commission		their charters, address of principal executive	IRS Employer
File Number		offices 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 or other jurisdiction of incorporation: Idaho
				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 Stock 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 the joint definitive proxy statement of IDACORP, Inc. and Idaho Power Company to be
	filed pursuant to Regulation 14A for the 2004 Annual Meeting of Shareholders to be held on May 20,
	2004.

TABLE OF CONTENTS
				Page
Part I

	Item 1.	Business		1-11
	Item 2.	Properties		12-14
	Item 3.	Legal Proceedings		14
	Item 4.	Submission of Matters to a Vote of Security Holders		14

	Executive Officers of the Registrants			15-16

Part II

	Item 5.	Market for the Registrant's Common Equity and Related Stockholder
			Matters	17
	Item 6.	Selected Financial Data		18-19
	Item 7.	Management's Discussion and Analysis of Financial Condition and
			Results of Operations	20-46
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		47-48
	Item 8.	Financial Statements and Supplementary Data		49-100
	Item 9.	Changes in and Disagreements with Accountants on Accounting and
			Financial Disclosure	101
	Item 9A.	Controls and Procedures		101

Part III

	Item 10.	Directors and Executive Officers of the Registrants*		102
	Item 11.	Executive Compensation*		102
	Item 12.	Security Ownership of Certain Beneficial Owners and Management
			and Related Stockholder Matters*	103
	Item 13.	Certain Relationships and Related Transactions*		103
	Item 14.	Principal Accounting Fees and Services*		103

Part IV

	Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		104-111

	Signatures			112-113

	Exhibit Index			114

	*Incorporated by reference to the joint definitive proxy statement of IDACORP, Inc. and Idaho Power Company
	for the 2004 Annual Meeting of Shareholders, except for the Code of Ethics information in Item 10 and the
	Equity Compensation Plan information in Item 12.

X		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2003

IDACORP, Inc.:	38,160,633
Idaho Power Company:	39,150,812 all held by IDACORP, Inc.

COMMONLY USED TERMS

AFDC	-	Allowance for Funds Used During Construction
ALJ	-	Administrative Law Judge
APB	-	Accounting Principles Board
ARO	-	Asset Retirement Obligation
BMPP	-	Bennett Mountain Power Plant
BPA	-	Bonneville Power Administration
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CSPP	-	Cogeneration and Small Power Production
CWIP	-	Construction Work in Progress
DSM	-	Demand-Side Management
EITF	-	Emerging Issues Task Force
EPA	-	Environmental Protection Agency
EPS	-	Earning per share
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	FASB Interpretation
FPA	-	Federal Power Act
HCC	-	Hells Canyon Complex
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
kW	-	kilowatt
kWh	-	kilowatt-hour
LTICP	-	Long-Term Incentive and Compensation Plan
MD&A	-	Management's Discussion and Analysis of Financial Condition and Results of
			Operations
MMbtu	-	Million British Thermal Units
MMCP	-	Mitigated Market Clearing Price
MW	-	Megawatt
MWh	-	Megawatt-hour
NPC	-	Nevada Power Company
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PM&E	-	Protection, Mitigation and Enhancement
PMC	-	Plaintiff's Master Complaint
PPA	-	Power Purchase Agreement
PPLM	-	PPL Montana, LLC
PURPA	-	Public Utilities Regulatory Policy Act of 1978
REA	-	Rural Electrification Administration
RFP	-	Request for Proposal
RMC	-	Risk Management Committee
RTOs	-	Regional Transmission Organizations
SET	-	Sempra Energy Trading
SFAS	-	Statement of Financial Accounting Standards
SPPCo	-	Sierra Pacific Power Company
Valmy	-	North Valmy Steam Electric Generating Plant
WSPP	-	Western Systems Power Pool

Quarter Ended

Date of Report

Filed by

Peter S. O'Neill

Peter S. O'Neill