UNITED STATES SECURITIES AND EXCHANGE COMMISSION

SAFE HARBOR STATEMENT
This Form 10-K contains "forward-looking statements" intended to qualify for the 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," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," or 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). Due to the repeal of the Public Utility Holding Company Act of 1935 (1935 Act), effective February 8, 2006, IDACORP is no longer subject to any provisions of the 1935 Act. IDACORP is a holding company under the newly enacted Public Utility Holding Company Act of 2005 (2005 Act), which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.

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

IDACORP's other subsidiaries include:

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

IdaTech, LLC (IdaTech) - developer of integrated fuel cell systems, over 90 percent owned by IDACORP's wholly-owned subsidiary IDACORP Technologies, Inc. (ITI);

IDACOMM, Inc. (IDACOMM) - provider of telecommunications services and commercial Internet services;

Ida-West Energy Company (Ida-West) - operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA). In 2003, Ida-West discontinued its project development operations and began managing its independent power projects with a reduced workforce; and

IDACORP Energy (IE), - a marketer of electricity and natural gas, which wound down its operations in 2003.

IDACORP is focusing on a back-to-basics strategy that emphasizes IPC as IDACORP's core business. IPC continues to experience strong growth in its service area, and this corporate strategy recognizes that IPC must make substantial investments in infrastructure to ensure adequate supply and reliable service. IFS, with its affordable housing and historic rehabilitation portfolio, remains a key component of the corporate strategy.

IDACORP has revised its business strategy for IDACOMM, its wholly-owned communications subsidiary. IDACOMM now will focus on building its existing competitive local exchange carrier business in Boise, Idaho and Las Vegas and Reno, Nevada, and phasing out the portion of its business exploring the potential use of power lines as the conduit for high speed Internet service, commonly referred to as broadband-over-power line (BPL) technology.

IDACORP is reviewing strategic alternatives for IdaTech's fuel cell business, including its possible sale or merger, in an effort to minimize the financial impact on IDACORP. IdaTech is transitioning from developmental projects to commercial products.

At December 31, 2005, IDACORP had 1,993 full-time employees. Of these employees, 1,821 were employed by IPC.

IDACORP's four reportable business segments are IPC, IFS, IDACOMM and ITI. IPC and IFS contributed $72 million and $11 million, respectively, to consolidated net income in 2005. IDACOMM and ITI had net losses of $13 million and $9 million, respectively, in 2005. Financial information relating to IDACORP's reportable segments is presented in Note 12 to IDACORP's and IPC's Consolidated Financial Statements and below in "Utility Operations," "IFS," "IDACOMM" and "ITI."

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

UTILITY OPERATIONS:

IPC was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. IPC's service territory covers a 24,000 square mile area in southern Idaho and eastern Oregon, with an estimated population of 911,000. 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 24 counties in Idaho and three counties in Oregon. As of December 31, 2005, IPC supplied electric energy to approximately 457,000 general business customers.

IPC owns and operates 17 hydroelectric generation developments, two natural gas-fired plants and one diesel-powered generator 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 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 weather conditions. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of IPC's hydroelectric facilities, reservoir storage, springtime snow pack run-off, rainfall and other weather and stream flow management considerations. During low water years, when stream flows into IPC's hydroelectric projects are reduced, IPC's hydroelectric generation is reduced. This results in less generation from IPC's resource portfolio (hydroelectric, coal-fired and gas-fired) available for off-system sales and, most likely, an increased use of purchased power to meet load requirements. Both of these situations - a reduction in profitable off-system sales and an increased use of more expensive purchased power - result in increased power supply costs.

The primary influences on electricity sales are weather, customer growth and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Increased precipitation levels during the growing season reduce electricity sales to customers who use electricity to operate irrigation pumps.

IPC's principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, forest product production, beet sugar refining and the skiing industry.

Regulation
IPC is under the regulatory jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the FERC, the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC). IPC is also under the regulatory jurisdiction of the IPUC, the OPUC and the Public Service Commission of Wyoming as to the issuance of debt and equity securities. IPC is subject to the provisions of the Federal Power Act as a "public utility" as therein defined. IPC's retail rates are established under the jurisdiction of the state regulatory commissions and its wholesale and transmission rates are regulated by the FERC (see "Rates" below). Pursuant to the requirements of Section 210 of PURPA, the state regulatory commissions have each issued orders and rules regulating IPC's purchase of power from cogeneration and small power production (CSPP) facilities.

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

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

Rates
The rates IPC charges to its general business customers are determined by the IPUC and the OPUC. Approximately 96 percent of IPC's general business revenue comes from customers in Idaho. IPC has a Power Cost Adjustment (PCA) mechanism that provides for annual adjustments to the rates charged to its Idaho retail customers. These adjustments are based on forecasts of net power supply costs, which are fuel and purchased power less off-system sales, and the true-up of the prior year's forecast. During the year, 90 percent of the difference between the actual and forecasted costs is deferred with interest. The ending balance of this deferral, called the true-up for the current year's portion and the true-up of the true-up for the prior years' unrecovered or over-recovered portion, is then included in the calculation of the next year's PCA. For further discussion of significant rate cases and proceedings see Part II, Item 7 - "MD&A - REGULATORY ISSUES."

Power Supply
IPC meets its system load requirements using a combination of its own generation, mandated purchases from private developers (see "CSPP Purchases" below) and purchases from other utilities and power wholesalers. IPC's generating plants and capacities are listed in Item 2 - "Properties."

IPC's system is dual peaking, with the larger peak demand occurring in the summer. The all-time system peak demand was 2,963 megawatts (MW), on July 12, 2002. Peak summer demand in 2005 was 2,961 MW, set on July 22 and peak winter demand for the year was 2,345 MW on December 15. IPC expects total system average load to grow 2.2 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
		2005	2004	2003	2005	2004	2003
		(thousands of MWhs)
Hydroelectric		6,199	6,041	6,149	46%	45%	47%
Thermal		7,315	7,303	6,914	54%	55%	53%
	Total system generation	13,514	13,344	13,063	100%	100%	100%

The amount of electricity IPC is able to generate from its hydroelectric plants depends on a number of factors, primarily snow pack in the mountains upstream of its hydroelectric facilities, reservoir storage and stream flow conditions. When these factors are favorable, IPC can generate more electricity using its hydroelectric plants.

Continued below normal stream flow conditions in 2005 resulted in a system generation mix of 46 percent hydroelectric and 54 percent thermal. Under normal stream flow conditions, IPC's system generation mix is approximately 55 percent hydroelectric and 45 percent thermal.

Below average stream flow conditions continued for a sixth consecutive year in 2005. Brownlee reservoir 2005 annual inflow was 8.9 million acre-feet (maf), 70 percent of average, and the April through July inflow was 3.6 maf, 57 percent of average. However, the forecast released on February 28, 2006 by the Northwest River Forecast Center indicates that Brownlee inflow for April through July 2006 is expected to total 6.7 maf, or 106 percent of average. Snow pack accumulation for the Snake River Basin was 117 percent of average on February 28, 2006. Storage in selected federal reservoirs upstream of Brownlee as of February 21, 2006 was 105 percent of average, up from 60 percent of average at the end of December 2004. October 1, 2005 storage in these reservoirs, which is considered carryover storage into water year 2006, was 85 percent of average, up from 45 percent of average on October 1, 2004. With approximately one month remaining in the typical snow accumulation period for 2006, conditions have improved from last year.

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

Integrated Resource Plan: The IRP is prepared and filed every two years with both the IPUC and the OPUC. Prior to filing, the IRP requires extensive involvement by IPC, the IPUC Staff and the OPUC Staff, as well as customer, technological and environmental representatives and is the starting point for demonstrating prudence in IPC's resource decisions. The 2004 IRP identified IPC's forecast load and resource situation for the next ten years, analyzed potential supply-side and demand-side options and identified near-term and long-term actions. The two primary goals of the 2004 IRP were to (1) identify sufficient resources to reliably serve the growing demand for energy service within IPC's service area throughout the 10-year planning period and (2) ensure that the portfolio of resources selected balances cost, risk and environmental concerns. In addition, there were two secondary goals: (1) to give equal and balanced treatment to both supply-side resources and demand-side measures and (2) to involve the public in the planning process in a meaningful way. The IPUC accepted the 2004 IRP on April 22, 2005. The OPUC acknowledged the 2004 IRP on June 17, 2005.

Preparation has begun on the 2006 IRP, with the initial meeting of the IRP Advisory Council held on October 20, 2005, and meetings are continuing on a monthly basis. The planning period will change from a 10-year forecast to a 20-year forecast. The 2006 IRP is scheduled to be filed in June 2006.

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

CSPP Purchases: As mandated by the enactment of PURPA and the adoption of avoided cost rates by the IPUC and the OPUC, IPC has entered into contracts for the purchase of energy from a number of private developers. Under these contracts, IPC is required to purchase all of the output from the facilities located inside the IPC service territory. For projects located outside the IPC service territory, IPC is required to purchase the output that IPC has the ability to receive at the facility's requested point of delivery on the IPC system. The IPUC jurisdictional portion of the costs associated with CSPP contracts are fully recovered through the PCA. For IPUC jurisdictional contracts, projects that generate up to ten average MW of energy on a monthly are eligible for IPUC Published Avoided Costs for up to a 20-year contract term. The Published Avoided Cost is a price established by the IPUC and the OPUC to estimate IPC's cost of developing additional generation resources. On August 4, 2005, the IPUC granted a temporary reduction in the eligible project size to 100 KW for intermittent generation resources only. This temporary project size reduction will remain in place until studies are completed which will help the IPUC determine if the Published Avoided Cost should be revised for intermittent generation resources. For OPUC jurisdictional contracts, projects that generate up to ten MW of capacity are eligible for OPUC Published Avoided Costs for up to a 20-year contract term. The OPUC jurisdictional portion of the costs associated with CSPP contracts is recovered through general rate case filings. The Oregon provisions are currently being reviewed in an OPUC proceeding, as discussed in Part II, Item 7 - "MD&A - REGULATORY ISSUES - Public Utility Regulatory Policies Act of 1978." If a PURPA project does not qualify for Published Avoided Costs, then IPC is required to negotiate the terms, prices and conditions with the developer of that project. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the IPC system and must be consistent with other similar energy alternatives.

As of December 31, 2005, IPC had signed agreements to purchase energy from 87 CSPP facilities with contracts ranging from one to 30 years. Of these facilities, 69 were on-line at the end of 2005; the other 18 facilities under contract are due to come on-line in 2006 and 2007. During 2005, IPC purchased 715,209 megawatt hours (MWh) from these projects at a cost of $43 million, resulting in a blended price of 6.1 cents per kilowatt hour.

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

IPC has two firm wholesale power sales contracts and one wholesale contract for load following services. One is a full requirements sales contract with the City of Weiser for approximately 12 MW that will expire in December 2006. The second contract is with the Raft River Electric Cooperative for up to 15 MW. This contract expires in September 2006; however, it can be renewed by Raft River Electric Cooperative on a year-to-year basis for five additional years. When these contracts expire, IPC will either renew them, negotiate an extension or use this power to meet its retail load requirements. The load following contract, with NorthWestern Energy, requires IPC to increase or decrease its generation by up to 30 MW to react to NorthWestern's system load changes. This contract automatically renews annually unless either party chooses to terminate. As long as IPC retains its Hells Canyon Complex operating flexibility, the load following contract is anticipated to be renewed into the foreseeable future.

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

Transmission Services: IPC has a long history of providing wholesale transmission service and provides firm and non-firm wheeling services for several surrounding utilities. IPC's system lies between and is interconnected to the winter-peaking northern and summer-peaking southern regions of the western interconnected power system. This geographic position allows IPC to provide transmission services and reach a broad power sales market.

IPC holds rights-of-way from Midpoint substation in south-central Idaho through eastern Nevada to the Dry Lake area northeast of Las Vegas, Nevada, known as the Southwest Intertie Project (SWIP). In 2004, the Bureau of Land Management granted a five-year extension to begin construction of a proposed 500-kilovolt transmission line within the rights-of-way to December 2009. IPC obtained the rights-of-way to construct a transmission line along this corridor, but no longer plans to build the line. On March 31, 2005, IPC entered into an agreement with White Pine Energy Associates, LLC (White Pine), an affiliate of LS Power Development, LLC, which provides White Pine a three-year exclusive option to purchase the SWIP rights-of-way from IPC. The option may be exercised in part or as a whole and, if fully exercised, will result in a net pre-tax gain to IPC of approximately $6 million.

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

Fuel
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-third interest in Bridger Coal Company, which owns the Jim Bridger mine supplying coal to the Jim Bridger generating plant in Wyoming. The mine, located near the Jim Bridger plant, operates under a long-term sales agreement that provides for delivery of coal over a 51-year period ending in 2024. 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 and unit coal train allow the plant to take advantage of potentially lower-cost coal from other mines for tonnage requirements above established contract minimums.

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

Sierra Pacific Power Company, as operator of the North Valmy Generating Plant (Valmy), has an agreement with Arch Coal Sales Company, Inc. to supply coal to the plant through 2009. IPC is obligated to purchase one-half of the coal, ranging from approximately 515,000 tons to 762,500 tons annually. Sierra Pacific Power Company also has a coal supply contract with Black Butte Coal Company's Black Butte Mine for deliveries from 2006 through 2009. Idaho Power is obligated to purchase one-half of the coal purchased under this agreement, ranging from 450,000 to 600,000 tons annually.

The Boardman generating plant receives coal from the Powder River Basin through annual contracts. Portland General Electric, as operator of the Boardman plant, has an agreement with Buckskin Mining Company to supply all of Boardman's coal requirements for the years 2006 through 2008. IPC is obligated to purchase 10 percent of the coal purchased under this agreement, ranging from 230,000 to 270,000 tons annually.

IPC owns and operates Danskin and Bennett Mountain combustion turbines, which receive gas through the Williams Northwest Pipeline. All gas is purchased as needs are identified for summer peaks or to meet system requirements. The gas is transported under a long-term capacity contract with the Williams Northwest Pipeline and an arrangement with IGI Resources, Inc. The Williams Northwest Pipeline contract, which extends through February 28, 2007, with annual extensions at IPC's sole discretion, is for 24,523 million British thermal units per day from the Sumas, Washington metering point to the Elmore, Idaho metering point. See further discussion in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Utility Operations - Fuel Expense."

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 certain future upstream diversions of water for irrigation and other recognized consumptive uses.

Over time, increased irrigation development and other consumptive diversions have resulted in a reduction in the stream flows available to fulfill IPC's water rights at certain hydroelectric generating facilities. In reaction to these reductions, IPC initiated and continues to pursue a course of action to determine and protect its water rights. As part of this process, IPC and the State of Idaho signed the Swan Falls agreement on October 25, 1984, which provided a level of protection for IPC's hydropower water rights at specified plants by setting minimum stream flows and establishing an administrative process governing the future development of water rights that may affect IPC's hydroelectric generation. In 1987, Congress passed, and the President signed into law, House Bill 519. This legislation permitted implementation of the Swan Falls agreement and further provided that during the remaining term of certain of IPC's project licenses the relationship established by the agreement would not be considered by the FERC as being inconsistent with the terms of IPC's project licenses or imprudent for the purposes of determining rates under Section 205 of the Federal Power Act. The FERC entered an order implementing the legislation on March 25, 1988.

In addition to providing for the protection of IPC's hydroelectric water rights, the Swan Falls agreement contemplated the initiation of a general adjudication of all water uses within the Snake River basin. In 1987, the director of the Idaho Department of Water Resources filed a petition in state district court asking that the court adjudicate all claims to water rights, whether based on state or federal law, within the Snake River basin. The court signed a commencement order initiating the Snake River Basin Adjudication on November 19, 1987. This legal proceeding was authorized by state statute based upon a determination by the Idaho Legislature that the effective management of the waters of the Snake River basin required a comprehensive determination of the nature, extent and priority of all water uses within the basin. The adjudication is proceeding and is expected to continue for at least the next several years. IPC has filed claims to its water rights within the basin and is actively participating in the adjudication in an effect to ensure that its water rights and the operation of its hydroelectric facilities are not adversely impacted.

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

Environmental Regulation
Idaho Power's activities are subject to a broad range of federal, state, regional and local laws and regulations designed to protect, restore and enhance the quality of the environment. Environmental regulation 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. IPC's compliance costs will continue to be significant for the foreseeable future.

Based upon present environmental laws and regulations, IPC estimates its 2006 capital expenditures for environmental matters, excluding Allowance for Funds Used During Construction (AFDC), will total $20 million. Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $17 million, and investments in environmental equipment and facilities at the thermal plants account for $3 million. From 2007 through 2008, environmental-related capital expenditures, excluding AFDC, are estimated to be $35 million. Anticipated expenses related to IPC's hydroelectric facilities account for $24 million, and thermal plant expenses are expected to total $11 million.

IPC anticipates $18 million in annual operating costs for environmental facilities during 2006. Hydroelectric facility expenses account for $12 million of this total, and $6 million is related to thermal plant operating expenses. From 2007 through 2008, total environmental related operating costs are estimated to be $35 million. Expenses related to the hydroelectric facilities are expected to be $23 million, and thermal plant expenses are expected to be $12 million during this period.

Clean Air: The Environmental Protection Agency (EPA) issued SO₂ allowances, as defined in the Clean Air Act amendments of 1990, based on coal consumption during established baseline years. IPC currently has more than a sufficient amount of SO₂ allowances to provide compliance for emissions attributable to IPC at all three of its jointly-owned coal-fired facilities and both of its natural gas-fired facilities. Prior to the sale of 77,000 emission allowances in 2005 and early 2006 discussed in Part II, Item 7 - "MD&A - REGULATORY ISSUES - Emission Allowances," IPC believed that it had approximately 107,000 allowances in excess of the amount needed for Clean Air Act compliance. In addition, IPC has been granted annual allotments of allowances ranging from 15,524 to 28,622 through the year 2035. Allowances necessary for IPC's compliance requirements are up to 14,500 annually. Excess allowances owned by IPC may be held for future use, as they do not contain expiration terms. There is an active marketplace for buying and selling allowances, so that SO₂allowances determined to be excess can be sold to others. For all the foregoing reasons, IPC does not foresee any adverse effects upon its operations with regard to SO₂ emissions at this time.

In March 2005, the EPA issued two new rules limiting emissions from utility boilers, the Clean Air Interstate Rule and the Clean Air Mercury Rule (CAMR). The Clean Air Interstate Rule caps emissions of SO₂ and nitrogen oxides (NO_x) in 28 eastern states and the District of Columbia. The Clean Air Interstate Rule does not impose any restrictions on emissions from any IPC facilities. IPC does not foresee any adverse effects upon its operations with regard to the Clean Air Interstate Rule.

The CAMR will limit mercury emissions from new and existing coal-fired power plants and creates a market-based cap-and-trade program that will permanently cap utility mercury emissions in two phases. Currently, power plants in the United States emit approximately 48 tons of mercury per year. The first phase cap is 38 tons beginning in 2010, with a second phase cap set at 15 tons beginning in 2018. Mercury emission allocations have been set at the state level, but the states have not allocated the allowances to individual utilities. IPC is actively monitoring developments on this issue and advances in control equipment technology. The CAMR is being challenged in court by a number of environmental groups and some states. On October 21, 2005, the EPA granted requests from petitions to reconsider certain aspects of the CAMR. It is anticipated that this rule may require additional emission controls and expenses at IPC's jointly-owned coal-fired facilities, although impacts on future plant operations, operating costs and generating capacity are not known at this time.

Other pending or proposed air regulations or legislation could require IPC and its partners to reduce emissions of SO₂, NO_x and other pollutants at the jointly-owned coal-fired facilities below current levels. These reductions could be required to address regional haze programs, acid rain, mercury emissions regulation and possible re-interpretations and changes to the federal Clean Air Act. Like many other coal-fired facilities in the United States, the Jim Bridger plant has received information requests from the EPA related to the plant's compliance with the New Source Review provisions of the Clean Air Act, which has resulted in discussions with the EPA and state regulatory authorities. IPC may incur significant costs to comply with tighter air emissions requirements in the future. These potential costs are expected to consist primarily of capital expenditures.

In July 1997, the EPA announced the National Ambient Air Quality Standards (NAAQS) for ozone and Particulate Matter (PM) and, in July 1999, the EPA announced regional haze regulations for protection of visibility in national parks and wilderness areas. On May 14, 1999, a federal court ruling blocked implementation of the NAAQS for ozone and PM. In November 2000, the EPA appealed to the U.S. Supreme Court to reconsider that decision. The Supreme Court ruled in favor of the EPA on February 27, 2001. The EPA has promulgated regulations designating areas of the country for attainment/non-attainment with these standards, and IPC's thermal plants are located in areas designated as attainment for both standards. EPA and state efforts to implement the NAAQS are ongoing. On January 17, 2006, the EPA proposed revisions to the PM NAAQS that potentially could make these NAAQS more stringent, and IPC continues to monitor the EPA's revisions. Litigation concerning the EPA's regional haze regulations resulted in two separate court remands of the rule back to the EPA for reconsideration. On June 15, 2005, the EPA issued the Clean Air Visibility Rule (CAVR) to address the first court remand. On July 20, 2005, the EPA proposed revisions to the CAVR to address the second court remand. Although the impacts of the NAAQS for ozone and particulate matter and the regional haze 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 on if and how the regulations are ultimately implemented.

Global Climate Change: Carbon dioxide emissions are the subject of growing discussion and action in the context of global climate change, but such emissions are not currently subject to regulation at the federal level or at the state level where IPC's thermal plants are located. IPC continues to monitor developments concerning global climate change to gauge potential impacts on future operations.

The United States is currently not a party to the Kyoto Protocol to the United Nations Framework Convention on Climate Change (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas emissions at certain levels from 2008 through 2012.

Greenhouse gas emissions are the result of many natural and man-made processes including the combustion of fossil fuels to generate electricity. Carbon dioxide represents the largest quantity of greenhouse gases emitted at IPC's coal and gas generation units. Under median water conditions, the majority of IPC's generation is hydro-based, which has negligible greenhouse gas emissions compared to fossil-based generation.

Although it has not ratified the Protocol, the United States may adopt a national, mandatory greenhouse gas program at some point in the future. At this time, IPC is unable to predict the potential impacts of any future mandatory governmental greenhouse gas legislative or regulatory requirements.

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

IPC agreed in March 1976 to meet certain dissolved oxygen standards at its American Falls hydroelectric generating plant. IPC signed amendments to the agreements relating to the operation of the American Falls Dam and the location of water quality monitoring facilities. The amendments provide more accurate and reliable water quality measurements necessary to maintain water quality standards downstream from IPC's plant during the period from May 15 to October 15 each year.

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

Endangered Species: Several species of fish and Snake River snails living within IPC's operating area are listed as threatened or endangered. IPC continues to review and analyze the effect such designation has on its operations. IPC is cooperating with governmental agencies to resolve issues related to these species. See Part II, Item 7 - "MD&A - REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

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, 2005, the investment in these facilities was $11 million and the annual cost of operation pursuant to FERC License 1971 was $3 million.

Hazardous/Toxic Wastes and Substances: Under the Toxic Substances Control Act, 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 Toxic Substances Control Act for the continued use of equipment containing PCBs. IPC continues to eliminate PCBs as part of its long-term strategy. This program will reduce costs associated with the long-term monitoring of PCB-containing equipment, responding to spills and reporting to the EPA. In 2005, IPC spent approximately $1 million identifying and eliminating PCBs.

Competition
Retail: Electric utilities have historically been recognized as natural monopolies and have operated in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory with an opportunity to earn a regulated rate of return.

Some state regulatory authorities are in the process of changing utility regulations in response to federal and state statutory changes and evolving competitive markets. These statutory changes and conforming regulations may result in increased retail competition. In 1997, the Idaho Legislature appointed a committee to study restructuring of the electric utility industry. The committee has not recommended any restructuring legislation and is not expected to in the foreseeable future. The committee's focus has since shifted from restructuring to general energy issues. In 1999, the Oregon Legislature passed legislation restructuring the electric utility industry, but exempted IPC's service territory.

Wholesale: The 1992 National Energy Policy Act and the FERC's rulemaking activities have established the regulatory framework to open the wholesale energy market to competition. This 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. This act does not, however, permit the FERC to require transmission access to retail customers. Open-access transmission for wholesale customers provides energy suppliers with opportunities to sell and deliver electricity at market-based prices.

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

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

			Years Ended December 31,
			2005			2004		2003
Revenues (thousands of dollars)
	Residential		$	299,488		$	274,313	$	275,920
	Commercial			173,268			164,053		173,820
	Industrial			118,259			111,797		128,620
	Irrigation			76,255			85,672		92,609
		Total general business		667,270			635,835		670,969
	Off-system sales			142,794			121,148		71,573
	Other			27,619			62,526		37,840
		Total	$	837,683	$		819,509	$	780,382

Energy use (thousands of MWh)
	Residential			4,760			4,580		4,427
	Commercial			3,639			3,561		3,511
	Industrial			3,423			3,335		3,206
	Irrigation			1,467			1,763		1,836
		Total general business		13,289			13,239		12,980
	Off-system sales			2,774			2,885		1,830
		Total		16,063			16,124		14,810

IFS:

IFS invests primarily in affordable housing developments, which provide a return principally by reducing federal and state income taxes through tax credits and accelerated tax depreciation benefits. IFS generated tax credits of $20 million, $22 million and $20 million in 2005, 2004 and 2003, respectively. IFS's portfolio also includes historic rehabilitation projects such as the Empire Building in Boise, Idaho. IFS made $5 million in new investments during 2005. Other activity during the year included cash receipts of $1.3 million representing returns of capital which reduced the investment carrying value.

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, 2005, the gross amount of IFS's portfolio equaled $170 million in tax credit investments. These investments cover 49 states, Puerto Rico and the U.S. Virgin Islands. The underlying investments include over 700 individual properties, of which all but three are administered through syndicated funds.

IDACOMM:

In August 2000, IDACORP formed IDACOMM and acquired Velocitus, Inc. (formerly Rocky Mountain Communication, Inc.), a Boise, Idaho-based Internet service provider founded in 1993. In October 2004, IDACORP transferred its ownership of Velocitus to IDACOMM, and in January 2005, Velocitus was merged into IDACOMM.

In June 2004, IDACOMM acquired Sierra Pacific Communications' Nevada metro area network assets. With this acquisition, IDACOMM provides high-speed fiber optic network service to large business enterprises, government organizations, and telephony carrier customers in Boise, Idaho, and Reno and Las Vegas, Nevada. IDACOMM employs dark fiber private networks and lit Ethernet communications over SONET (Sychronous Optical Networking) fiber ring topology to provide the services. During 2005, IDACOMM sold eight strands of fiber inventory within its Las Vegas network to several large customers for $3.9 million.

IDACOMM began offering its Voice over Internet Protocol (VoIP) services in July 2004 to business customers in Boise, Idaho, and expanded these services to Las Vegas, Nevada in February 2005. The company is currently launching a VoIP offering in Reno, Nevada. The company sells, designs, installs, and operates an Internet Protocol voice and data service package to small and medium business enterprises ranging from 5 to 100 phone stations. The service packages include dial-tone, integrated voice and email messaging, and hosted telephony advanced services such as complex call routing and Internet access. These services are offered over its own networks or over T-1 lines leased from the local telephone company.

During 2004 and 2005, IDACOMM explored the commercial viability of BPL, staging equipment trials in Boise, Idaho and in Houston, Texas. In January 2006, the company announced its intention to phase out this endeavor, seeing its economic viability as a longer-term proposition than desirable. While the company will meet all of its current contractual obligations from this effort, it will cease pursuing additional commercial contracts using this emerging technology. As part of the shift in strategy away from additional BPL efforts, the company took a goodwill impairment charge of $10 million. In 2005, IDACOMM also recorded a valuation allowance of $1.6 million against tax assets acquired in 2000 with its acquisition of Velocitus.

ITI:

IdaTech was founded in 1996 as Northwest Power Systems, LLC to develop and bring fuel cell technology to market. In April 1999, ITI, a wholly-owned subsidiary of IDACORP, purchased an interest in IdaTech and now owns over a 90 percent interest.

IdaTech is a developer of proton exchange membrane (PEM) fuel cell systems for critical backup, emergency, remote and portable power applications.

IdaTech's products under development include:

ElectraGen™ - Critical backup systems ranging from 3-5 kW in output and designed to provide backup power in applications such as telecommunications sites.

iGen™ - A 250 watt fuel cell system with on-board fuel reformer providing portable and auxiliary power for remote off-grid locations as well as military and recreational vehicles.

Modular fuel reformers - Fuel reformers convert liquid fuel to hydrogen for use in the ElectraGen™ systems.

Components - Multi-fuel fuel processors, fuel cell stack technology and automated fuel cell systems target longer-term commercial applications in vehicular auxiliary power units and combined heat and power units. For these longer-term market opportunities, IdaTech has joined with German companies Volkswagen, RWE Fuel Cells and Bosch Buderus in product development programs.

Currently, these systems are being evaluated by European utilities and telecommunications companies, Rittal Corp., The U.S. Department of Energy, the U.S. Army Communication Electronics Command and other customers in North America, Europe and Asia.

During 2005, IdaTech expanded its corporate headquarters and in February 2005, opened its first European office in Herten, state of North Rhine Westphalia, Germany, to provide development and technical support to existing customers and facilitate additional growth in the European telecommunications market. A strategic development agreement with Rittal Corp. was signed in March 2005, which will integrate IdaTech's fuel cell systems with Rittal's telecommunications and information technology systems to provide the seamless backup power solutions. In July, the U.S. Army contracted with IdaTech to continue development of and enhance its iGen™ system.

In September 2005, IdaTech received CE Certification of the ElectraGen™ systems, allowing sales and operation of the systems in Europe. Following the certification, IdaTech introduced the ElectraGen™ Extended Run Module and the ElectraGen™3 fuel cell system.

IDA-WEST:

Ida-West operates and has a 50 percent interest in nine hydroelectric plants with a total generating capacity of 45 MW. Four of the projects are located in Idaho and five are in northern California. All nine projects are "qualifying facilities" under PURPA. IPC purchased all of the power generated by Ida-West's four Idaho hydroelectric projects, at a cost of $7 million per year, in 2005, 2004 and 2003.

RESEARCH AND DEVELOPMENT:

IPC:
In 2005, IPC spent approximately $6.5 million to promote energy efficiency and summer peak reduction through its Demand Side Management (DSM) programs. Major funding for program development, implementation and administration comes from the Idaho and Oregon tariff riders for DSM and from the Conservation and Renewable Discount Program of the Bonneville Power Administration.

A portion of these programs covers research and development, technology evaluation and market transformation, through promotion and collaboration with manufacturers of electricity consuming products, including air conditioning equipment, appliances, building components and control equipment. These programs represent approximately nine percent of the total spending.

Energy efficiency programs target savings across the entire year for a wide range of customer segments with an emphasis on reducing energy during the summer peak:

Approximately one-third of the 2005 expenses were devoted to achieving summer peak reduction through focusing on irrigation pumping and residential air conditioning equipment control measures.

The residential programs target new and existing homes, focusing on customer education and the application of energy efficiency remediation, including energy efficient building techniques, insulation augmentation, air duct sealing, and the use of efficient lighting. The segment's 2005 spending represented about 33 percent of the total.

Energy efficiency programs for existing industrial and new commercial facilities focus on application of energy efficient techniques and technologies as well as operational and management processes to reduce energy consumption. These programs represent approximately 22 percent of total expenses.

IdaTech:
In 2005, IdaTech spent $8.6 million for research and development of fuel cell technology. IdaTech's research and development program is focused on the adaptation of its fuel processor technology to operate on all commercially important fuels, as well as the continued development of fully integrated fuel cell systems.

IdaTech continues to pursue patent protection in the Americas, Europe, and Asia. The patents issued to IdaTech address the design and operation of fuel reformers, the design and materials of construction used in IdaTech's two stage hydrogen purification devices based on the HyPurium™ membranes used to filter out impurities in the product hydrogen, fuel cell system automated control and operation; integrated heat recovery from fuel cell systems and automated control of integrated pressure-swing absorption for efficient and reliable operation. Currently, 43 U.S. patents lasting 20 years and 62 foreign patents have been issued or allowed to IdaTech. These patents expire from 2016 to 2026. IdaTech also has approximately 200 pending domestic and foreign patent applications addressing aspects of (1) fuel processor system design, operation, materials and integration; (2) membrane purification, materials and design; and (3) fuel cell system operation, thermal recovery, design, remote control and diagnostics. These patents will continue to help IdaTech bring its backup and remote fuel cell solutions to market. The patents also provide the potential for licensing of IdaTech's technology in the future.

ITEM 1A. RISK FACTORS

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

Reduced hydroelectric generation can reduce revenues and increase costs. Idaho Power Company has a predominately hydroelectric generating base. Because of Idaho Power Company's heavy reliance on hydroelectric generation, the weather can significantly affect its operations. Idaho Power Company experienced its sixth consecutive year of below normal water conditions in 2005. When hydroelectric generation is reduced, Idaho Power Company must increase its use of more expensive thermal generating resources and purchased power. Through its power cost adjustment in Idaho, Idaho Power Company can expect to recover approximately 90 percent of the increase in its Idaho jurisdictional net power supply costs, which are fuel and purchased power less off-system sales, above the level included in its base rates. The power cost adjustment recovery includes both a forecast and deferrals that are subject to the regulatory process. However, recovery of amounts above forecast in one power cost adjustment year does not occur until the subsequent power cost adjustment year. The non-Idaho net power supply costs are subject to periodic recovery from the Oregon and Federal Energy Regulatory Commission jurisdictional customers.

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

Changes in temperature and precipitation can reduce power sales and revenues. Warmer than normal winters, cooler than normal summers and increased rainfall during the irrigation seasons will reduce retail revenues from power sales.

If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission grant less rate relief than requested in rate case filings, it will reduce Idaho Power Company's earnings and cash flows. If the Idaho Public Utilities Commission, the Oregon Public Utility Commission or the Federal Energy Regulatory Commission were to grant less rate relief than Idaho Power Company requests in its rate case filings, it could have a negative effect on earnings and cash flow and result in future downgrades of IDACORP, Inc.'s and Idaho Power Company's credit ratings.

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

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

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

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

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. If Idaho Power Company does not receive timely regulatory relief, Idaho Power Company will have to rely more on external financing for its planned utility construction expenditures from 2006 through 2008; these large planned expenditures may weaken the consolidated financial profile of Idaho Power Company and IDACORP, Inc. Additionally, a significant portion of Idaho Power Company's facilities were constructed many years ago. Aging equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures. Failure of equipment or facilities used in Idaho Power Company's systems could potentially increase repair and maintenance expenses, purchased power expenses and capital expenditures.

If losses at the non-regulated subsidiaries continue and if they are unable to obtain financing, this may reduce IDACORP, Inc.'s earnings and cash flow. IdaTech and IDACOMM have experienced operating losses and it is not certain that they will achieve or sustain profitability in the future. If these non-regulated subsidiaries do not achieve profitability or are unable to obtain financing to fund their operations, this could increase the need for IDACORP, Inc. to provide liquidity in the form of capital contributions or loans and/or increase the need for IDACORP to pursue other strategic alternatives including possible sale, merger or dissolution. Any of these actions could have a negative impact on IDACORP, Inc.'s earnings and cash flows. In addition, if the value of these subsidiaries declines, IDACORP, Inc. may need to evaluate for possible asset impairment charges.

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

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

Adverse results of income tax audits could reduce earnings and cash flows. In March 2005, the Internal Revenue Service began its examination of IDACORP's 2001 through 2003 tax years. On October 24, 2005, the Idaho State Tax Commission also began its examination of the same tax years. Outcome of the audits could differ materially from the amounts currently recorded, and the difference could reduce IDACORP's and Idaho Power Company's earnings and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

IPC's generation system includes 17 hydroelectric generation developments located in Idaho and Oregon, two natural gas-fired plants and one diesel-powered generator located in Idaho, and interests in three coal-fired generating plants in Wyoming, Oregon and Nevada. IPC acquired the second gas-fired plant, Bennett Mountain Power Plant, on March 31, 2005. The system also includes approximately 4,691 miles of high voltage transmission lines, 24 step-up transmission substations located at power plants, 20 transmission substations, nine transmission switching stations and 219 energized distribution substations (excluding mobile substations and dispatch centers).

IPC holds FERC licenses for 12 of its hydroelectric projects. These projects and the other generating stations and their capacities are listed below:

						Estimated
						Non-Coincident	Nameplate
						Maximum Operating	Capacity	License
Project						Capacity (kW)	(kW)	Expiration
Hydroelectric Developments:
		Properties subject to federal licenses:
				Lower Salmon		70,000	60,000		2034
				Bliss		80,000	75,000		2034
				Upper Salmon		39,000	34,500		2034
				Shoshone Falls		12,500	12,500		2034
				CJ Strike		89,000	82,800		2034
				Upper Malad - Lower Malad		24,000	21,770		2035
				Brownlee-Oxbow-Hells Canyon		1,398,000	1,166,900		2005	(a)
				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:
				Clear Lakes - Thousand Springs		10,400	11,300
				Total Hydroelectric			1,706,715
Steam and Other Generating Plants:
				Jim Bridger (coal-fired) (b)		706,667	770,501
				Valmy (coal-fired) (b)		260,650	283,500
				Boardman (coal-fired) (b)		58,500	56,050
				Danskin (gas-fired)(c)		76,000	90,000
				Salmon (diesel-internal combustion)		5,500	5,000
				Bennett Mountain (gas-fired)(c)		164,000	172,800
					Total Steam and Other		1,377,851
					Total Generation		3,084,566
(a) Licensed on an annual basis while application for new multi-year license is pending.
(b) IPC's ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman Amounts shown represent
			IPC's share.
(c) Maximum operating capacity is based on summer rating at 90 degrees F.

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

At December 31, 2005, the composite average ages of the principal parts of IPC's system, based on dollar investment, were production plant, 24 years; transmission system and substations, 23 years; and distribution lines and substations, 19 years. IPC considers its properties to be well-maintained and in good operating condition.

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

Idaho Energy Resources Co. owns a one-third interest in the Bridger Coal Company and coal leases near the Jim Bridger generating plant in Wyoming from which coal is mined and supplied to the plant.

Ida-West holds 50 percent interests in nine operating hydroelectric plants with a total generating capacity of 45 MW. These plants are located in Idaho and California.

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

ITEM 3. LEGAL PROCEEDINGS

See Note 8 of IDACORP's and IPC's Consolidated Financial Statements.

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

None

EXECUTIVE OFFICERS OF THE REGISTRANT

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

JAN B. PACKWOOD President and Chief Executive Officer of IDACORP, Inc., appointed May 30, 1999. Mr. Packwood was Chief Executive Officer of Idaho Power Company from March 1, 2002 to November 17, 2005. Mr. Packwood was President and Chief Executive Officer of Idaho Power Company from May 30, 1999 to March 1, 2002. Mr. Packwood also serves on the Board of Directors of both IDACORP, Inc. and Idaho Power Company. Age 62

J. LAMONT KEEN Executive Vice President of IDACORP, Inc., appointed March 1, 2002. Mr. Keen also serves as President and Chief Executive Officer of Idaho Power Company, appointed November 17, 2005. Mr. Keen was President and Chief Operating Officer of Idaho Power Company from March 1, 2002 to November 17, 2005. Mr. Keen was Senior Vice President - Administration and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company from May 5, 1999 to March 1, 2002. Mr. Keen also serves on the Board of Directors of both IDACORP, Inc. and Idaho Power Company. Age 53

DARREL T. ANDERSON Senior Vice President - Administrative Services and Chief Financial Officer of IDACORP, Inc. and Idaho Power Company, appointed July 1, 2004. Mr. Anderson was Vice President, Chief Financial Officer and Treasurer of IDACORP, Inc. and Idaho Power Company from March 1, 2002 to July 1, 2004 and Vice President - Finance and Treasurer of IDACORP, Inc. and Idaho Power Company from May 5, 1999 to March 1, 2002. Age 47

THOMAS R. SALDIN Senior Vice President, General Counsel and Secretary of IDACORP, Inc. and Idaho Power Company, appointed October 1, 2004. Mr. Saldin was Executive Vice President and General Counsel of Albertson's Inc., a supermarket chain, from January 29, 1999 to his retirement on August 31, 2001. Age 59

DENNIS C. GRIBBLE Vice President and Treasurer of IDACORP, Inc. and Idaho Power Company, appointed July 15, 2004. Mr. Gribble was Finance Controller of Idaho Power Company from January 1, 1997 to July 15, 2004. Age 53

A. BRYAN KEARNEY Vice President and Chief Information Officer of IDACORP, Inc. and Idaho Power Company, appointed March 15, 2001. Mr. Kearney has been the Vice President and Chief Information Officer of Idaho Power Company since November 18, 1999. Age 43

LUCI K. MCDONALD Vice President - Human Resources of IDACORP, Inc. and Idaho Power Company, appointed December 6, 2004. Ms. McDonald was Corporate Staff Director of Human Resources of Boise Cascade Corporation, a forest products company, from September 16, 1999 to November 19, 2004. Age 48

GREGORY W. PANTER Vice President - Public Affairs of IDACORP, Inc. and Idaho Power Company, appointed April 1, 2001. Mr. Panter was self-employed with Greg Panter Consulting, a lobbying/government affairs business, from July 1, 1999 to April 1, 2001. Age 57

LORI D. SMITH Vice President - Finance and Chief Risk Officer of IDACORP, Inc. and Idaho Power Company, appointed July 15, 2004. Ms. Smith was Director of Strategic Analysis of Idaho Power Company from January 1, 2000 to July 15, 2004. Age 45

PART II

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

IDACORP's common stock, without par value, is traded on the New York Stock Exchange. On December 31, 2005, there were 17,016 holders of record and the stock price was $29.30 per share.

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

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

A covenant under the IDACORP and IPC Credit Facilities described in "MD&A - LIQUIDITY AND CAPITAL RESOURCES - Financing Programs - Credit Facilities" requires IDACORP and IPC to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization of no more than 65 percent at the end of each fiscal quarter. IPC's ability to pay dividends on its common stock held by IDACORP and IDACORP's ability to pay dividends on its common stock are limited to the extent payment of such dividends would cause their leverage ratios to exceed 65 percent. At December 31, 2005, the leverage ratios for IDACORP and IPC were 51 and 52 percent, respectively.

IPC's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears. IPC has no preferred stock outstanding. IPC paid dividends toIDACORP of $51 million, $46 million and $65 million in 2005, 2004 and 2003, respectively.

The following table shows the reported high and low sales price of IDACORP's common stock and dividends paid for 2005 and 2004 as reported in the consolidated transaction reporting system.

		2005 Quarters
Common Stock, without par value:		1^st	2^nd	3^rd	4^th
	High	$30.64	$30.80	$32.05	$31.09
	Low	27.32	26.22	28.75	27.46
	Dividends paid per share	30.0	30.0	30.0	30.0

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

Issuer Purchases of Equity Securities:

IDACORP, Inc. Common Stock				(c) Total Number	(d) Maximum
				Purchased of	Number (or
	(a) Total			Shares as Part of	Approximate Value
	Number	(b) Average		Publicly	of Shares that May
	of Shares	Price Paid		Announced	Yet Be Purchased Under
Period	Purchased	per Share		Plans or Programs	the Plans or Programs
October 1 - October 31, 2005	-	$	-
November 1 - November 30, 2005	-		-
December 1 - December 31, 2005	82(1)		29.54
Total	82	$	29.54
(1) These shares were withheld for taxes upon vesting of restricted stock.

ITEM 6. SELECTED FINANCIAL DATA

IDACORP, Inc.
SUMMARY OF OPERATIONS
(thousands of dollars except per share amounts)
		2005		2004		2003		2002		2001
Operating Revenues		$	859,488	$	844,491	$	823,002	$	928,800	$	1,275,312
Operating income			127,749		93,251		84,062		75,640		242,289
Net income			63,661		72,983		46,578		61,672		125,214
Earnings per diluted share			1.50		1.90		1.22		1.63		3.35
Dividends declared per share			1.20		1.20		1.70		1.86		1.86

Financial Condition:
Total assets		$	3,364,126	$	3,234,172	$	3,106,108	$	3,387,168	$	3,769,992
Long-term debt			1,039,887		1,058,152		1,013,757		988,268		879,048

Financial Statistics:
Times interest charges earned:
	Before tax		2.27		1.83		1.37		1.16		3.52
	After tax		2.06		2.25		1.68		1.93		2.66
Market-to-book ratio			121%		128%		132%		108%		175%
Payout ratio			79%		63%		139%		114%		56%
Return on year-end common equity			6.2%		7.2%		5.4%		7.1%		14.4%
Book value per share		$	24.17	$	23.88	$	22.61	$	22.98	$	23.21

See Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS" for a discussion of the factors that affect comparability.
The above data should be read in conjunction with IDACORP's and IPC's Consolidated Financial Statements including
the Notes to the Consolidated Financial Statements.

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

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

INTRODUCTION:

In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, IPC) are discussed.

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is IPC. Due to the repeal of the Public Utility Holding Company Act of 1935 (1935 Act), effective February 8, 2006, IDACORP is no longer subject to any provisions under the 1935 Act. IDACORP is a holding company under the newly enacted Public Utility Holding Company Act of 2005 (2005 Act), which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.

IPC is an electric utility with a service territory covering approximately 24,000 square miles 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 subsidiaries include:

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

IdaTech, LLC (IdaTech) - developer of integrated fuel cell systems, over 90 percent-owned by IDACORP's wholly-owned subsidiary IDACORP Technologies, Inc. (ITI);

IDACOMM, Inc. (IDACOMM) - provider of telecommunications services and commercial Internet services;

IDACORP Energy (IE), - marketer of electricity and natural gas, which wound down its operations in 2003.

While reading the MD&A, please refer to the Consolidated Financial Statements of IDACORP and IPC, which present the financial position at December 31, 2005 and 2004, and the results of operations and cash flows for each company for the years ended December 31, 2005, 2004 and 2003.

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, 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," "may result," "may 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 IDACORP's or IPC's control and may cause actual results to differ materially from those contained in forward-looking statements:

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

Changes arising from the recently enacted Energy Policy Act of 2005;

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

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

Weather variations affecting hydroelectric generating conditions and customer energy usage;

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

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

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

Impacts from the potential formation of a regional transmission organization;

Population growth rates and demographic patterns;

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

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

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

Actions by credit rating agencies, including changes in rating criteria and new interpretations of existing criteria;

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

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

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

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

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

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

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

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

Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

EXECUTIVE OVERVIEW:

2005 Financial Results
IDACORP's net income in 2005 was $64 million compared to $73 million in 2004. Diluted earnings per share (EPS) for the year of $1.50 was a $0.40 per share decrease from 2004's results of $1.90 per share.

The key components of the change in annual IDACORP net income are:

IPC's earnings increased to $72 million, a $6 million increase over last year. This increase resulted primarily from improved operating margins resulting from the implementation of general rate increases in June of both years. IPC set a record for annual general business customer growth with a gain of 16,737 customers to 457,146. This represents a 3.8 percent increase year-over-year.

IDACOMM lost $13 million in 2005 compared to a $2 million loss in 2004. In the fourth quarter of 2005, IDACOMM recorded a $10 million goodwill impairment, which resulted principally from a revision to the company's business strategy and decision to phase out the broadband-over-powerline (BPL) portion of its business.

Net loss at ITI increased from $6 million to $9 million as IdaTech accelerates in its product development phase. The increase results from a $3 million reduction in sales of products in development, and a $2 million increase in product development costs.

Earnings at IE increased from $2 million in 2004 to $5 million in 2005, due primarily to a $9.5 million reduction in the allowance for uncollectible accounts due from California parties in the California refund proceeding. This adjustment was based on management's assessment of negotiations to settle the legal actions surrounding transactions in the California markets in 2000 and 2001. On February 17, 2006, IE and IPC jointly filed with several California parties an Offer of Settlement at the FERC. Final comments on the settlement are due to be filed by March 20, 2006, after which the FERC will determine whether to approve the settlement. This matter is discussed in more detail in "Legal Matters." In 2004, IE had recorded $4 million of gains on settlement of legal disputes.

In 2005, IFS contributed $2 million less to earnings than in the prior year. In 2004, IFS recorded a $2 million gain on the sale of its investment in the El Cortez Hotel in San Diego, California.

Per share amounts in 2005 were also affected by the issuance of approximately four million shares of IDACORP common stock in December 2004.

Business Strategy
IDACORP is focusing on a back-to-basics strategy that emphasizes IPC as IDACORP's core business. IPC continues to experience strong customer growth in its service area, and this corporate strategy recognizes that IPC must make substantial investments in infrastructure to ensure adequate supply and reliable service. IFS, with its affordable housing and historic rehabilitation portfolio, remains a key component of the corporate strategy.

The strategy includes seeking timely rate relief in both the Idaho and Oregon jurisdictions. IPC plans to file in Idaho and Oregon for either asset-specific or general rate relief regularly in upcoming years. In 2005, IPC received approval from the IPUC of a rate request related to costs incurred in connection with the construction of the Bennett Mountain Power Plant. IPC also filed an Idaho general rate case in the fall; a proposed settlement of this case was filed for IPUC approval in February 2006.

IDACORP is reviewing strategic alternatives for IdaTech's fuel cell business, including its possible sale or merger in an effort to minimize the financial impact on IDACORP. IdaTech is transitioning from developmental projects to commercial products.

Regulatory Matters:
Idaho general rate case: IPC filed a general rate case in October 2005, requesting the IPUC to approve an annual increase to its Idaho retail base rates of $44 million or 7.8 percent. Base rates primarily reflect IPC's cost of providing electrical service to its customers, including equipment, vehicles and infrastructure.

On February 27, 2006, IPC, the IPUC staff and representatives of customer groups filed a proposed stipulation with the IPUC that, if approved, would settle this case. The stipulation calls for an $18.1 million increase, or 3.2 percent in IPC's annual electric rates. If approved by the IPUC, the changes in rates are expected to become effective on June 1, 2006.

The rate case filing was made with six months of actual operating expenses and six months of projected expenses. The agreed to increase in rates was lower than the requested amount primarily due to three factors: (1) 2005 actual numbers were significantly less than those forecasted; (2) the overall rate of return agreed to was 8.1 percent compared to the 8.42 percent IPC requested (no specific return on equity was determined); and (3) net power supply costs were kept at levels currently existing in rates. As a result of the settlement, IPC's overall rate of return will increase from the 7.85 percent currently authorized.

Emission allowances: During the fourth quarter of 2005, IPC sold 69,500 excess sulfur dioxide (SO₂) emission allowances (out of a total of approximately 107,000 excess allowances) on the open market for approximately $71 million. Through February 28, 2006, IPC has sold an additional 7,500 emission allowances for approximately $10 million and plans to continue selling surplus allowances as market conditions permit. IPC is now seeking an order from the IPUC to determine the accounting treatment for these transactions and the allocation of proceeds between retail customers and shareholders. Under the approved interim accounting treatment, IPC is recording the Idaho and Oregon allocated portions of the proceeds (net of expenses) as a regulatory liability. At this time, IPC cannot predict how the proceeds might ultimately be allocated.

Shareholder Lawsuits:
In connection with the shareholder lawsuits filed against IDACORP and four of its officers and directors in 2004, on September 14, 2005, Magistrate Judge Mikel H. Williams of the U.S. District Court for the District of Idaho issued a Report and Recommendation that the defendants' motion to dismiss be granted and that the case be dismissed. The Magistrate Judge determined that the plaintiffs did not satisfactorily plead loss causation (i.e., a causal connection between the alleged material misrepresentation and the loss) in conformance with the standards set forth in the recent United States Supreme Court decision of Dura Pharmaceuticals, Inc. v. Broudo, 544 U.S._____, 125 S. Ct. 1627 (2005). The Magistrate Judge also concluded that it would be futile to afford the plaintiffs an opportunity to file an amended complaint because it did not appear that they could cure the deficiencies in their pleadings. The parties have each filed objections to different parts of the Magistrate Judge's Report and Recommendation, and the matter is now before the District Judge.

Capital Requirements and Cash Flows: IPC estimates that it will spend $720 million on construction expenditures over the next three years. This amount reflects the need for additional resources in order for IPC to supply power to its growing number of customers.

Forecasts indicate that internal cash generation after dividends will provide less than the full amount of total capital requirements for 2006 through 2008. IDACORP and IPC expect to continue financing the utility construction program and other capital requirements with internally generated funds and continued reliance on externally financed capital.

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.

Idaho Water Management Issues: Six years of below normal water conditions have exacerbated a developing water shortage in the state of Idaho, which is manifested by a number of water issues including declining Snake River base flows and declining levels in the Eastern Snake Plain Aquifer. These issues are of interest to IPC because of their potential impacts on generation at IPC's hydroelectric projects. As a result of declines in river flows, in 2003 several surface water users filed delivery calls with the Idaho Department of Water Resources, demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the aquifer and affecting flows to senior surface water rights. These delivery calls have resulted in the several administrative actions before the Idaho Department of Water Resources and judicial actions before the State District Court in Ada and Gooding Counties in Idaho challenging the constitutionality of state regulations used by the Department to conjunctively administer ground and surface water rights. IPC is participating in several of these actions to protect its interests and encourage the development of a long-term management plan that will protect the aquifer from further depletion.

One management option being explored is aquifer recharge, or using surface water supplies to increase ground water supplies by allowing the water to percolate into the aquifer in porous locations. Under certain circumstances aquifer recharge may impact senior water rights, including water rights held by IPC for hydropower purposes, and therefore conflict with state law. For that reason, IPC continues to participate in the processes that are considering solutions, such as aquifer recharge, to the conflict between ground and surface water interests in an effort to protect its existing hydroelectric generation water rights. In February 2006, at the request of senior surface water interests, IPC entered into discussions with the State of Idaho and senior surface water interests to explore opportunities for engaging in some limited aquifer recharge in 2006, provided any adverse impact to IPC's hydropower generation and its customers is adequately addressed. These discussions continue and are expected to reach conclusion by mid-March or early April 2006.

Relicensing: IPC's most significant ongoing relicensing effort is the Hells Canyon Complex, which provides approximately two-thirds of IPC's hydroelectric generating capacity and approximately 40 percent of its total generating capacity. Over the past year, IPC has participated in negotiations with a number of interested parties in an attempt to develop a comprehensive agreement for relicensing the Hells Canyon Complex. To date, however, the parties have not been successful in reaching an agreement. Because it was unlikely that the parties to the settlement process would reach an agreement on a comprehensive settlement package in the near term and with the issuance of the Notice of Ready for Environmental Analysis (NREA) by the FERC in October 2005, the settlement discussions were terminated to allow the parties the opportunity to develop comments and preliminary terms and conditions for filing with the FERC. The parties expect to reassess opportunities for settlement in the spring of 2006 after the filings with the FERC.

Energy Policy Act of 2005: On August 8, 2005, the President signed into law the Energy Policy Act of 2005 (Energy Act), which is a comprehensive energy bill affecting the regulation of energy companies, including IPC. Key provisions of the Energy Act that may affect IPC include:

Creation of an electric reliability organization that the FERC will appoint and oversee to establish and enforce mandatory reliability rules regarding the interstate electric transmission system;

Requirements for the FERC to establish incentive-based transmission rate policies;

FERC backstop authority for transmission line siting in corridors of national interest;

Changes in authority over regional transmission organizations;

Amendments to PURPA, prospectively terminating mandatory purchase and sale requirements when a qualifying facility has access to competitive markets and eliminating the prohibition against utility ownership of qualifying facilities;

Reform of the hydroelectric licensing process to provide trial-type hearings for disputed facts regarding license conditions, to create a process for licensees to propose alternatives to prescribed conditions and to require prescribing authorities to balance competing interests;

Incentives to develop additional generation at existing hydroelectric dams;

Creation of significant tax incentives to encourage and promote electricity reliability, renewable and clean energy investment and clean coal, and other energy efficiency and conservation; and

Repeal of the 1935 Act and amendments to the Federal Power Act (FPA), effective February 8, 2006, giving the FERC (i) increased authority over mergers involving public utilities and the acquisition of the securities of electric utility companies and holding companies, (ii) authority to protect public utilities from cross subsidization and the encumbrance of utility assets, (iii) authority to set cost allocation methods for affiliate transactions involving public utilities, and (iv) providing the FERC and state commissions increased access to the books and records of holding company systems.

Implementation of the Energy Act requires the development of regulations by the FERC, the Department of Energy and other federal agencies as well as proceedings at the state level. The FERC has adopted numerous new rules and regulations, including new rules relating to utility acquisitions and dispositions, books and records access, electric utility reliability and reliability organizations, and procedures for determining conditions or proscriptions on hydropower licenses. The FERC also has issued proposed rules that are still undergoing review and comment.

IDACORP and IPC are currently monitoring the Energy Act's implementation to determine its effects on the companies.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES:

IDACORP's and IPC's discussion and analysis of their financial condition and results of operations are based upon their consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of these financial statements requires IDACORP and IPC to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, IDACORP and IPC evaluate these estimates, including those related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, unbilled revenues and bad debt. These estimates are based on historical experience and on 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 jurisdictions regulating IPC. The primary effect of this policy is that IPC has recorded $418 million of regulatory assets and $345 million of regulatory liabilities at December 31, 2005. While IPC expects to fully recover these regulatory assets and return these regulatory liabilities, such recovery is subject to final review by the regulatory entities.

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

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

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

The assumed discount rate is based on reviews of market yields on high-quality corporate debt. Specifically, IDACORP and IPC utilize data published in the Citigroup Pension Liability Index and apply the rates therein against the projected cash outflows of the plans. The discount rate used to calculate the 2006 pension expense will be reduced to 5.60 percent from the 5.75 percent used in 2005.

Rate-of-return projections for plan assets are based on historical risk/return relationships among asset classes. The primary measure is the historical risk premium each asset class has delivered versus the return on 10-year US Treasury Notes. This historical risk premium is then added to the current yield on 10-year US Treasury Notes, and the result provides a reasonable prediction of future investment performance. Additional analysis is performed to measure the expected range of returns, as well as worst-case and best-case scenarios. Based on the current low interest rate environment, current rate-of-return expectations are lower than the nominal returns generated over the past 20 years when interest rates were generally much higher.

Pension expense for these plans totaled $10 million, $10 million, and $12 million for the three years ended December 31, 2005, 2004 and 2003, respectively, including amounts allocated to capitalized labor costs. For 2006, pension expense is expected to total approximately $12 million, which takes into account the reduction of the discount rate noted above. 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
	2006		2005		2006		2005
	(millions of dollars)
Effect of 0.5% increase	$	(1.7)	$	(1.2)	$	(1.8)	$	(1.7)
Effect of 0.5% decrease		3.8		2.7		1.8		1.7

No cash contributions were made to the qualified plan in 2003 through 2005, and none are expected in 2006. Under the non-qualified plan, IPC makes payments directly to participants in the plan. Payments averaged approximately $2.5 million per year from 2003 to 2005, and a similar amount is anticipated in 2006.

Please refer to Note 10 of IDACORP's and IPC'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 is charged to income if (a) it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements and (b) the amount of the loss can be reasonably estimated. Disclosure in the notes to the financial statements is required for loss contingencies not meeting both conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until realized.

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

Asset Impairment
IDACORP has several assets that are evaluated for impairment in accordance with generally accepted accounting principles. Those assets that were evaluated in 2005 include the following:

Goodwill: At December 31, 2005, IDACORP had $3 million of goodwill related to its investments in IdaTech. In 2005, IDACORP recorded an impairment of the entire $10 million goodwill balance related to its investment in IDACOMM.

IDACORP follows the impairment testing provisions of SFAS 142, "Goodwill and Other Intangible Assets." In accordance with 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 annual impairment tests were conducted as of June 30, and at that time no impairment was noted. The strategic decision made in December 2005 to exit one of IDACOMM's lines of business, BPL, triggered the requirement to conduct another impairment test. Based on the results of that test, IDACOMM's goodwill balance was impaired.

The fair value calculations used for these tests require IDACORP to make assumptions about items that are inherently uncertain. Assumptions related to future market demand, market prices and product costs could vary from actual results, and the impact of such variations could be material. Factors that could affect the assumptions include changes in economic conditions, success in developing marketable products and services and competitive conditions in the telecommunications and fuel cell industries.

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

Southwest Intertie Project: IPC began developing the Southwest Intertie Project (SWIP) in 1988. IPC's investment consists predominantly of a federal permit for a specific transmission corridor in Nevada and Idaho and also private rights-of-way in Idaho. The SWIP rights-of-way extend from Midpoint substation in south-central Idaho through eastern Nevada to the Dry Lake area northeast of Las Vegas, Nevada. In 2004 the Bureau of Land Management granted a five-year extension to begin construction of a proposed 500kV transmission line within the rights-of-way before December 2009. On March 31, 2005 IPC entered into an agreement with White Pine Energy Associates, LLC (White Pine), an affiliate of LS Power Development, LLC, which provides White Pine a three-year exclusive option to purchase the SWIP rights-of-way from IPC. The option may be exercised in part or as a whole and, if fully exercised, will result in a net pre-tax gain to IPC of approximately $6 million. Based on management expectations regarding SWIP, no impairment has been identified.

Investments:IFS has affordable housing and other investments with a net book value of $100 million at December 31, 2005, and Ida-West has investments in four joint ventures that own electric power generation facilities. Except for two investments now consolidated under the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) 46R, "Consolidation of Variable Interest Entities - an interpretation of ARB No. 51," these investments are accounted for under the equity method of accounting as described in Accounting Principles Board Opinion No. (APB) 18, "The Equity Method of Accounting for Investments in Common Stock." The standard for determining whether impairment must be recorded under APB 18 is whether the investment has experienced a loss in value that is considered an other-than-temporary decline in value.

Prior to the decision to discontinue Ida-West's project development activities, Ida-West had the intent and ability to hold the investments for a period sufficient to recover the recorded value. Based upon the change in management's intent, these investments were tested for impairment, and two of the investments were determined to be impaired, resulting in a write down of $2 million in 2003. The impairment amounts are based on the estimated fair value of the investments. Impairment tests on these investments were performed in 2005 and no impairment was noted.

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

Unbilled Revenue
IPC's retail revenues include an estimate of MWhs delivered but unbilled at the end of each period. Unbilled revenues are dependent upon a number of factors that require management's judgment. Unbilled revenue is calculated by taking daily estimates of MWhs delivered and applying information from the meter-reading schedule to estimate the portion of MWhs delivered that have not been billed. These unbilled MWhs are then allocated to the retail customer classes based on estimated usage by each class. IPC then records revenue for each customer class based on their respective rates. Due to the seasonal fluctuations of IPC's actual load, the amount of unbilled revenue increases during the summer and winter months and decreases during the spring and fall.

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 2005 are compared to 2004 and the results of 2004 are compared to 2003.

The following table presents earnings for IDACORP's segments as well as for the holding company:

		2005		2004		2003
IPC - Utility operations		$	71,839	$	65,785	$	55,161
IDACORP Financial Services			10,911		13,313		10,404
IDACOMM			(12,988)		(1,990)		(1,794)
ITI			(9,067)		(5,808)		(1,360)
IDACORP Energy			4,881		2,162		(9,563)
Ida-West Energy			2,381		3,089		(4,995)
Holding company expenses			(4,296)		(3,568)		(1,275)
	Total Earnings	$	63,661	$	72,983	$	46,578

Average outstanding shares (000s)			42,279		38,361		38,228
Earnings per diluted share		$	1.50	$	1.90	$	1.22

Utility Operations
Operating environment: IPC 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 weather conditions. The availability of hydroelectric power depends on the amount of snow pack in the mountains upstream of IPC's hydroelectric facilities, springtime snow pack run-off, rainfall and other weather and stream flow management considerations. During low water years, when stream flows into IPC's hydroelectric projects are reduced, IPC's hydroelectric generation is reduced. This results in less generation from IPC's resource portfolio (hydroelectric, coal-fired and gas-fired) available for off-system sales and, most likely, an increased use of purchased power to meet load requirements. Both of these situations - a reduction in profitable off-system sales and an increased use of more expensive purchased power - result in increased power supply costs.

On a frequent basis, an operations plan is developed to provide guidance for generation resource utilization and energy market activities (off-system sales and power purchases). The plan incorporates forecasts for generation unit availability, reservoir storage and stream flows, gas and coal prices, customer loads, energy market prices and other pertinent inputs. Consideration is given to when to use IPC's available resources to meet forecast loads and when to transact in the energy market. The allocation of hydroelectric generation between heavy load and light load hours or various calendar periods is considered in development of the operating plan. This allocation is intended to utilize the flexibility of the hydroelectric system to shift generation to high value periods, while operating within the constraints imposed on the system. IPC's energy risk management policy, unit operating requirements and other obligations provide the framework for the plan.

In 2005, IPC experienced its sixth consecutive year of below normal hydroelectric generating conditions. The National Weather Service Northwest River Forecast Center reports that April through July inflow to Brownlee Reservoir for 2005 totaled 3.6 million acre-feet (maf), which is 57 percent of average. The annual Brownlee inflow for 2005 was 8.9 maf, which the River Forecast Center reports is 70 percent of average. However, the forecast released on February 28, 2006, by the Northwest River Forecast Center indicates that Brownlee inflow for April through July 2006 is expected to total 6.7 maf, or 106 percent of average. Snow pack accumulation for the Snake River Basin was 117 percent of average on February 28, 2006. Storage in selected federal reservoirs upstream of Brownlee as of February 21, 2006 was 105 percent of average, up from 60 percent of average at the end of December 2004. October 1, 2005 storage in these reservoirs, which is considered carryover storage into water year 2006, was 85 percent of average, up from 45 percent of average on October 1, 2004. With approximately one month remaining in the typical snow accumulation period for 2006, conditions have improved from last year.

IPC's system load peaks in the summer and winter, with the larger peak demand occurring in the summer. IPC's record system peak of 2,963 MW occurred on July 12, 2002. Peak summer demand in 2005 was 2,961 MW on July 22, and peak winter demand for the year was 2,345 MW on December 15. IPC was able to meet system load requirements and off-system sales requirements and had sufficient system reserves in place. The following table presents IPC's power supply for the last three years:

	MWh
			Total system	Purchased
	Hydroelectric	Thermal	generation	Power	Total
2005	6,199	7,315	13,514	3,894	17,408
2004	6,041	7,303	13,344	4,274	17,618
2003	6,149	6,914	13,063	3,383	16,446

IPC's median annual hydroelectric generation is 8.5 million MWh, based on median hydrologic conditions for the standardized period of record, 1928 through 2004.

General Business Revenue: The primary influences on electricity sales are weather, customer growth and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the growing season affect sales to customers who use electricity to operate irrigation pumps. Increased precipitation reduces electricity usage by these customers.

The following table presents IPC's general business revenues, MWh sales and average customers, and Boise, Idaho weather conditions for the three years:

			2005		2004		2003
Revenue
	Residential		$	299,488	$	274,313	$	275,920
	Commercial			173,268		164,053		173,820
	Industrial			118,259		111,797		128,620
	Irrigation			76,255		85,672		92,609
		Total	$	667,270	$	635,835	$	670,969

MWh
	Residential			4,760		4,580		4,427
	Commercial			3,639		3,561		3,511
	Industrial			3,423		3,335		3,206
	Irrigation			1,467		1,763		1,836
		Total		13,289		13,239		12,980

Customers (average)
	Residential			373,602		360,462		349,219
	Commercial			57,146		55,577		54,194
	Industrial			129		120		115
	Irrigation			17,942		17,306		16,911
		Total		448,819		433,465		420,439

Heating degree-days				5,437		5,249		4,906
Cooling degree-days				965		998		1,305
Precipitation				13.6"		11.6"		10.1"

Heating and cooling degree-days are a common measure used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree day, and each degree of temperature below 65 degrees is counted as one heating degree-day. Normal heating-degree-days and cooling degree days are 5,727 and 807, respectively.

2005 vs. 2004:

Rates: Increased average rates resulting from higher base rates that took effect on June 1 in both 2005 and 2004 increased revenues $31 million. This was partially offset by a net reduction in the power cost adjustment rates, which reduced revenue $3 million from 2004. Approximately $16 million of the rate increase represents collection of previously recorded revenues from the irrigation load reduction program and rate case tax settlement. This revenue is offset by a corresponding reduction to other revenues for the same amount.

Customers: A 3.5 percent increase in average general business customers increased revenue $27 million, as IPC continued to experience strong customer growth in its service territory. IPC added over 16,000 general business customers during the year; and

Usage: Heavy spring precipitation reduced sales to irrigation customers by $17 million. Rainfall during the second quarter of 2005 was double that of 2004. Other weather and usage factors reduced sales to other customers by $6 million.

2004 vs. 2003:

Rates: Lower average rates, resulting from the PCA, decreased general business revenue $40 million. The decrease in PCA revenues was approximately $68 million. This was partially offset by a $28 million increase due to new base rates beginning on June 1, 2004. The rate changes were the result of several rate proceedings discussed in more detail below in "REGULATORY ISSUES;"

Customers: An increase in general business customers improved revenue $19 million during 2004. IPC added nearly 14,000 general business customers during the year, a 3.2 percent average increase;

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

Usage: Revenues decreased approximately $6 million during 2004 mainly due to cooler summer weather. Cooling degree-days for 2004 were 24 percent less than 2003, which had unusually hot summer temperatures.

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

	2005		2004		2003

Revenue	$	142,794	$	121,148	$	71,573
MWh sold		2,774		2,885		1,830
Revenue per MWh	$	51.48	$	41.99	$	39.11

2005 vs. 2004: Revenues grew 18 percent due to higher energy prices in 2005. Market prices were higher and more volatile because of oil and gas price increases due to instability in the Middle East and hurricane damage on the Gulf Coast. For the Northwest, continuation of drought conditions in the region compounded the impact of these global problems. Consequently, off-system sales revenue on a per MWh basis increased 23 percent for the year. Off-system sales volumes declined four percent, due primarily to changes in operating conditions and load and stream flow timing, which reduced market sales opportunities.

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

Other revenues:
The following table presents the components of other revenues:

		2005		2004		2003
Transmission services and property rental		$	39,012	$	39,839	$	37,840
BPA credit			-		4,000		-
Rate case tax settlement			(2,892)		7,100		-
Irrigation lost revenues			(8,501)		11,587		-
	Total	$	27,619	$	62,526	$	37,840

2005 vs. 2004: Other revenues decreased $35 million due mainly to the following:

In December 2004, IPC recorded approximately $12 million related to the recovery of lost revenue resulting from IPC's Irrigation Load Reduction Program. The recovery was included as part of IPC's annual PCA beginning on June 1, 2005, and $9 million has been amortized as the amounts are billed. This matter is discussed further in "REGULATORY ISSUES - Deferred Power Supply Costs - Idaho;"

In 2004, IPC recognized approximately $7 million of revenue due to the IPUC order approving Settlement No. 1, which relates to the calculation of IPC's taxes for purposes of test year income tax expense in the 2003 Idaho general rate case. As a result of this settlement, IPC recorded a regulatory asset of approximately $12 million from June 1, 2004 through May 31, 2005 ($7 million in 2004 and $5 million in 2005). IPC began collecting this amount beginning in June 2005 with an adjustment to rates and $8 million has been amortized as the amounts are billed; and

In July 2004, IPC recognized $4 million of revenue from an agreement with the Bonneville Power Administration for the release of 100,000 acre-feet of storage water from Brownlee Reservoir. This amount was included in the June 1, 2005 PCA resulting in a benefit to IPC's Idaho customers.

2004 vs. 2003: Other revenues increased $25 million over 2003 due mainly to the same factors discussed above.

Purchased power:

		2005		2004		2003
Purchased power:
	Purchases	$	222,310	$	195,642	$	147,850
	Load reduction costs	$	-	$	-	$	3,130

MWh purchased			3,894		4,274		3,383
Cost per MWh purchased		$	57.09	$	45.77	$	43.70

2005 vs. 2004: Purchased power expense grew 14 percent due to higher energy prices in 2005. Market prices were higher and more volatile for the reasons discussed above. Purchased power expense on a per MWh basis increased 25 percent for the year. Purchased power volumes declined nine percent. Different operating conditions and system load and stream flow timing led to reduced market purchase activities.

2004 vs. 2003: The 2004 increase in purchased power expense was mostly due to a 26 percent increase in volumes purchased. The increased volumes purchased were a result of power supply hedge activity based on expectations of reduced hydroelectric generation due to continued below normal water conditions. Load reduction costs decreased from $3 million in 2003 to zero due to the expiration in March 2003 of the FMC/Astaris Voluntary Load Reduction Program.

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

	2005		2004		2003
Fuel expense	$	103,164	$	103,261	$	99,898
Thermal MWh generated		7,315		7,303		6,914
Cost per MWh	$	14.10	$	14.14	$	14.45

2005 vs. 2004: Fuel expenses and thermal plant volumes were essentially unchanged in 2005.

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

PCA: PCA expense represents the effect of IPC's PCA regulatory mechanism, which is discussed in more detail below in "REGULATORY ISSUES - Deferred Power Supply Costs - Idaho." In 2005, 2004 and 2003, actual net power supply costs, which are fuel and purchased power less off-system sales, exceeded those anticipated in the annual PCA forecast, resulting in the deferral of a portion of those costs to subsequent years when they are to be recovered in rates. As the revenues are being recovered, the deferred balances are amortized.

The following table presents the components of PCA expense:

		2005			2004		2003
Current year net power supply cost deferral		$	(30,786)		$	(29,306)	$	(44,320)
FMC/Astaris and irrigation program cost deferral			-			-		(2,245)
Amortization of prior year authorized balances			27,791			49,190		117,279
Write-offs of disallowed costs			-			-		48
Settlement agreement			-			19,300		-
	Total power cost adjustment	$	(2,995)	$		39,184	$	70,762

Other Operations and Maintenance Expenses:
2005 vs. 2004: Other operations and maintenance expenses decreased $15 million due mainly to the 2004 write-off of $9 million related to disallowed items in the Idaho general rate case.

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

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

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

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

Non-utility Operations

IFS
IFS earned $11 million, $13 million, and $10 million in 2005, 2004 and 2003, respectively, principally from the generation of federal income tax credits and accelerated tax depreciation benefits. The 2004 results included a gain on the sale of its investment in the El Cortez Hotel in San Diego, California. In June 2000, IFS invested $4 million to assist in the renovation of the historic El Cortez into upscale apartment units. Upon exiting the investment on April 22, 2004, IFS recognized a gain on the sale of $5 million, income taxes of $3 million and a net gain of $2 million. The gain is included in other income on IDACORP's Consolidated Statements of Income.

IFS generates federal income tax credits and accelerated tax depreciation benefits related to its investments in affordable housing and historic rehabilitation developments. IFS made $5 million in new investments during 2005 and generated tax credits of $20 million, $22 million and $20 million during 2005, 2004 and 2003, respectively. IFS expects to continue delivering tax benefits at a level commensurate with the ongoing needs of IDACORP.

ITI
ITI recorded net losses of $9 million, $6 million and $1 million in 2005, 2004 and 2003, respectively. The increase in losses in 2005 results from a $3 million reduction in sales of products in development, and a $2 million increase in product development costs, partially offset by a $1.5 million decrease in related income tax expense. The loss in 2004 exceeded the loss in 2003 because of a $2 million decline in sales and a $6 million increase in costs, partially offset by a $3 million decrease in related income tax expenses.

IDACOMM
IDACOMM recorded net losses of $13 million, $2 million and $2 million in 2005, 2004 and 2003, respectively. In the fourth quarter of 2005, IDACOMM recorded a $10 million goodwill impairment, which resulted principally from a revision to the company's business strategy and decision to phase out the portion of the business previously dedicated to exploring the potential use of BPL technology.

Energy Marketing
IE recorded net income (loss) of $5 million, $2 million and ($9) million in 2005, 2004 and 2003, respectively.

In 2003, IE wound down its power marketing operations, closed its business locations and sold its forward book of electricity trading contracts to Sempra Energy Trading. Since that time, IE has had no operations but has been working to settle outstanding legal actions surrounding transactions in the California energy markets in 2000 and 2001. These matters, including a pending settlement agreement filed with the FERC for approval in February 2006, are discussed in "Legal Matters."

Net income increased from $2 million in 2004 to $5 million in 2005, due primarily to a $9.5 million adjustment to an allowance for uncollectible accounts recorded in the fourth quarter of 2005. This adjustment was based on management's assessment of the negotiations to settle the aforementioned California refund proceedings. If the settlement agreement is approved by the FERC, IE's required reserve may be further reduced.

The major transaction affecting results in 2004 was $5 million of gains on settlements of legal disputes.

IE's 2003 results included 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 of a disputed receivable. IE had a $46.1 million long-term receivable from Overton, and this payment resulted in a $1.1 million expense to IE in December 2003. In addition, IE recorded a write-down of $21.5 million related to this receivable in the second quarter of 2003. These write-downs are included in other operating expenses on IDACORP's Consolidated Statement of Income.

As part of the sale of the forward book of electricity trading contracts, IE entered into an Indemnity Agreement with Sempra Energy Trading guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. In 2005, under the terms of the guarantee, IE made $10 million in margin deposits. IE expects this amount to be refunded no later than the end of the guarantee in 2009. The Indemnity Agreement has been accounted for in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" and did not have a material effect on IDACORP's financial statements.

See Note 15 of IDACORP's and IPC's Consolidated Financial Statements for information related to restructuring costs of IE.

Ida-West
Ida-West recorded net income (loss) of $2 million, $3 million and ($5) million in 2005, 2004 and 2003, respectively.

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

Garnet impairment: In 2001, Garnet, a wholly-owned subsidiary of Ida-West, entered into an agreement with IPC to provide energy to be produced by Garnet's proposed natural gas-fired plant. Due to changes in the electricity industry, financing of the project on acceptable terms under the agreement became impracticable, and in 2003, the agreement was mutually terminated. Based on the termination of the agreement and other factors including IDACORP's decision to discontinue Ida-West's project development operations, an impairment charge was recorded for the remaining $3.6 million investment balance in 2003. This impairment is presented on the Consolidated Statement of Income in other operating expenses.

Joint ventures: Based on the change in corporate strategy, Ida-West's investments in four joint ventures were evaluated for impairment in 2003. As a result, $2.4 million in impairment charges were recorded in the fourth quarter of 2003 to partially impair two of the joint ventures. This impairment is presented on the Consolidated Statement of Income in other expense. There were no impairments identified for 2004 or 2005.

In addition, a $2.6 million bad debt reserve was established in 2003 on a note receivable from a partner in one of the joint ventures. The related expense is presented on the Consolidated Statement of Income as other operating expenses. No adjustments were made to this reserve in 2004, but in 2005, the reserve was reduced by $0.7 million based on updated estimates of collectibility.

Income Taxes
Status of Audit Proceedings: In March 2005, the Internal Revenue Service (IRS) began its examination of IDACORP's 2001 through 2003 tax years. On October 24, 2005, the Idaho State Tax Commission also began its examination of the same tax years. Management believes that an adequate provision for income taxes and related interest charges has been made for the open years 2001 and after. The accrued amounts are classified as a current liability in taxes accrued.

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

In 2004, IDACORP completed settlement of all issues related to the IRS's examination of its federal income tax returns for the years 1998 through 2000. Concurrently, IPC settled federal income tax deficiencies for the years 1999 and 2000 related to its partnership investment in the Bridger Coal Company. Applicable state tax return amendments were completed in 2004 and settled. Finalization of these examinations resulted in deficiencies that were less than previously accrued, enabling IDACORP to decrease income tax expense by $2 million in 2004 and $9 million in 2003.

Capitalized Overhead Costs: On August 2, 2005, the IRS and Treasury Department issued guidance interpreting the meaning of "routine and repetitive" for purposes of the simplified service cost and simplified production methods of the Internal Revenue Code section 263A uniform capitalization rules. The guidance was issued in the form of a revenue ruling (Rev. Rul. 2005-53) and proposed and temporary regulations. The regulations are effective for tax years ending on or after August 2, 2005, and the revenue ruling applies for all prior open years. Both pieces of guidance take a more restrictive view of the definition of self-constructed assets produced by a taxpayer on a "routine and repetitive" basis than do the current treasury regulations.

Generally, section 263A requires the capitalization of all direct costs and those indirect costs, known as "mixed service costs", which directly benefit or are incurred by reason of the production of property by a taxpayer. The treasury regulations for section 263A provide several "safe-harbor" methods taxpayers may adopt in order to comply with the statute. The simplified service cost method is one of the methods available for the calculation of indirect overhead "mixed service costs" cost capitalization. IPC changed to the simplified service cost method for both the self-construction of utility plant and production of electricity beginning with its 2001 federal income tax return.

For IPC, the simplified service cost method produces a current tax deduction for costs capitalized to electricity production that are capitalized into fixed assets for financial accounting purposes. Deferred income tax expense has not been provided for this deduction because the prescribed regulatory tax accounting treatment does not allow for inclusion of such deferred tax expense in current rates. Rate 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.

For fiscal years 2002 through 2004, the simplified service cost method decreased IPC's income tax expense by $60 million and resulted in cash refunds from federal and state tax authorities of $75 million. For years 2004 and prior open tax years, if IPC cannot satisfy the new guidance as currently drafted, IPC would be required to use another method of uniform capitalization, which could be more or less favorable to IPC than the simplified service cost method. A less favorable method could result in a one time charge to earnings and reduced cash flow that could be partially offset by carryover tax credits, accelerated tax depreciation, changes in tax regulations and state regulatory recovery.

The temporary regulations are effective for IPC's 2005 tax year and, as drafted, preclude IPC from using this method for self-constructed assets for 2005 and thereafter. Accordingly, in the third quarter of 2005, IPC reversed its previously accrued 2005 tax deduction for capitalized overhead costs for both financial reporting and estimated tax payment purposes. IPC is evaluating alternatives for a new uniform capitalization method.

IPC is actively involved in pursuing resolution of this matter and is working diligently with the IRS in the examination process. At this time, IPC cannot predict the earnings or cash flow impacts that the revenue ruling, temporary regulations, or additional action by the IRS in this matter may have on 2005 or prior tax years.

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

Tax Credits and Net Operating Loss Carryforwards
As of December 31, 2005, IDACORP had $21 million of general business credit carryforward for federal income tax purposes and $6 million of Idaho investment tax credit carryforward. The general business credit carryforward period expires in 2025 and the Idaho investment tax credit expires from 2018 to 2019. IDACOMM has a separate company net operating loss carryforward of $4 million that expires from 2010 to 2021. The deferred tax asset associated with the net operating loss carryforward is fully offset by a $1.6 million valuation allowance recorded in 2005.

Accounting for Uncertain Tax Positions
On July 14, 2005, the FASB released an Exposure Draft for its proposed Interpretation clarifying accounting for uncertain tax positions in accordance with SFAS 109, "Accounting for Income Taxes." The proposed guidance addresses the recognition, measurement, classification, and disclosure issues related to the recording of financial statements benefits for income tax positions that have some degree of uncertainty.

In October the FASB announced that it has moved its projected issuance date of the final standard to the first quarter of 2006. The FASB met on this topic in November 2005 and January 2006. The significant developments to come from those meetings were recommendations to lower the Interpretation's recognition threshold from "probable" to "more likely than not" and to delay the start date until the first annual period beginning after December 15, 2006. Management is unable to predict the final action by the FASB, but is continuing to assess the provisions of this proposed Interpretation as well as the recent FASB deliberations.

LIQUIDITY AND CAPITAL RESOURCES:

Operating Cash Flows
IDACORP's and IPC's operating cash flows for 2005 were $161 million and $166 million, respectively. IDACORP's and IPC's operating cash flows decreased $33 million and $32 million respectively, compared to 2004. The decreases were mainly related to: (1) a $19 million reduction in distributions from the Bridger Coal joint venture, as Bridger is retaining cash to fund increased capital expenditures for conversion to underground mining; and (2) timing of cash disbursements made in 2005 for December 2004 payable balances, including $9 million in employee incentive compensation paid during the first quarter of 2005.

In 2005, net cash provided by operating activities was driven by IPC, where general business revenues and the costs to supply power to general business customers have the greatest impact on operating cash flows. As IPC's service territory experienced below normal water conditions, the company relied more on higher-cost thermal generation and wholesale power purchases to meet its energy needs.

IDACORP's and IPC's operating cash flows for 2004 were $195 million and $198 million, respectively. IDACORP's operating cash flows decreased $118 million in 2004 as a result of reduced receipts from IPC's general business customers of $44 million and an $83 million decrease in net operating cash flows from IE. In 2003, IE received $40 million from the sale of its forward book of electricity trading contracts and collected $45 million on a note receivable from Overton Power District No. 5. These decreases in 2004 were partially offset by a $45 million reduction in income taxes paid.

Working Capital
Changes in working capital accounts from December 31, 2004 to December 31, 2005 include:

Other receivables at IDACORP increased $14 million due principally to a $10 million margin deposit related to the sale of IE's energy marketing book to Sempra Energy Trading.

IDACORP's allowance for uncollectible accounts decreased $10 million due predominantly to an adjustment of IE's allowance related to receivables from California entities.

IDACORP's energy marketing assets and liabilities both increased $15 million from changes in the mark-to-market values of IE's energy marketing contracts.

Taxes accrued increased $26 million at IDACORP and $31 million at IPC, primarily due to income taxes due on the $70.8 million of emission allowances sold in the fourth quarter of 2005.

Other changes in working capital are due predominantly to timing and normal business activity.

Environmental Regulation Costs: IPC anticipates $18 million in annual operating costs for environmental facilities during 2006. Hydroelectric facility expenses account for $12 million of this total and $6 million is related to thermal plant operating expenses. From 2007 through 2008, total environmental related operating costs are estimated to be $35 million. Anticipated expenses related to the hydroelectric facilities account for $23 million and thermal plant expenses are expected to total $12 million during this period.

Pension Expense and Contributions
Total pension expenses in 2005 were $10 million and pension plan contributions were $2 million for the qualified and non-qualified plans. Pension expense is expected to increase to $12 million in 2006.

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

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

			Payment Due by Period
			Total		2006		2007-2008		2009-2010		Thereafter
Long-term debt - IPC (a)			$	987,045	$	-	$	82,127	$	82,127	$	822,791
Future interest payments - IPC (b)				852,018		55,755		106,628		94,526		595,109
Long-term debt - Other (a)(i)				56,132		16,307		24,454		8,622		6,749
Future interest payments - Other (b)(i)				12,215		2,843		3,386		1,372		4,614
Capital lease obligations - Other (i)				35		35		-		-		-
Operating leases - IPC (c)				13,980		4,339		4,390		608		4,643
Operating leases - Other (i)				9,330		1,969		2,578		1,512		3,271
Purchase obligations - IPC:
	Cogeneration and small power
		production		1,387,167		59,719		140,566		147,505		1,039,377
	Fuel swap			660		660		-		-		-
	Fuel supply agreements			151,004		43,370		67,493		30,023		10,118
	Purchased power & transmission (d)			194,850		148,818		23,124		9,907		13,001
	Maintenance & service agreements (e)			85,280		44,314		22,073		7,351		11,542
	Other (f)			60,582		10,746		11,594		11,241		27,001
		Total IPC purchase obligations		1,879,543		307,627		264,850		206,027		1,101,039
Purchase obligations - Other (i)				1,214		1,165		34		15		-
Restructuring charges - Other (g)				1,063		351		374		338		-
Other long-term liabilities - IPC (h)				4,168		831		1,285		1,067		985
Total IDACORP			$	3,816,743	$	391,222	$	490,106	$	396,214	$	2,539,201
Total IPC			$	3,736,754	$	368,552	$	459,280	$	384,355	$	2,524,567

(a)		For additional information, see Note 5 to IDACORP's and IPC's Consolidated Financial Statements.
(b)		Future interest payments are calculated based on the assumption that all debt is outstanding until maturity. For debt instruments with
		variable rates, interest is calculated for all future periods using the rates in effect at December 31, 2005.
(c)		Approximately $10 million of the obligations included in the detail of operating leases have contracts that do not specify terms related to
		expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current contract terms,
		have been included in the table for presentation purposes.
(d)		Approximately $7 million of the obligations included in the detail of purchased power and transmission have contracts that do not specify
		terms related to expiration. As these contracts are presumed to continue indefinitely, 10 years of information, estimated based on current
		contract terms, have been included in the table for presentation purposes.
(e)		Approximately $24 million of the obligations included in the detail of the maintenance and service agreements can be cancelled without
		penalty. Additionally, approximately $17 million of the contracts do not specify terms related to expiration. As these contracts are
		presumed to continue indefinitely, 10 years of information, estimated based on current contract terms, have been included in the table
		for presentation purposes.
(f)		Approximately $5 million of the obligations included in the detail of other purchase obligations can be cancelled without penalty.
		Additionally, approximately $56 million of the contracts do not specify terms related to expiration. As these contracts are presumed to
		continue indefinitely, 10 years of information, estimated based on current contract terms, have been included in the table for presentation
		purposes.
(g)		Restructuring charges are related to the wind down of IE; for additional information see Note 15 to IDACORP's and IPC's Consolidated
		Financial Statements.
(h)		Other long-term liabilities include credit facilities, the human resources information system license fee and lobbying agreements. The
		human resources license fee obligation of approximately $2 million can be cancelled without penalty. Additionally, as the contract does not
		specify terms related to contract expiration, 10 years of information, estimated based on current contract terms, have been included in the
		table for presentation purposes.
(i)		Amounts include the obligations of various subsidiaries with the exception of IPC, which is shown separately.

Off-Balance Sheet Arrangements
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. The mining operations at the Bridger Coal Company are subject to these reclamation and closure requirements. IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company, of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at December 31, 2005. 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 of this guarantee is minimal.

In August 2003, IE sold its forward book of electricity trading contracts to Sempra Energy Trading. As part of the sale, IE entered into an Indemnity Agreement with Sempra Energy Trading, guaranteeing the performance of one of the counterparties. The indemnification expires at the end of 2009 and 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
S&P: On November 29, 2004, S&P announced that it had lowered the corporate credit ratings and long-term ratings of IDACORP and IPC. The companies' commercial paper rating was affirmed at A-2, and the rating outlooks for both companies are stable.

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

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

Moody's stated that the downgrade of IPC's ratings reflected (1) expected weaker cash flow coverage of interest and debt; (2) the likelihood for continued negative free cash flow over the next few years, with internally generated funds falling short of meeting the dividend requirements of IDACORP and significant utility-related capital spending; (3) persistent drought conditions that are likely to result in higher supply costs, not all of which are recoverable under IPC's power cost adjustment mechanism; (4) the final resolution of IPC's 2003 rate case, which resulted in a revenue increase of a little more than half of IPC's updated request; and (5) the likely need for additional support from the IPUC in future rate proceedings as IPC adds new generation and transmission infrastructure to help meet customer and load growth and ensure reliability of service.

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

In addition, Moody's has assigned a Baa2 rating to IDACORP's five-year $150 million senior unsecured bank credit facility and a Baa1 rating to IPC's five-year $200 million senior unsecured bank credit facility. Both facilities expire on March 31, 2010.

Moody's stated that the ratings assigned to the bank credit facilities reflected the pari passu ranking of the facilities with each company's other senior unsecured obligations. The facilities serve as part of the alternate liquidity for each company's commercial paper program and contain a maximum 65 percent total debt to total capitalization ratio covenant with a material adverse change clause as part of the representations and warranties relating to each credit extension. In Moody's view, the existence of the material adverse change clause detracts from the quality of the facilities since it could preclude access to funds at the time of greatest need.

Fitch: On January 24, 2005, Fitch announced that it has lowered the long-term ratings of IDACORP and IPC and the short-term debt ratings at IPC. The rating outlooks for both companies are stable.

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

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

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

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

Capital Requirements
The following table presents IDACORP's and IPC's expected capital requirements from 2006 through 2008:

				2006		2007-2008
				(millions of dollars)
IPC capital expenditures:
	Generating facilities:
		Hydroelectric		$	25	$	68
		Thermal			29		175
			Total generating facilities		54		243
	Transmission lines and substations				55		115
	Distribution lines and substations				66		122
	General				20		45
Other IPC					4		10
		Total IPC			199		535
IFS investments					21		47
Other					8		19
	Total IDACORP			$	228	$	601

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

Internal cash generation after dividends is expected to provide less than the full amount of total capital requirements for 2006 through 2008. The contribution from internal cash generation is dependent primarily upon IPC's cash flows from operations, which are subject to risks and uncertainties relating to weather and water conditions and IPC's ability to obtain rate relief to cover its operating costs. IDACORP's internally generated cash after dividends is expected to provide 34 percent of 2006 capital requirements excluding mandatory or optional principal payments on debt obligations. IDACORP and IPC expect to continue financing capital requirements with internally generated funds and externally financed capital. In 2005, sales of emission allowances provided investing cash of $71 million. On these sales, IPC is expects to pay approximately $28 million in income taxes in the first quarter of 2006, reducing IDACORP's 2006 internally generated cash. Excluding the subsequent cash impacts from the sale of emission allowances, IDACORP's internally generated cash after dividends is expected to provide 51 percent of 2006 capital requirements.

Utility Construction Program: IPC's construction expenditures were $185 million in 2005, $190 million in 2004 and $148 million in 2003. IPC is experiencing a cycle of heavy infrastructure investment needed to address continued customer growth, peak demand growth, and aging plant and equipment. As a result, IPC expects to spend $720 million in construction expenditures from 2006 to 2008. The 2006 - - 2008 utility construction expenditure forecast includes: (1) $82 million of construction costs for a 170-MW combustion turbine peaking resource expected to be operational in mid-2008; and (2) $29 million for an upgrade to the Shoshone Falls hydroelectric facility expected to be operational in 2010.

IPC's aging hydroelectric facilities require continuing upgrades and component replacement. In addition, costs related to relicensing hydroelectric facilities are expected to increase substantially. The three-year construction program anticipates $39 million of upgrades to existing hydroelectric facilities and $54 million of costs associated with relicensing of hydroelectric facilities.

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

Based upon present environmental laws and regulations, IPC estimates its 2006 capital expenditures for environmental matters, excluding AFDC, will total $20 million. Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $17 million and investments in environmental equipment and facilities at the thermal plants account for $3 million. From 2007 through 2008, environmental-related capital expenditures, excluding AFDC, are estimated to be $35 million. Anticipated expenditures related to IPC's hydroelectric facilities account for $24 million and thermal plant expenditures are expected to total $11 million.

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

See further discussion in "REGULATORY ISSUES - Integrated Resource Plan" and "REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

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

Financing Programs
IDACORP's consolidated capital structure consisted of common equity of 48 percent and debt of 52 percent at December 31, 2005.

Credit Facilities: On May 3, 2005, IDACORP entered into a $150 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners (IDACORP Facility). The IDACORP Facility replaced IDACORP's $150 million facility that was to expire on March 16, 2007. The IDACORP Facility, which will be used for general corporate purposes and commercial paper back-up, will terminate on March 31, 2010. The IDACORP Facility provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $150 million, provided that the aggregate amount of the standby letters of credit may not exceed $75 million.

Under the terms of the IDACORP Facility, IDACORP may borrow floating rate advances and eurodollar rate advances. The floating rate is equal to the higher of (i) the prime rate announced by Wachovia Bank or its parent and (ii) the sum of the federal funds effective rate for such day plus 1/2 percent per annum, plus, in each case, an applicable margin. The eurodollar rate is based upon the British Bankers' Association interest settlement rate for deposits in U.S. dollars published on the Telerate Page 3750 (or any successor page) as adjusted by the applicable reserve requirement for Eurocurrency liabilities imposed under Regulation D of the Board of Governors of the Federal Reserve System, for periods of one, two, three or six months plus the applicable margin. The applicable margin is based on IDACORP's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's Investors Services (Moody's) and Standard & Poor's Ratings Service (S&P). The applicable margin for the floating rate advances is zero percent unless IDACORP's rating falls below Baa3 from Moody's or BBB- from S&P, at which time it would equal 0.50 percent. The applicable margin for eurodollar rate advances ranges from 0.27 percent to 0.875 percent depending upon the credit rating. In addition to the applicable margin, if the outstanding aggregate credit exposure exceeds 50 percent of the facility amount, IDACORP would pay a utilization fee ranging from 0.10 percent to 0.125 percent on outstanding loans depending on the credit rating. At December 31, 2005, the applicable margin was zero percent for floating rate advances and 0.425 percent for eurodollar rate advances and 0.125 percent for a utilization fee. A facility fee, payable quarterly by IDACORP, is calculated on the average daily aggregate commitment of the lenders under the IDACORP Facility and is also based on IDACORP's rating from Moody's or S&P as indicated above. At December 31, 2005, the facility fee was 0.15 percent.

In connection with the issuance of letters of credit, IDACORP must pay (i) a fee equal to the applicable margin for eurodollar rate advances on the average daily undrawn stated amount under such letters of credit, payable quarterly in arrears, (ii) a fronting fee at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

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

The events of default under the IDACORP Facility include (i) nonpayment of principal when due and nonpayment of reimbursement obligations under letters of credit within one business day after becoming due and nonpayment of interest or other fees within five days after becoming due, (ii) materially false representations or warranties made on behalf of IDACORP or any of its subsidiaries on the date as of which made, (iii) breach of covenants, subject in some instances to grace periods, (iv) voluntary and involuntary bankruptcy of IDACORP or any material subsidiary, (v) the non-consensual appointment of a receiver or similar official for IDACORP or any of its material subsidiaries or any substantial portion (as defined in the IDACORP Facility) of its property, (vi) condemnation of all or any substantial portion of the property of IDACORP or its subsidiaries, (vii) default in the payment of indebtedness in excess of $25 million or a default by IDACORP or any of its subsidiaries under any agreement under which such debt was created or governed which will cause or permit the acceleration of such debt or if any of such debt is declared to be due and payable prior to its stated maturity, (viii) IDACORP or any of its subsidiaries not paying, or admitting in writing its inability to pay, its debts as they become due, (ix) the acquisition by any person or two or more persons acting in concert of beneficial ownership (within the meaning of Rule 13d-3 of the Securities Exchange Act of 1934) of 20 percent or more of the outstanding shares of voting stock of IDACORP, (x) the failure of IDACORP to own free and clear of all liens, all of the outstanding shares of voting stock of IPC, (xi) unfunded liabilities of all single employer plans under the Employee Retirement Income Security Act of 1974 exceeding $50 million and (xii) IDACORP or any subsidiary being subject to any proceeding or investigation pertaining to the release of any toxic or hazardous waste or substance into the environment or any violation of any environmental law (as defined in the IDACORP Facility) which could reasonably be expected to have a material adverse effect (as defined in the IDACORP Facility). A default or an acceleration of indebtedness of IPC in excess of $25 million, including indebtedness under the IPC Facility described below, will result in a cross default under the IDACORP Facility.

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

On May 3, 2005, IPC entered into a $200 million five-year credit agreement with various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners (IPC Facility). The IPC Facility replaced IPC's $200 million credit agreement that was to expire on March 16, 2007. The IPC Facility, which expires on March 31, 2010, will be used for general corporate purposes and commercial paper back-up. The IPC facility provides for the issuance of loans and standby letters of credit not to exceed the aggregate principal amount of $200 million, provided that the aggregate amount of the standby letters of credit may not exceed $100 million. Under the terms of the IPC Facility, IPC may borrow floating rate advances and eurodollar rate advances. The methods of calculating the floating rate and the eurodollar rate are the same as set forth above for the IDACORP Facility. The applicable margin for the IPC Facility is also dependent upon IPC's rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. At December 31, 2005, the applicable margin for the IPC Facility was zero percent for floating rate advances and 0.35 percent for eurodollar rate advances and 0.125 percent for a utilization fee. A facility fee, payable quarterly by IPC, is calculated on the average daily aggregate commitment of the lenders under the IPC Facility and is also based on IPC's rating from Moody's or S&P as indicated above. At December 31, 2005, the facility fee was 0.125 percent.

In connection with the issuance of letters of credit, IPC must pay (i) a fee equal to the applicable margin for eurodollar rate advances on the average daily undrawn stated amount under such letters of credit, payable quarterly in arrears, (ii) a fronting fee at a per annum rate of 0.125 percent on the average daily undrawn stated amount under each letter of credit, payable quarterly in arrears and (iii) documentary and processing charges in accordance with the letter of credit issuer's standard schedule for such charges.

A ratings downgrade would result in an increase in the cost of borrowing, but would not result in any default or acceleration of the debt under the IPC Facility. If there is a ratings downgrade below investment grade (BBB- or higher by S&P and Baa3 or higher by Moody's), then IPC's authority for continuing borrowings under its regulatory approvals issued by the IPUC and the Oregon Public Utility Commission (OPUC) must be extended or renewed during the occurrence of the ratings downgrade. The Oregon statutes, however, permit the issuance or renewal of indebtedness maturing not more than one year after the date of such issue or renewal without approval of the OPUC. In an order issued May 6, 2005, the IPUC clarified that IPC's authority will not terminate but will continue for a period of 364 days from any downgrade below investment grade.

At December 31, 2005, no loans were outstanding under the IDACORP Facility or the IPC Facility. The events of default under the IPC Facility are the same as under the IDACORP Facility.

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

Debt Covenants: The IDACORP Facility and the IPC Facility each contain a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization of no more than 65 percent as of the end of each fiscal quarter. At December 31, 2005, the leverage ratios for IDACORP and IPC were 51 and 52 percent, respectively. At December 31, 2005, IDACORP was in compliance with all other covenants of the IDACORP Facility and IPC was in compliance with all other covenants of the IPC Facility.

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

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

Long-term financings: On December 15, 2004, IDACORP issued 4,025,000 shares of its common stock at $30 per share. After expenses, IDACORP received approximately $116 million. These proceeds were used to make a capital contribution to IPC and to pay down short-term borrowings at both companies.

On December 15, 2005, IDACORP entered into a Sales Agency Agreement with BNY Capital Markets, Inc. (BNYCMI). Under the terms of the Sales Agency Agreement, IDACORP may offer and sell up to 2,500,000 shares of its common stock, from time to time in at the market offerings through BNYCMI, as IDACORP's agent for such offer and sale. No shares have been sold under this program.

IDACORP currently has $679 million remaining on two shelf registration statements that can be used for the issuance of unsecured debt (including medium-term notes) and preferred or common stock, including the 2,500,000 shares referred to in the preceding paragraph.

In April 2005, with the goal of adding additional common equity to its capital structure, IDACORP began using original issue common stock in its Dividend Reinvestment and Stock Purchase Plan, rather than purchasing this stock on the open market. Beginning in August 2005, IDACORP also began using original issue common stock for its 401(k) plan. Approximately 203,253 shares were issued in 2005.

On August 26, 2005, IPC issued $60 million of 5.30% First Mortgage Bonds due 2035, Secured Medium-Term Notes, Series F. The proceeds of the issuance were used to repay the $60 million, 5.83% First Mortgage Bonds that matured on September 9, 2005. On August 30, 2005, IPC settled a forward-starting interest rate swap agreement by making a payment of $2.7 million to the counterparty of the agreement. In accordance with regulatory accounting practices under SFAS 71, IPC is amortizing this amount over the life of its 5.30% First Mortgage Bonds due 2035.

IPC currently has in place one shelf registration statement that can be used for the issuance of an aggregate principal amount of $240 million of first mortgage bonds (including medium-term notes) and unsecured debt.

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

Subsidiary Financing
IDACORP is currently evaluating its strategic alternatives with respect to IdaTech. One alternative is to raise additional funds from private sources in 2006 for the ongoing funding of operations. IDACORP cannot presently determine what level of private funding, if any, may be raised or what equity interest in IdaTech may be issued in connection with any such funding.

LEGAL AND ENVIRONMENTAL ISSUES:

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

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

The new complaint alleged that during the class period IDACORP and/or certain of its officers and/or directors made materially false and misleading statements or omissions about its business operations, and specifically the IE financial outlook, in violation of Rule 10b-5, thereby causing investors to purchase IDACORP's common stock at artificially inflated prices. The new complaint alleged that IDACORP failed to disclose and misrepresented the following material adverse facts which were known to it or recklessly disregarded by it: (1) IDACORP falsely inflated the value of energy contracts held by IE in order to report higher revenues and profits; (2) IDACORP permitted IPC to inappropriately grant native load priority for certain energy transactions to IE; (3) IDACORP failed to file 13 ancillary service agreements involving the sale of power for resale in interstate commerce that it was required to file under Section 205 of the Federal Power Act; (4) IDACORP failed to file 1,182 contracts that IPC assigned to IE for the sale of power for resale in interstate commerce that IPC was required to file under Section 203 of the Federal Power Act; (5) IDACORP failed to ensure that IE provided appropriate compensation from IE to IPC for certain affiliated energy transactions; and (6) IDACORP permitted inappropriate sharing of certain energy pricing and transmission information between IPC and IE. These activities allegedly allowed IE to maintain a false perception of continued growth that inflated its earnings. In addition, the new complaint alleges that those earnings press releases, earnings release conference calls, analyst reports and revised earnings guidance releases issued during the class period were false and misleading. The action seeks an unspecified amount of damages, as well as other forms of relief. IDACORP and the other defendants filed a consolidated motion to dismiss on February 9, 2005, and the plaintiffs filed their opposition to the consolidated motion to dismiss on March 28, 2005. IDACORP and the other defendants filed their response to the plaintiff's opposition on April 29, 2005 and oral argument on the motion was held on May 19, 2005.

On September 14, 2005, Magistrate Judge Mikel H. Williams of the U.S. District Court for the District of Idaho issued a Report and Recommendation that the defendants' motion to dismiss be granted and that the case be dismissed. The Magistrate Judge determined that the plaintiffs did not satisfactorily plead loss causation (i.e., a causal connection between the alleged material misrepresentation and the loss) in conformance with the standards set forth in the recent United States Supreme Court decision of Dura Pharmaceuticals, Inc. v. Broudo, 544 U.S._____, 125 S. Ct. 1627 (2005). The Magistrate Judge also concluded that it would be futile to afford the plaintiffs an opportunity to file an amended complaint because it did not appear that they could cure the deficiencies in their pleadings. The parties have each filed objections to different parts of the Magistrate Judge's Report and Recommendation, and the matter is now before the District Judge.

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

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

IDACORP, IPC and IE removed this action from the state court to the U.S. District Court for the Western District of Washington at Tacoma. On November 12, 2002, the companies filed a motion to dismiss Grays Harbor's complaint, asserting that the U.S. District Court lacked jurisdiction because the FERC has exclusive jurisdiction over wholesale power transactions and thus the matter is preempted under the Federal Power Act and barred by the filed-rate doctrine. The court ruled in favor of the companies' motion to dismiss and dismissed the case with prejudice on January 28, 2003. On February 25, 2003, Grays Harbor filed a Notice of Appeal, appealing the final judgment of dismissal to the U.S. Court of Appeals for the Ninth Circuit. On August 10, 2004, the Ninth Circuit affirmed the dismissal of Grays Harbor's complaint, finding that Grays Harbor's claims were preempted by federal law and were barred by the filed-rate doctrine. The court also remanded the case to allow Grays Harbor leave to amend its complaint to seek declaratory relief only as to contract formation, and held that Grays Harbor could seek monetary relief, if at all, only from the FERC, and not from the courts. IDACORP, IPC and IE sought rehearing from the Ninth Circuit arguing that the court erred in granting leave to amend the complaint as such a declaratory relief claim would be preempted and would be barred by the filed-rate doctrine. The Ninth Circuit denied the rehearing request on October 25, 2004, and the decision became final on November 12, 2004.

On that same date, the companies took steps to have the case transferred and consolidated with other similar cases arising out of the California energy crisis currently pending before the Honorable Robert H. Whaley, sitting by designation in the Southern District of California and presiding over Multidistrict Litigation Docket No. 1405, regarding California Wholesale Electricity Antitrust Litigation. On November 18, 2004, Grays Harbor filed an amended complaint alleging that the contract was formed under circumstances of "mistake" as to an "artificial . . . power shortage." Grays Harbor asked that the contract therefore be declared "unenforceable" and found "unconscionable." On December 23, 2004, the Judicial Panel on Multidistrict Litigation conditionally transferred the case to Judge Whaley. Grays Harbor sought to vacate the transfer; however, on April 18, 2005, the Judicial Panel on Multidistrict Litigation ordered the case transferred. On May 18, 2005, IDACORP, IPC and IE filed a motion to dismiss the amended complaint. The motion was heard on September 29, 2005.

On December 16, 2005, Judge Whaley issued an Order Setting Status Conference wherein, rather than expressly ruling on the companies' motion to dismiss Grays Harbor's amended complaint, he ruled that either Grays Harbor or the companies may, within 45 days of the date of the order, petition the FERC to weigh in on this case in light of "the extensive hearings . . . already undertaken by FERC in the Northwest refund proceeding" which may be relevant to this case. On January 27, 2006 Grays Harbor and the companies jointly filed a stipulation requesting that the court stay the action and extend the time in which the parties may petition the FERC by sixty days to March 31, 2006, stating that the parties felt the case was appropriate for mediation prior to further proceedings. On January 31, 2006 the court approved the stipulation staying the case until March 31, 2006 and setting a status conference for April 14, 2006. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC's and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit. On July 19, 2005 the companies filed a motion for summary affirmance of the district court's order dismissing the Port of Seattle's complaint. The Ninth Circuit issued an order denying this motion on October 17, 2005. The appeal has been fully briefed and oral argument has been scheduled for March 7, 2006. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

On September 8, 2004, this case was transferred and consolidated with other similar cases currently pending before the Honorable Robert H. Whaley. The companies' motion to dismiss the complaint was granted on February 11, 2005. Wah Chang appealed to the Ninth Circuit on March 10, 2005. The Ninth Circuit set a briefing schedule on the appeal, requiring Wah Chang's opening brief to be filed by July 6, 2005. On May 18, 2005, Wah Chang filed a motion to stay the appeal or in the alternative to voluntarily dismiss the appeal without prejudice to reinstatement. The companies opposed the motion and filed a cross-motion asking the Court to summarily affirm the district court's order of dismissal. On July 8, 2005, the Ninth Circuit denied Wah Chang's motion and also denied the companies' motion for summary affirmance without prejudice to renewal following the filing of Wah Chang's opening brief. Wah Chang's opening brief was filed on September 21, 2005. On October 11, 2005 the companies, along with the other defendants, filed a motion to consolidate this appeal with Wah Chang v. Duke Energy Trading and Marketing currently pending before the Ninth Circuit. On October 18, 2005 the Ninth Circuit granted the motion to consolidate and established a revised briefing schedule. The companies filed an answering brief on November 30, 2005. Wah Chang's reply brief was filed on January 6, 2006. The appeal has been fully briefed; however, no date has yet been set for oral argument. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

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

On August 9, 2005, the companies moved for summary affirmance of the district court's order dismissing the City of Tacoma's complaint. The City of Tacoma filed a response to the companies' motion for summary affirmance on August 24, 2005. The Ninth Circuit denied the companies' motion for summary affirmance on November 3, 2005. The appeal has been fully briefed; however, no date has yet been set for oral argument. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their 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. Suit was filed against entities including Reliant Energy Services, Inc., Reliant Ormond Beach, L.L.C., Reliant Energy Etiwanda, L.L.C., Reliant Energy Ellwood, L.L.C., Reliant Energy Mandalay, L.L.C. and Reliant Energy Coolwater, L.L.C. (collectively, Reliant); and Duke Energy Trading and Marketing, L.L.C., Duke Energy Morro Bay, L.L.C., Duke Energy Moss Landing, L.L.C., Duke Energy South Bay, L.L.C. and Duke Energy Oakland, L.L.C. (collectively, Duke). While varying in some particulars, these cases made a common claim that Reliant, Duke and certain others (not including IE or IPC) colluded to influence the price of electricity in the California wholesale electricity market. The plaintiffs asserted various claims that the defendants violated the California Antitrust Law (the Cartwright Act), Business and Professions Code Section 16720 and California's Unfair Competition Law, Business and Professions Code Section 17200. Among the acts complained of are bid rigging, information exchanges, withholding of power and other wrongful acts. These actions were subsequently consolidated, resulting in the filing of Plaintiffs' Master Complaint in San Diego Superior Court on March 8, 2002.

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

Some of the newly added defendants (foreign citizens and federal agencies) removed that litigation to federal court. IPC and IE, together with numerous other defendants added by the cross-complaints, moved to dismiss these claims, and those motions were heard in September 2002, together with motions to remand the case back to state court filed by the original plaintiffs. On December 13, 2002, the U.S. District Court granted Plaintiffs' Motion to Remand to state court, but did not issue a ruling on IPC and IE's motion to dismiss. The U.S. Court of Appeals for the Ninth Circuit granted certain Defendants and Cross-Defendants' Motions to Stay the Remand Order while they appeal the order. The briefing on the appeal was completed in December 2003. On December 8, 2004, the Ninth Circuit issued its opinion in People of California v. NRG Energy, Inc., et al., which affirmed the district court's remand of these cases to state court and dismissed certain federal government defendants due to their sovereign immunity from suit.

On June 3, 2005, the cross-defendants, including IPC and IE, filed a demurrer in state court seeking to dismiss the cross-complaints filed by Duke and Reliant. On August 8, 2005, before that demurrer was to be heard, the Clerk of the Court entered Duke's voluntary dismissal, with prejudice, of the cross-complaint against IE and IPC. Further briefing and hearing on IE and IPC's demurrer to the Reliant cross-complaint was stayed pending the outcome of the demurrer filed by Reliant on the Master Complaint. On September 22, 2005, the Court took Reliant's demurrer off calendar pending approval of a proposed settlement as to the plaintiff's Master Complaint. On October 3, 2005 the court sustained the defendants' (other than Reliant's) joint demurrer to the Master Complaint and scheduled a status conference to discuss the status of the cross-complaints. On October 13, 2005 the court set IE and IPC's demurrer on the cross-complaint for hearing on December 23, 2005.

However, on November 14, 2005, Judge Joan M. Lewis approved a stipulation between the cross-defendants, including IE and IPC, and Reliant. This stipulation provided for dismissal of IE and IPC by Reliant with prejudice subject to reinstatement in the event that approval and finalization of a settlement agreement between Reliant and the underlying plaintiffs in these cases does not occur. The December 23, 2005 hearing on IE and IPC's demurrer to the cross-complaint was taken off the calendar. A hearing regarding approval of the Reliant settlement was held on Friday January 6, 2006 before Judge Lewis.

Reliant has filed a request for dismissal of IE and IPC with prejudice, which was entered by the clerk of the court on December 19, 2005. Pursuant to IE and IPC's stipulation with Reliant, the dismissal will become final once any judgment and order from the Court approving the Reliant settlement with the plaintiffs becomes final (i.e., once the time for any appeal on the order approving the settlements runs or, if review is sought, the trial court's approval order is affirmed after resolution of all appeals). The time for an appeal from an order approving the settlements would range from 30 to 90 days after entry of the Court's judgments and orders.

If the Court does not grant final approval for the Reliant settlement, Reliant may elect to reactivate its cross-complaint. Similarly, should the Court for any reason fail to approve the Reliant settlement by May 31, 2006, IE and IPC may withdraw from the stipulation agreement by giving ten days advance written notice. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

These matters are also discussed in Note 8 to IDACORP's and IPC's Consolidated Financial Statements.

Western Energy Proceedings at the FERC: IE and IPC are involved in a number of FERC proceedings arising out of the western energy situation in California and claims that dysfunctions in the organized California markets contributed to or caused unjust and unreasonable prices in Pacific Northwest spot markets, and may have been the result of manipulations of gas or electric power markets. They include proceedings involving:

(1) the chargeback provisions of the California Power Exchange (CalPX) participation agreement triggered when a participant defaulted on a payment to the CalPX. Upon such a default, other participants were required to pay their allocated share of the default amount to the CalPX. This provision was first triggered by the Southern California Edison default and later by the Pacific Gas and Electric Company default. The FERC has ordered the CalPX to hold the chargeback funds and that such funds may be used to make-up individual seller shortfalls in their CalPX account at the conclusion of the California Refund proceeding. One party has appealed this order to the D.C. Circuit Court of Appeals. Based upon the settlement agreement filed with the FERC on February 17, 2006 regarding the California Refund proceeding, the California Parties supported a request that the FERC authorize the CalPX to release $2.27 million to IE and IPC;

(2) The California refund proceeding is an efforts by the State of California to obtain refunds for a portion of the spot market sales from sellers of electricity into California from October 2, 2000 through June 20, 2001. California is claiming that the sales prices were not just and reasonable and were not in compliance with the Federal Power Act. The FERC issued an order on refund liability on March 26, 2003 on which multiple parties, including IE, sought rehearing. On October 16, 2003, the FERC denied the requests for rehearing and required the California Independent System Operator (Cal ISO) to make a compliance filing regarding refund amounts within five months, which has since been delayed until March 2006. On May 12, 2004, the FERC issued an order clarifying its earlier refund orders and denying a request by certain parties to present as evidence an earlier settlement between the California Public Utilities Commission and El Paso related to manipulation of gas pipeline capacity claiming that the settlement dollars California is receiving from El Paso ($1.69 billion) are duplicative of the FERC order changing the gas component of its refund methodology. The FERC denied requests for rehearing on November 23, 2004. On December 2, 2003, IE and others petitioned the United States Court of Appeals for the Ninth Circuit for review of the FERC's orders on California refunds. As additional FERC orders have been issued, further petitions for review have been filed, including by IE, and have been consolidated with the appeals already pending before the Ninth Circuit. On September 21, 2004, the Ninth Circuit convened the first of its case management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed several issues related to the FERC's refund jurisdiction, established a schedule for briefing and held oral argument on April 12 and 13, 2005. On May 26, 2005, the California Parties filed a motion with the FERC to submit additional evidence. A number of parties are opposing this motion. On September 6, 2005, the Ninth Circuit issued a decision in one of the severed cases concluding that the FERC lacked refund authority over wholesale electrical energy sales made by governmental entities and non-public utilities. On August 8, 2005 the FERC issued an order establishing a framework for those sellers wanting to make a cost filing to demonstrate that the generally applicable FERC refund methodology interfered with the recovery of costs. The companies along with others made a cost filing on September 14, 2005, the California entities commented on October 11, 2005, and IPC and IE replied to those comments on October 17, 2005. The California entities filed supplemental comments on October 24, 2005 and the companies filed supplemental reply comments on October 27, 2005.

In December 2005 IE and IPC reached a tentative agreement with the California Parties settling matters encompassed by the California Refund proceeding including IE and IPC's cost filing and refund obligation. On January 20, 2006, the Parties filed a request with the FERC asking that FERC defer ruling on IE and IPC's cost filing for thirty days so the parties could complete and file the settlement agreement with the FERC. On January 26, 2006, the FERC granted the requested deferral and required that the settlement be filed by February 17, 2006. On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement at the FERC. Final comments on the settlement are due to be filed by March 20, 2006, after which the FERC will determine whether to approve the settlement. If the settlement is approved by the FERC, IE and IPC will assign $24.25 million of the rights to accounts receivable from the Cal ISO and the CalPX to the California Parties to pay into an escrow account for refunds to settling parties. Amounts from that escrow not used for settling parties and $1.5 million of the remaining IE and IPC receivables which are to be retained by the CalPX are available to fund, at least partially, payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter. Approximately $10.25 million of the remaining IE and IPC receivables are to be released to IE and IPC. At December 31, 2005, 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. In the fourth quarter of 2005 IE reduced by $9.5 million to $32 million its reserve 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, 2005, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a material adverse effect on its consolidated financial position, results of operations or cash flows;

(3) the Pacific Northwest refund proceedings wherein it was argued that the spot market in the Pacific Northwest was affected by the dysfunction in the California market, warranting refunds. The FERC rejected this claim on June 25, 2003, and denied rehearing on November 11, 2003 and February 9, 2004. The FERC orders were appealed to the Ninth Circuit, which established a briefing schedule under which final briefs were submitted in May 2005. There presently is no date set for oral argument. IE and IPC are unable to predict the outcome of these matters; and

(4) two FERC show cause orders which resulted from a ruling of the Ninth Circuit that the FERC permit the California parties in the California refund proceeding to submit materials to the FERC demonstrating market manipulation by various sellers of electricity into California. On June 25, 2003, the FERC ordered a large number of parties including IPC to show cause why certain trading practices did not constitute gaming ("gaming") or anomalous market behavior ("partnership") in violation of the Cal ISO and CalPX Tariffs. On October 16, 2003, IPC reached agreement with the FERC Staff on the show cause orders. The "gaming" settlement was approved by the FERC on March 3, 2004. The FERC approved the motion to dismiss the "partnership" proceeding on January 23, 2004. Although the orders establishing the scope of the show cause proceedings are presently the subject of review petitions in the Ninth Circuit, the order dismissing IPC from the "partnership" proceedings was not the subject of rehearing requests. Eight parties have requested rehearing of the FERC's March 3, 2004 order approving the "gaming" settlement but the FERC has not yet acted on those requests.

In addition to the two show cause orders, on June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale markets for the time period May 1, 2000 through October 1, 2000 to review evidence of economic withholding of generation. IPC, along with over 60 other market participants, responded to FERC data requests and the FERC terminated its investigations as to IPC on May 12, 2004. Numerous parties have appealed the FERC's termination of this investigation as to IPC and over 30 other market participants.

The February 17, 2006 settlement, if approved by the FERC, also provides a basis for FERC disposition of the "gaming" settlement.

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

Other Legal Proceedings: IDACORP, IPC and/or IE are involved in lawsuits and legal proceedings in addition to those discussed above and in Note 8 to IDACORP's and IPC'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.

Environmental Issues
Idaho Water Management Issues: The state of Idaho has experienced six consecutive years of below normal precipitation and stream flows. These conditions have exacerbated a developing water shortage in the state, which is manifested by a number of water issues including declining Snake River base flows and declining levels in the Eastern Snake Plain Aquifer, a large underground aquifer that has been estimated to hold between 200-300 maf of water. These issues are of interest to IPC because of their potential impacts on generation at IPC's hydroelectric projects. With respect to base flows, observed records suggest that the base flows in the Snake River, particularly between IPC's Twin Falls and Swan Falls projects, have been in decline for several decades. The yearly average flow measured below Swan Falls declined at an average rate of 43 cubic feet per second (cfs) per year during the period 1961-2003, and between Twin Falls and Lower Salmon Falls, which significantly contribute to base flow, declined at a rate of approximately 27 cfs per year over the same period. Low flow in the Snake River near Hagerman, Idaho continued to be observed during 2005, where several river gauges in that area recorded the lowest January - March Snake River flows since the early 1960's.

As a result of these declines in river flows, in 2003 several surface water users filed delivery calls with the Idaho Department of Water Resources, demanding that it manage ground water withdrawals pursuant to the prior appropriation doctrine of "first in time is first in right" and curtail junior ground water rights that are depleting the aquifer and affecting flows to senior surface water rights. These delivery calls have resulted in several administrative actions before the Idaho Department of Water Resources and judicial actions before the State District Court in Ada and Gooding Counties in Idaho challenging the constitutionality of state regulations used by the Department to conjunctively administer ground and surface water rights. One such action, filed in January 2005, involves seven surface water irrigation entities from above Milner Dam that submitted a delivery call letter to the Director of the Idaho Department of Water Resources requesting that the Director administer and deliver their senior natural flow and storage water rights pursuant to Idaho law. The irrigation entities contend that existing data reflects that senior surface water rights above Milner Dam have been reduced by approximately 600,000 acre-feet, a 30 percent reduction, over the past six years due, in part, to junior groundwater pumping from the Eastern Snake Plain Aquifer, and that these reductions have resulted in cumulative shortages in natural flow and storage water accrual in American Falls Reservoir, a U.S. Bureau of Reclamation reservoir that supplies a portion of their senior water rights. The Idaho Ground Water Appropriators, Inc., an Idaho non-profit corporation organized to promote and represent the interests of groundwater users, and the U.S. Bureau of Reclamation, the owner of American Falls Reservoir, petitioned to intervene in the delivery call action. Both petitions were granted.

Since IPC holds water rights that are dependent on the Snake River, spring flows and the overall condition of the Eastern Snake Plain Aquifer, IPC is participating in several of these actions to protect its interests and encourage the development of a long-term management plan that will protect the aquifer from further depletion.

One management option being explored is aquifer recharge, or using surface water supplies to increase ground water supplies by allowing the water to percolate into the aquifer in porous locations. Under certain circumstances aquifer recharge may impact senior water rights, including water rights held by IPC for hydropower purposes, and therefore conflict with state law. For that reason, IPC continues to participate in the processes that are considering solutions, such as aquifer recharge, to the conflict between ground and surface water interests in an effort to protect its existing hydroelectric generation water rights. In February 2006, at the request of senior surface water interests, IPC entered into discussions with the State of Idaho and senior surface water interests to explore opportunities for engaging in some limited aquifer recharge in 2006 provided any adverse impact to IPC's hydropower generation and its customers is adequately addressed. These discussions continue and are expected to reach conclusion by mid-March or early April 2006.

Clean Air: The Environmental Protection Agency (EPA) issued Sulfur Dioxide (SO₂) allowances, as defined in the Clean Air Act amendments of 1990, based on coal consumption during established baseline years. IPC currently has more than a sufficient amount of SO₂allowances to provide compliance for emissions attributable to IPC at all three of its jointly-owned coal-fired facilities and both of its natural gas-fired facilities. Prior to the sale of 77,000 emission allowance in 2005 and early 2006 discussed below in "Emission Allowances," IPC believed that it had approximately 107,000 allowances in excess of the amount needed for Clean Air Act compliance. In addition, IPC has been granted annual allotments of allowances ranging from 15,524 to 28,622 through the year 2035. Allowances necessary for IPC's compliance requirements are up to 14,500 annually. Excess allowances owned by IPC may be held for future use, as they do not contain expiration terms. There is an active marketplace for buying and selling allowances, so that SO₂allowances determined to be excess can be sold to others. For all the foregoing reasons, IPC does not foresee any adverse effects upon its operations with regard to SO₂ emissions at this time. See further discussion in "REGULATORY ISSUES - - Emission Allowances."

In March 2005, the EPA issued two new rules limiting emissions from utility boilers, the Clean Air Interstate Rule and the Clean Air Mercury Rule. The Clean Air Interstate Rule will cap emissions of SO₂ and nitrogen oxides (NO_x) in 28 eastern states and the District of Columbia. The Clean Air Interstate Rule does not impose any restrictions on emissions from any IPC facilities. IPC does not foresee any adverse effects upon its operations with regard to the Clean Air Interstate Rule.

The Clean Air Mercury Rule (CAMR) will limit mercury emissions from new and existing coal-fired power plants and creates a market-based cap-and-trade program that will permanently cap utility mercury emissions in two phases. Currently, power plants in the United States emit approximately 48 tons of mercury per year. The first phase cap is 38 tons beginning in 2010, with a second phase cap set at 15 tons beginning in 2018. Mercury emission allocations have been set at the state level, but the states have not allocated the allowances to individual utilities. IPC is actively monitoring developments on this issue and control equipment technology advances. The CAMR is being challenged in court by a number of environmental groups and some states. On October 21, 2005, the EPA granted requests from petitions to reconsider certain aspects of the CAMR. It is anticipated that this rule may require additional emission controls and expenses at IPC's jointly-owned coal-fired facilities, although impacts on future plant operations, operating costs and generating capacity are not known at this time.

Other pending or proposed air regulations or legislation could require IPC's jointly-owned coal-fired facilities to reduce plant emissions of SO₂, NO_x and other pollutants below current levels. These reductions could be required to address regional haze programs, acid rain, mercury emission regulations and possible re-interpretations and changes to the federal Clean Air Act. Like many other coal-fired facilities in the United States, the Jim Bridger plant has received information requests from the EPA related to the plant's compliance with the New Source Review provisions of the Clean Air Act, which has resulted in discussions with the EPA and state regulatory authorities. IPC may incur significant costs to comply with tighter air emissions requirements in the future. These potential costs are expected to consist primarily of capital expenditures.

In July 1997, the EPA announced the National Ambient Air Quality Standards (NAAQS) for ozone and particulate matter (PM) and, in July 1999, the EPA announced regional haze regulations for protection of visibility in national parks and wilderness areas. On May 14, 1999, a federal court ruling blocked implementation of the NAAQS for ozone and PM. In November 2000, the EPA appealed to the U.S. Supreme Court to reconsider that decision. The Supreme Court subsequently ruled in favor of the EPA on February 27, 2001. The EPA has promulgated regulations designating areas of the country for attainment/non-attainment with these standards, and IPC's thermal plants are located in areas designated as attainment for both standards. EPA and state efforts to implement the NAAQS are ongoing. On January 17, 2006, the EPA proposed revisions to the PM NAAQS that potentially could make these NAAQS more stringent, and IPC continues to monitor the EPA's proposed revisions. Litigation concerning the EPA's regional haze regulations resulted in two separate court remands of the rule back to the EPA for reconsideration. On June 15, 2005, the EPA issued the Clean Air Visibility Rule (CAVR) to address the first court remand. On July 20, 2005, the EPA proposed revisions to the CAVR to address the second remand. Although the impacts of the NAAQS for ozone and particulate matter and the regional haze regulations on IPC's thermal operations are not known at this time, the future costs of compliance with these regulations could be substantial and will be dependent on if and how the programs are ultimately implemented.

Global Climate Change: The United States is currently not a party to the Kyoto Protocol to the United Nations Framework Convention on Climate Change (Protocol) that became effective for signatories on February 16, 2005. The Protocol process generally requires developed countries to cap greenhouse gas emissions at certain levels from 2008 through 2012.

Greenhouse gas emissions are the result of many natural and man-made processes including the combustion of fossil fuels to generate electricity. Carbon dioxide represents the largest quantity of greenhouse gases emitted at IPC's coal and gas generation units. Under median water conditions, the majority of IPC's generation is hydro-based which has negligible greenhouse gas emissions compared to fossil-based generation.

REGULATORY ISSUES:

General Rate Case
Idaho: IPC filed its 2003 Idaho general rate case with the IPUC on October 16, 2003. The IPUC approved an increase of $25 million in IPC's electric rates, an average of 5.2 percent, in an order issued on May 25, 2004. The rate increase became effective on June 1, 2004. Additionally, the IPUC approved a return on equity of 10.25 percent and an overall rate of return of 7.85 percent.

On July 13, 2004, after IPC petitioned the IPUC for reconsideration of certain items, the IPUC ordered rates increased by approximately $3 million, in light of the IPUC Staff's computational errors, on or before August 1, 2004. The IPUC also agreed to reconsider an issue relating to the determination of IPC's income tax expense. As a result of this reconsideration, on September 28, 2004, the IPUC issued separate orders approving two settlement agreements entered into on August 16, 2004, between IPC and the IPUC Staff.

In Order No. 29601, the IPUC approved the modification of the general rate case order to utilize IPC's statutory income tax rates to compute test year income tax expense. The rate case tax settlement allows IPC to continue its compliance with the normalization provisions of the Internal Revenue Code of 1986, as amended, and associated Treasury Regulations, and will allow IPC to continue to receive the benefits of accelerated tax depreciation. As a result, IPC computed and recorded monthly during the period June 1, 2004 through May 31, 2005 a regulatory asset (with interest accrued at a rate of one percent per annum) of approximately $12 million, or 2.2 percent, which is a one-year adjustment and will expire on June 1, 2006. The IPUC also granted an ongoing adjustment of approximately $12 million, or 2.25 percent, related to the rate case tax settlement. The increase of 4.45 percent related to the rate case tax settlement adjustments was effective June 1, 2005.

Additionally, IPUC Order No. 29600 resolved outstanding issues related to: (1) an unplanned outage at one of the two units of Valmy in the summer of 2003, (2) a matter relating to the expense adjustment rate for growth component of the PCA and (3) regulatory accounting issues related to a tax accounting method change in 2002. As a result, in September 2004, IPC established a regulatory liability of $19 million with a charge to PCA expense. A monthly credit of approximately $0.8 million is included in the PCA through May 2006, which will reduce this regulatory liability. Also in September 2004, IPC reversed a $16 million regulatory tax liability by reducing income tax expense. This regulatory tax liability was established in 2002 when IPC adopted a tax accounting method change for capitalized overhead costs.

The final result of IPC's 2003 Idaho general rate case was a $40 million increase to the base Idaho jurisdictional revenue requirement, comprised of $25 million in the initial order, $3 million related to computational errors and $12 million in the order approving the rate case tax settlement.

IPC filed a general rate case in October 2005, requesting the IPUC to approve an annual increase to its Idaho retail base rates of $44 million or 7.8 percent. Base rates primarily reflect IPC's cost of providing electrical service to its customers, including equipment, vehicles and infrastructure.

Oregon: On September 21, 2004, IPC filed an application with the OPUC to increase general rates an average of 17.5 percent or approximately $4.4 million annually.

A partial settlement resolved most issues in a manner consistent with the final result in the 2003 Idaho rate case. The most significant issue in this proceeding was the appropriate quantification of net power supply expenses for purposes of setting rates. The OPUC Staff proposed that net power supply expenses for IPC be set at a negative number - meaning that IPC should be able to sell enough surplus energy to pay for all fuel and purchased power expenses and still have revenue left over to offset other costs. The bulk of IPC's rebuttal was directed at this position. A hearing was conducted on May 23, 2005. The OPUC issued its order on July 29, 2005 authorizing an increase of $597,000 in annual revenues for an average of 2.37 percent. The OPUC adopted the Staff argument for the negative net power supply costs, thus reducing IPC's initial rate request of $4.4 million by $2.4 million with this one adjustment.

On September 26, 2005, IPC filed a complaint with the Circuit Court of Marion County, Oregon asking the court to reverse the portion of the OPUC's general rate case order related to the determination of net power supply costs.

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

		2005		2004
Idaho PCA current year:
	Deferral for the 2005-2006 rate year	$	-	$	22,778
	Deferral for the 2006-2007 rate year		3,684		-
Irrigation Lost Revenues			-		13,290
Idaho PCA true-up awaiting recovery:
	Authorized May 2004		-		11,415
	Authorized May 2005*		28,567		-
Oregon deferral:
	2001 costs		8,411		12,047
	2005 costs		2,880		-
	Total deferral	$	43,542	$	59,530

*$28 million will be recovered with interest during the 2006-2007 PCA rate year.

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

The true-up of the true-up portion of the PCA provides a tracking of the collection or the refund of true-up amounts. Each month, the collection or the refund of the true-up amount is quantified based upon the true-up portion of the PCA rate and the consumption of energy by customers. At the end of the PCA year, the total collection or refund is compared to the previously determined amount to be collected or refunded. Any difference between authorized amounts and amounts actually collected or refunded are then reflected in the following PCA year, which becomes the true-up of the true up. Over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized.

On April 15, 2005, IPC filed the 2005-2006 PCA with the IPUC with a proposed effective date of June 1, 2005. The application proposed to hold the PCA component of customers' rates at the existing level, which is currently recovering $71 million above base rates. By IPUC order, the 2005 - 2006 year's PCA includes $12 million in lost revenues and $2 million in related interest resulting from IPC's Irrigation Load Reduction Program that was in place in 2001. IPC proposed to defer recovery of approximately $28 million of power supply costs, or 4.75 percent, for one year to help mitigate the impacts of the $9 million, or 1.84 percent, increase for the Bennett Mountain Power Plant and the $23 million, or 4.45 percent, increase due to the rate case tax settlement adjustments. The $28 million will be recovered during the 2006-2007 PCA rate year, and IPC will earn a two percent carrying charge on this balance. The IPUC accepted the company's PCA proposal.

Oregon: On March 2, 2005, IPC filed for an accounting order to defer net power supply costs for the period of March 1, 2005 through February 28, 2006 in anticipation of continued low water conditions. The forecasted net power supply costs included in this filing were $169 million, of which $3 million related to the Oregon jurisdiction. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses. On July 1, 2005, IPC, the OPUC staff, and the Citizen's Utility Board entered into a stipulation requesting that the OPUC accept IPC's proposed methodology. Under this methodology, IPC will earn its Oregon authorized rate of return on the deferred balance and will recover the amount through rates in future years, as approved by the OPUC.

Fixed-Cost Adjustment Mechanism:
On January 27, 2006, IPC filed with the IPUC for authority to implement a rate adjustment mechanism which would adjust IPC's rates upward or downward to recover IPC's fixed costs independent from the volume of IPC's energy sales. The filing is a continuation of an Idaho case opened in 2004 to investigate the financial disincentives to investment in energy efficiency by IPC. The true-up mechanism, entitled "fixed-cost adjustment" (FCA) would be applicable only to residential service and small general service customers.

The fixed-cost recovery portion of IPC's revenue requirement allowed for recovery in rates would be established for these two customer classes at the time of a general rate case. Thereafter, the FCA would provide a mechanism to true-up the collection of fixed costs to recover the difference between the fixed costs actually recovered through rates and the fixed costs that were allowed to be recovered. Accounting for the FCA would be effective as of January 1, 2006, and the first FCA rate change would occur on June 1, 2007.

The FCA is proposed to change rates coincidentally with IPC's Power Cost Adjustment (PCA) and IPC's seasonal rates. Although the FCA would be timed to adjust on the same schedule as the PCA, the accounting for the FCA would be separate from the PCA. Additionally, IPC proposes to include a three percent cap on any FCA filing, to be applied at the discretion of the IPUC.

Public Utility Regulatory Policies Act of 1978
As mandated by the enactment of PURPA and the adoption of avoided cost rates by the IPUC and the OPUC, IPC has entered into contracts for the purchase of energy from a number of private developers. Under these contracts, IPC is required to purchase all of the output from the facilities located inside the IPC service territory. For projects located outside the IPC service territory, IPC is required to purchase the output that IPC has the ability to receive at the facility's requested point of delivery on the IPC system. The IPUC jurisdictional portion of the costs associated with CSPP contracts are fully recovered through the PCA. For IPUC jurisdictional contracts, projects that generate up to ten average MW of energy on a monthly basis are eligible for IPUC Published Avoided Costs for up to a 20-year contract term. The Published Avoided Cost is a price established by the IPUC and the OPUC to estimate IPC's cost of developing additional generation resources. On August 4, 2005, the IPUC granted a temporary reduction in the eligible project size to 100 kW for intermittent generation resources only. This temporary project size reduction will remain in place until studies are completed which will help the IPUC determine if the Published Avoided Cost should be revised for intermittent generation resources. For OPUC jurisdictional contracts, projects that generate up to ten MW of capacity are eligible for OPUC Published Avoided Costs for up to a 20-year contract term. The OPUC jurisdictional portion of the costs associated with CSPP contracts is recovered through general rate case filings. The Oregon provisions are currently being reviewed in an OPUC proceeding. If a PURPA project does not qualify for Published Avoided Costs, then IPC is required to negotiate the terms, prices and conditions with the developer of that project. These negotiations reflect the characteristics of the individual projects (i.e., operational flexibility, location and size) and the benefits to the IPC system and must be consistent with other similar energy alternatives.

Recent activities, including the extension of the Federal Production Tax Credit and the expansion of the tax credit for eligibility to solar, geothermal and other forms of generation, resolution of IPUC and OPUC PURPA-related hearings and the December 1, 2004 order by the IPUC increasing the Published Avoided Costs, create a favorable climate for PURPA project development, which may require IPC to enter into additional PURPA agreements. The requirement to enter into additional PURPA agreements may result in IPC acquiring energy at above wholesale market prices, thus increasing costs to its customers. Additionally, it is highly likely that the requirement to enter into additional PURPA agreements will add to IPC's surplus during certain times of the year, potentially during off-peak hours. This could also increase costs to IPC's customers. As of December 31, 2005, IPC had signed agreements to purchase energy from 87 small power production (CSPP) facilities with contracts ranging from one to 30 years. Of these facilities, 69 were on-line at the end of 2005; the other 18 facilities under contract are due to come on-line in 2006 and 2007. During 2005, IPC purchased 715,209 MWh from these projects at a cost of $43 million, resulting in a blended price of 6.1 cents per kilowatt hour.

Emission Allowances
In June 2005, IPC filed applications with the IPUC and OPUC requesting blanket authorization for the sale of excess sulfur dioxide emission allowances and an accounting order. The IPUC issued Order 29852 on August 22, 2005, authorizing the sale and interim accounting treatment. Pursuant to the Order, IPC is required to file a report with the IPUC within 60 days after receipt of any sale proceeds. The OPUC issued Order 05-983 on September 13, 2005, stating that IPC did not need a blanket order to sell emission allowances and approved the interim accounting treatment. The OPUC also ordered IPC to file a report within 60 days after receipt of any sales proceeds and stated that ratemaking treatment of the proceeds will be determined in a ratemaking proceeding. Two reports on the sales proceeds have been filed with both the IPUC and the OPUC.

IPC is now seeking approval from the IPUC for the accounting treatment of these transactions, which will determine the allocation of proceeds between retail customers and shareholders. Order 29852 stated that the IPUC Staff was to conduct workshops and make a recommendation as to the appropriate ratemaking treatment. Thus far, parties to the Idaho case have participated in two workshops in November 2005 and one in February 2006 without reaching resolution. Thus far, the matter is now set to be decided by the IPUC via the submittal of comments and briefs by the parties to the case. A decision is anticipated by June 1, 2006.

In 2005, IPC sold 69,500 allowances (out of a total of approximately 107,000 excess allowances) for approximately $71 million (before income taxes and expenses) on the open market. Through February 28, 2006, IPC has sold an additional 7,500 emission allowances for approximately $10 million and plans to continue selling surplus allowances periodically as it deems prudent in light of ongoing analysis of compliance requirements and market conditions. Under the approved interim accounting treatment, IPC is recording the Idaho and Oregon allocated portions of the proceeds (net of expenses) as a regulatory liability. At this time, IPC cannot predict the outcome of the IPUC process, or any future OPUC ratemaking proceeding relating to this issue, or how the proceeds might ultimately be allocated between retail customers and shareholders.

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

The IRP is filed every two years with both the IPUC and the OPUC. Prior to filing, the IRP requires extensive involvement by IPC, the IPUC Staff and the OPUC Staff, as well as customer, technological and environmental representatives and is the starting point for demonstrating prudence in IPC's resource decisions. The IPUC accepted the 2004 IRP on April 22, 2005. The OPUC acknowledged the 2004 IRP on June 17, 2005. The 2004 IRP includes the following elements:

76-MW demand response programs;

48-MW energy efficiency programs;

100-MW geothermal-powered generation;

48-MW combined heat and power at customer facilities;

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

500-MW coal-fired generation;

350-MW wind-powered generation; and

88-MW simple-cycle natural gas fired combustion turbine (peaking resource).

The 2004 IRP identified specific actions to be taken by IPC prior to the next IRP in 2006. IPC is in the process of implementing these actions. During December of 2004, IPC issued two Requests for Proposal (RFPs) associated with an Air Conditioning Cycling Program. During 2005, IPC continued implementation of the 2004 IRP action plan. A Draft RFP for 100 MW of geothermal-powered generation was released on January 18, 2006. Due to a PURPA developer's interest in constructing a large cogeneration project in IPC's service territory, IPC has decided to suspend any further action on the 48-MW combined heat and power RFP.

Coal-fired Resource Screening and Evaluation: In the 2004 IRP, IPC identified the need for seasonal-ownership of a coal-fired resource beginning in 2011. The 2004 IRP's Near-Term Action Plan noted that during 2005 IPC would attempt to identify a utility partner for this resource and that in 2006 IPC would issue an RFP for the coal-fired resource. As a result of discussions with potential resource participants, IPC and Spokane, Washington-based Avista Utilities have entered into an agreement to jointly investigate possible future coal-fired resources. Under the arrangement, the utilities will be studying the options for base load coal-fired generation to meet their collective IRP forecast needs.

Wind RFP: An RFP for 200 MW of wind-powered generation was issued on January 13, 2005. The RFP requested deliveries of energy from approximately 100 MW of wind-powered generation commencing no later than the end of 2006 and deliveries of energy from all 200 MW commencing no later than the end of 2007. Final bids were due on March 10, 2005. The selection committee compiled a short list of bidders then suspended further action until the IPUC could process IPC's request for a moratorium on PURPA wind projects (see "PURPA Wind Projects" below). In late September IPC announced that it would reactivate the RFP, although IPC now anticipates acquiring 100 MW through the process instead of the original 200 MW. Upon receipt of Generation Interconnect Feasibility Studies for the short-listed projects, IPC will complete its evaluation of the proposals received in response to this RFP.

PURPA Wind Projects: As of January 2006, two wind projects, with a total nameplate capacity of 10.8 MW, are selling energy to IPC under approved PURPA agreements. An additional twelve wind projects, comprising 166.5 MW of wind generation, have approved PURPA agreements and are scheduled to come online during 2006 and 2007. The total nameplate capacity of PURPA wind projects currently under contract is 177.3 MW.

As a result of recent IPUC actions, IPC anticipates executing three additional PURPA wind agreements that will subsequently be submitted to the IPUC for approval. These three agreements are expected to provide an additional 50.4 MW of wind-powered generation. If these agreements are signed and approved by the IPUC, the total nameplate capacity of PURPA wind projects under contract will increase to 227.7 MW.

On June 17, 2005, IPC filed an application requesting the IPUC to issue an order temporarily suspending IPC's obligation under PURPA and various IPUC orders to enter into new contracts to purchase energy generated by wind-powered qualifying facilities. IPC requested the temporary suspension remain in effect until the IPUC investigates the impact on IPC's customers arising out of the addition of substantial amounts of wind-powered generation projects. IPC is concerned that the continuous absorption of additional wind resources will adversely affect IPC's overall power supply costs and system reliability. IPC is also concerned that the apparent high price for wind PURPA resources is impacting bid prices for the wind RFP. On July 8, 2005, IPC submitted testimony in support of the request. On July 22, 2005, the IPUC conducted a hearing on the matter and issued an order on August 4, 2005 reducing the maximum size for projects eligible to receive published avoided cost rates to 100 kW from 10 MW and setting grandfathering criteria for PURPA wind projects in progress at the time of the order. Currently, approximately 65 MW of proposed PURPA wind projects are actively seeking contracts from IPC through the grandfathering criteria or via negotiated PURPA agreements. The outcome of these agreement requests is unknown at this time.

Peaking Resource RFP: On January 9, 2006, IPC selected a Siemens-Westinghouse combustion turbine project in response to a RFP for construction of a natural gas-fired power plant, as identified in the 2004 IRP. IPC sought bids for the construction of a turnkey generating facility to expand its generation capabilities during peak times when electricity supplies are low, electricity import capabilities are reduced due to transmission constraints, or wholesale energy costs are high. The plant is planned to be on line prior to the summer of 2008. The proposal selected is for a Siemens-Westinghouse SGT6-5000F combustion turbine located at the Evander Andrews Power Complex near Mountain Home, Idaho. The unit will provide approximately 166 MW of capacity to help meet summer load peaks and can provide greater capacity during cooler times of the year. The Siemens-Westinghouse contract value is expected to be between $48-$51 million following contract negotiations. IPC plans to submit an application to the IPUC for a Certificate of Public Convenience and Necessity before proceeding with the project.

2006 IRP: Preparation has begun on the 2006 IRP with the initial meeting of the IRP Advisory Council held on October 20, 2005, and meetings are continuing on a monthly basis. The planning period will change from a ten-year forecast to a 20-year forecast. The 2006 IRP is scheduled to be filed in June 2006.

Advanced Meter Reading
On February 21, 2003, the IPUC issued Order No. 29196, which directed IPC to submit a plan no later than March 20, 2003 to replace its existing meters with advanced meters that are capable of both automated meter reading and time-of-use pricing. On April 15, 2003, the IPUC issued Order No. 29226, which modified and clarified Order No. 29196. The requirement to commence installation in 2003 was removed; however, IPC was expected to implement Advanced Meter Reading as soon as practicable, subject to updated analysis showing Advanced Meter Reading to be cost effective for customers. As ordered by the IPUC, IPC submitted an updated analysis on May 9, 2003. A workshop with the IPUC Staff and other interested parties to discuss the analysis was held on May 19, 2003. The IPUC issued Order No. 29291 on July 14, 2003, providing interested parties the opportunity to submit comments regarding IPC's updated analysis. On October 24, 2003, the IPUC issued Order No. 29362, which directed IPC to collaboratively develop and submit a Phase One Advanced Meter Reading Implementation Plan to replace current residential meters with advanced meters in selected service areas. IPC complied with this order on December 23, 2003 by filing a Phase One Implementation Plan that targeted the Emmett, Idaho and McCall, Idaho areas for 2004 installation and 2005 implementation. Phase One is projected to cost $7 million and IPC included the 2005 costs in its Idaho General Rate Case. Since April 2004, approximately 24,000 advanced meters have been installed. IPC submitted a report to the IPUC in December 2005 summarizing the Advanced Meter Reading project and associated benefits and costs. The IPUC has opened a comment period extending to April 15, 2006 regarding the report.

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

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

On September 2, 2004, two conservation groups, American Rivers and Idaho Rivers United, filed petitions for rehearing of the orders issuing the licenses for the middle Snake River projects. These petitions ask the FERC to vacate the licensing orders and request a determination from the U.S. Fish and Wildlife Service that the middle Snake River projects jeopardize the listed snail species. On October 4, 2004, the FERC issued an Order Granting Rehearing for Further Consideration to provide additional time to consider the matters raised by the rehearing requests. On March 4, 2005, the FERC issued an order denying the conservation groups' rehearing request. On April 28, 2005, American Rivers and Idaho Rivers United appealed this order to the U.S. Court of Appeals for the Ninth Circuit. IPC filed a motion to intervene in the appeal and the U.S. Fish and Wildlife Service filed a motion to be designated a respondent-intervenor. On June 15, 2005, the court granted these motions. By order dated October 4, 2005, the court extended the briefing schedule in the appeal. Pursuant to the extended schedule, American Rivers and Idaho Rivers United filed their briefs with the court on October 14, 2005 and the FERC filed its brief on December 16, 2005. IPC's and Fish and Wildlife's briefs were filed on January 27, 2006. American Rivers and Idaho Rivers United filed a reply brief and supplemental record on February 28, 2006.

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

Many of the new license articles require IPC to develop comprehensive plans for Protection, Mitigation and Enhancement (PM&E) measures and submit them to the FERC for approval. The plans were due within six months to one year following license issuance and were required to have detailed costs, schedules and methods for implementing the PM&E measures. IPC has submitted these plans to the FERC.

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

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

At December 31, 2005, $9 million of middle Snake River project relicensing and compliance costs were in electric plant in service. The majority of these costs, which were incurred prior to the completion of IPC's 2003 Idaho general rate case, were approved for recovery in rates. Costs incurred since the 2003 general rate case are included in the 2005 general rate case filing. Future costs related to the new license will be submitted to regulators for recovery through the ratemaking process.

Malad Project: On March 25, 2005, IPC received a new 30-year operating license for the Malad project. The new license was effective March 1, 2005 and includes license article requirements to address project operations, minimum flow to benefit aquatic species, ESA snail protection and monitoring, habitat enhancements, fish passage, recreation enhancements and historic properties. IPC has developed project plans, schedules and cost estimates for each article, the last of which will be filed with the FERC by March 2006.

Cost estimates for the plans to implement required PM&E measures are $2 million in capital and $1 million in additional annual operation and maintenance expense. Most of the capital expenditures will occur within the first five years of the license. A fish passage plan, to be filed by March 25, 2006, includes a lower diversion fish ladder. If the plan is approved, construction will commence in 2008. If the proposed fish ladder is successful in addressing intended environmental issues, then a second fish passage structure will be built. A second structure will result in additional capital expenditure of approximately $2 million sometime during the 2010-2015 timeframe. Because the plans have not yet been accepted by the FERC, the cost estimates are preliminary.

At December 31, 2005, $3 million of Malad project relicensing costs were included in electric plant in service and are included in the 2005 Idaho general rate case filing. Future costs related to the new license will be submitted to regulators for recovery through the ratemaking process.

Hells Canyon Complex: The most significant ongoing relicensing effort is the Hells Canyon Complex, which provides approximately two-thirds of IPC's hydroelectric generating capacity and 40 percent of its total generating capacity. The current license for the Hells Canyon Complex expired at the end of July 2005. IPC now operates the project under an annual license issued by the FERC until the new multi-year license is issued. IPC developed the license application for the Hells Canyon Complex through a collaborative process involving representatives of state and federal agencies and business, environmental, tribal, customer, local government and local landowner interests. The license application was filed in July 2003 and accepted by the FERC for filing in December 2003.

The license application includes the continuation of existing, as well as proposed new measures intended to protect, mitigate and enhance fish and wildlife, protect recreational opportunities and preserve other aspects of environmental quality. The estimated costs of these PM&E measures are approximately $106 million in the first five years of a license and $218 million over the following 25 years, for a total estimated cost of $324 million over a 30-year license. These cost estimates do not include estimated costs of proposed water quality measures included in the license application. These measures are the subject of ongoing state processes under Section 401 of the Clean Water Act. IPC estimates that costs associated with these water quality measures may result in an additional cost of $62 million, for a total estimated cost of $386 million. These estimated costs could increase as a result of the licensing process as the FPA requires that the FERC consider, and include in the license, conditions to ensure that the project is consistent with the comprehensive development of the water resource for the improvement and utilization of hydropower development, and for the adequate protection, mitigation and enhancement of fish and wildlife resources and other beneficial public uses. The conditions included in the final license may include mandatory conditions and prescriptions proposed by federal agencies. Under the FPA, some federal agencies have mandatory conditioning authority. Section 18 of the FPA provides the Departments of Commerce and the Interior with authority to require fishways, or passage facilities, to allow fish to migrate below and above a project. Section 4(e) allows federal agencies with jurisdiction over a federal reservation, such as a national forest or park that is occupied by a licensed project, to require the FERC to include in the license such conditions and prescriptions that the federal agency considers necessary for the adequate protection and utilization of that reservation. The FERC must include in the license those conditions and prescriptions proposed by these agencies, which fall within that agency's conditioning authority, under the FPA. These conditions and prescriptions, however, must be supported by substantial evidence and otherwise be in compliance with the provisions of the Energy Act. If they are not, a federal appeals court may set the conditions and prescriptions aside. In other words, the agencies have the authority to require actions to be included in a license to protect resources or address issues under their jurisdiction. As such, the actual costs of the PM&E measures associated with the relicensing of the Hells Canyon Complex will not be known until after the new license is issued by the FERC.

In response to the filing of the license application in July 2003, federal and state agencies, Native American Indian Tribes and other participants in the Hells Canyon Complex relicensing process filed initial comments to the license application, some of which contained additional proposed PM&E measures. IPC's initial estimate of the potential cost of the measures proposed in these initial comments, assuming all of the proposed measures were included as conditions in a final license, which IPC believes is unlikely, totaled more than $2 billion over a period up to 50 years. IPC's preliminary estimate is that this would result in an approximate 25 to 30 percent increase to existing base rates. These cost estimates, however, are preliminary as federal, state, tribal and private parties participating in the relicensing proceeding are not required to file their final comments, recommendations, terms, conditions and prescriptions with the FERC until later in the relicensing process. The FERC has recently issued its Notice of Ready for Environmental Analysis (NREA), which requires the agencies, tribes and other participants in the relicensing process to file preliminary comments, recommendations, terms, conditions and prescriptions under the FPA, the National Environmental Policy Act of 1969, as amended (NEPA), the Energy Policy Act of 2005 and other applicable federal laws. These preliminary recommendations, conditions, and prescriptions will be processed as part of the licensing and NEPA process outlined below, and when filed with the FERC, will provide IPC with a better indicator of the type and nature of PM&E measures that may be included in final license. When the comments, recommendations, terms, conditions and prescriptions become final, the FERC will consider them and include those conditions in the final license that the FERC determines are necessary and required to protect, mitigate and enhance those resources affected by the operation and management of the project, including any mandatory conditions or prescriptions proposed under Sections 4(e) or 18 of the FPA.

At December 31, 2005, $76 million of Hells Canyon Complex relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to a new license, as discussed above, will be submitted to regulators for recovery through the ratemaking process.

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

On October 20, 2003, the FERC issued Scoping Document 1 to provide interested parties with information on the relicensing of the project and solicit comments and suggestions for a preliminary list of issues and alternatives that might be addressed in the environmental impact statement. The FERC also held four scoping meetings in the fall and winter of 2003 to offer parties the opportunity for input on the scope of the environmental impact statement. Based upon comments and information received in response to Scoping Document 1, on November 24, 2004, the FERC Staff issued Scoping Document 2, which provides for a tentative schedule for the environmental impact statement preparation including the filing of additional information. Subsequent to the issuance of Scoping Document 2, IPC and a number of other parties participating in the FERC licensing process requested that the FERC revise the tentative schedule to enable the parties to pursue comprehensive settlement discussions in an effort to reach agreement for the relicensing of the Hells Canyon Complex. (see "Consultation/Settlement Process" discussion below) To facilitate settlement efforts, the FERC extended the NEPA schedule, delaying the issuance of the NREA until the fall of 2005. The FERC issued the NREA on October 28, 2005. Federal and state agencies, Native American Indian Tribes and other participants in the relicensing process filed preliminary comments, recommendations, terms, conditions and prescriptions with the FERC in January 2006. Reply comments by IPC, or other participants in the process, are to be filed by April 11, 2006. The FERC will consider these filings as required by the FPA and NEPA and under its current schedule will issue a draft environmental impact statement in July 2006 and a final environmental impact statement in January 2007.

Consultation/Settlement Process: In an effort to resolve issues associated with the relicensing of the Hells Canyon Complex, IPC has been engaged in discussions with the FERC and relevant federal and state agencies on the effects, if any, of the relicensing of the project on species listed as threatened or endangered under the ESA. The National Marine Fisheries Service listed Snake River sockeye as endangered in 1991, Snake River spring, summer and fall chinook as threatened in 1992 and Snake River steelhead as threatened in 1997. In June 1998, the U.S. Fish and Wildlife Service also listed bull trout in the Columbia and Klamath River basins as threatened. From 1997 to 2004, discussions with the National Marine Fisheries Service and other federal, state and tribal interests on issues associated with the effect of the Hells Canyon Complex operations on ESA-listed species and aquatic resources below the Hells Canyon Complex were in the context of the Snake River Basin Adjudication mediation process.

In July 2004, the FERC requested formal consultation with the National Marine Fisheries Service regarding the effects of interim Hells Canyon Complex operations on ESA-listed species and issued a notice to all interested parties of an ESA consultation meeting on September 9, 2004 to discuss how to proceed with consultation, including how to integrate the ongoing Hells Canyon Complex relicensing settlement discussion into the consultation process.

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

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

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

Following expedited negotiations, on January 7, 2005, IPC filed an agreement on interim operations (Interim Agreement) with the FERC. The Interim Agreement was executed by IPC, American Rivers, Idaho Rivers United, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the U.S. Department of Agriculture - Forest Service, the U.S. Bureau of Land Management, the Oregon Departments of Fish and Wildlife and Environmental Quality, the Nez Perce Tribe, the Shoshone-Bannock Tribes and the Shoshone-Paiute Tribes. The Interim Agreement addresses issues relating to operations of the Hells Canyon Complex and ESA-listed species in advance of the issuance of a new license while the parties to the settlement process participated in negotiations for a comprehensive settlement agreement. In accordance with the provisions of the Interim Agreement, IPC agreed to implement certain measures until a new license is issued for the Hells Canyon Complex including monitoring flows above the Hells Canyon Complex to protect existing rights, the leasing and passing of certain U.S. Bureau of Reclamation flow augmentation water, continuing its fall chinook plan, identifying and monitoring potential stranding sites from March 1 through May 31 of each year and continuing to fund its hatchery program. IPC has also agreed to implement certain additional measures on an annual basis, provided that the parties remain engaged in settlement discussions intended to resolve long-term relicensing issues including, subject to certain variables, flow augmentation to aid anadromous fish migration, the shaping of U.S. Bureau of Reclamation storage water, establishing procedures to collect the data and information necessary in the relicensing settlement discussions, identifying, developing and reviewing potential structural modifications to address dissolved oxygen, total dissolved gas and seasonal water temperatures, providing water quality information to support consultations under Section 401 of the Clean Water Act and sharing information regarding native resident and anadromous fish passage through the Hells Canyon Complex. The signatories agree that the measures in the Interim Agreement are intended to provide reasonable protection for ESA-listed species during the term of the Interim Agreement and also establish a basis for comprehensive settlement discussions to continue. Although the settlement discussions have concluded (see below), IPC has agreed to implement the measures of the Interim Agreement through 2006.

After the filing of the Interim Agreement with the FERC, the Settlement Working Group, with the continuing assistance of the facilitator and separated FERC Staff, commenced negotiations on the long-term settlement agreement. These negotiations continued through the fall of 2005, but due to the number and complexity of the issues, the parties were not successful in reaching an agreement in principle for the licensing of the Hells Canyon Complex. Because it was unlikely that the parties to the settlement process would reach agreement on a comprehensive settlement package in advance of the issuance of the NREA by the FERC in October 2005, the settlement discussions were terminated to allow the parties the opportunity to develop comments and preliminary terms and conditions for filing with the FERC. The parties expect to reassess opportunities for settlement in the spring of 2006 after the filings with the FERC and the proceedings provided for by the Energy Act have concluded.

The Energy Policy Act of 2005: The Energy Act was signed into law on August 8, 2005. Section 241 of the Energy Act modifies the existing hydroelectric relicensing process under the FPA. The Energy Act requires federal resource agencies with authority to impose mandatory conditions on licenses under Sections 4(e) or 18 of the FPA (conditions that the FERC must include in the license, see discussion above) to provide license applicants, and other parties to the licensing process, with evidentiary hearings on disputed issues of material fact related to proposed conditions. It also requires that such agencies accept more cost effective alternative conditions proposed by license applicants, or other parties, provided that the proposed alternative conditions will be no less protective of the resource or the reservation than the original condition recommended by the agency. Pursuant to the provisions of the Energy Act, the Departments of the Interior, Commerce and Agriculture promulgated interim final rules on November 17, 2005 providing for specific procedures and time frames for implementing the evidentiary hearing provisions of the Energy Act and for proposing alternative conditions to the agencies. Pursuant to these rules, IPC and other parties to the licensing process must file requests for evidentiary hearings on disputed issues of material fact and proposed alternative conditions within 30 days of the agency's filing of their preliminary terms and conditions. IPC filed requests for hearing on February 27, 2006. Within 45 days thereafter, the agencies must respond to the hearing requests and the evidentiary hearings are to be held within 90 days thereafter. IPC is now preparing for the proceedings contemplated by the Energy Act.

Swan Falls Project: The license for the Swan Falls hydroelectric project expires in 2010. On March 10, 2005, IPC initiated formal consultation with agencies, Native American tribes and the public regarding the relicensing of the Swan Falls project. This was done by providing interested stakeholders with detailed information on the Swan Falls project. In addition, a site tour and meeting for interested stakeholders was held on May 2, 2005. IPC is in the process of compiling information and performing studies in preparation for filing an application for a new license with the FERC in 2008.

At December 31, 2005, $2 million of Swan Falls project relicensing costs were included in construction work in progress. The relicensing costs are recorded and held in construction work in progress until a new multi-year license is issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to a new license will be submitted to regulators for recovery through the ratemaking process.

Regional Transmission Organizations
In December 1999, the FERC, in Order No. 2000, encouraged all companies with transmission assets to form regional transmission organizations (RTOs). By encouraging the formation of RTOs, the FERC sought to further facilitate the formation of efficient, competitive wholesale electricity markets. In response, several northwest utilities, including IPC, attempted formation of an RTO called RTO West, which eventually evolved into Grid West, a transmission management entity that would not necessarily become an RTO. In July 2005, the FERC acknowledged that Grid West would not need to satisfy their RTO requirements, but did acknowledge that the Grid West governance was sufficiently independent to satisfy the independence requirements of an RTO.

By September 2005, the Grid West technical design was complete and the process was begun to commit the necessary funding to transfer corporate control to a new independent governing board and provide for continued development. Since then, two major funding entities, the Bonneville Power Administration and the British Columbia Transmission Corporation, have declared they are unable to commit to this developmental funding. Recently, Grid West has developed a plan to accelerate development and provide limited near-term services at a potentially much lower cost than the original proposal. The remaining utilities are now in the process of deciding whether to fund the next stages of development on the basis of this new plan.

IPC has spent funds supporting the development of Grid West, and expects to continue funding as long as Grid West remains viable and IPC remains a participating utility. Funding of this effort has taken two forms. First, funds have been loaned to Grid West for the purpose of meeting its developmental expenses. The total accumulated loan through the fourth quarter of 2005 was approximately $1.0 million. IPC expects this loan to be repaid by Grid West when it commences operation. Second, IPC has incurred incremental internal costs from participating in the developmental effort, which are mostly related to incremental travel and legal consultation. Prior to 2005, IPC had accumulated these costs in a deferred expense account. The total accumulated internal expense through the fourth quarter of 2004 was approximately $2.3 million. In recognition of Grid West's decision at the end of 2004 to take a significant first step toward operation, IPC decided that, beginning in 2005, all additional incremental costs related to Grid West development activities would be expensed rather than deferred. At this time, IPC expects to pursue recovery of the accumulated internal costs through rates.

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

On May 2, 2005 IPC filed a "Notice of Change in Status" in accordance with FERC requirements to report the addition of Bennett Mountain Power Plant, which IPC acquired on March 31, 2005. The purpose of the filing is to explain whether, and if so, how, the addition of Bennett Mountain reflects a departure from the characteristics the FERC relied on when it authorized IPC to make sales at market-based rates.

The May 2005 filing included an updated generation market power study that utilized original 2003 data as well as pertinent 2004 data. The results showed that, with the addition of Bennett Mountain, IPC still passed both of the FERC's market power screens in all relevant control areas.

On December 9, 2005, the FERC staff requested that IPC perform a complete generation market power study for the IPC control area using 2004 data. IPC has completed the study and is awaiting a response from the FERC.

OTHER MATTERS:

Adopted Accounting Pronouncements
FIN 46(R): In January 2004, IDACORP and IPC adopted FIN 46(R), which addresses consolidation by business enterprises of variable interest entities, which have one or more of the following characteristics:

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

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

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

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

FIN 47: In 2005, IDACORP and IPC adopted FIN 47. This Interpretation clarifies that the term "conditional asset retirement obligation"(ARO) as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional ARO should be recognized when incurred - generally upon acquisition, construction, or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional ARO should be factored into the measurement of the liability when sufficient information exists. FAS 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate the fair value of an ARO. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO.

FIN 47 became effective December 31, 2005. After reviewing the provisions of FIN 47, no additional ARO's were identified at IPC. One ARO was identified at IDACOMM. Upon adoption, IDACOMM recorded an ARO liability of $0.4 million and a related asset of $0.4 million.

New Accounting Pronouncements
See Note 1 to IDACORP's and IPC's Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and IPC are exposed to various market risks, including changes in interest rates, changes in commodity prices, credit risk and equity price risk. The following discussion summarizes these risks and the financial instruments, derivative instruments and derivative commodity instruments sensitive to changes in interest rates, commodity prices and equity prices that were held at December 31, 2005.

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, 2005, IDACORP and IPC had $133 million and $74 million, respectively, in floating rate debt, net of temporary investments. Assuming no change in either company's financial structure, if variable interest rates were to average one percentage point higher than the average rate on December 31, 2005, interest expense would increase and pre-tax earnings would decrease by approximately $1 million for both IDACORP and IPC.

Fixed Rate Debt: As of December 31, 2005, IDACORP and IPC had outstanding fixed rate debt of $920 million and $865 million, respectively. The fair market value of this debt was $937 million and $881 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 $84 million for IDACORP and $83 million for IPC if interest rates were to decline by one percentage point from their December 31, 2005 levels.

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

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

The Policy requires monitoring monthly volumetric electricity position and total dollar (net power supply cost) exposure on a rolling 18-month forward view. The Power Supply business unit produces and evaluates projections of the operating plan and orders risk mitigating actions dictated by the limits stated in the Policy. The RMC evaluates the actions initiated by Power Supply for consistency and compliance with the Policy. IPC representatives meet with the CAG at least annually to assess effectiveness of the limits. Changes to the limits can be endorsed by the CAG and referred to the Board of Directors for approval. The primary tools for risk mitigation are physical forward power transactions and fueling alternatives for utility-owned generation resources.

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 2003 sale of IE's forward book of electricity trading contracts, IE entered into an Indemnity Agreement with Sempra Energy Trading guaranteeing the performance of one of the counterparties. The maximum amount payable by IE under the Indemnity Agreement is $20 million. In 2005, under the terms of the guarantee, IE made $10 million in margin deposits. IE expects this amount to be refunded no later than the end of the guarantee in 2009. The Indemnity Agreement has been accounted for in accordance with FIN 45 and did not have a significant effect on IDACORP's financial statements.

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

		PAGE
Consolidated Financial Statements:
IDACORP, Inc.
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003		61
Consolidated Balance Sheets as of December 31, 2005 and 2004		62-63
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		64
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2005, 2004
	and 2003	65
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005,
	2004 and 2003	66

Idaho Power Company
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003		67
Consolidated Balance Sheets as of December 31, 2005 and 2004		68-69
Consolidated Statements of Capitalization as of December 31, 2005 and 2004		70
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		71
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2005, 2004
	and 2003	72
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005,
	2004 and 2003	72

Notes to the Consolidated Financial Statements		73-110
Reports of Independent Registered Public Accounting Firm		111-112

Supplemental Financial Information and Consolidated Financial Statement Schedules
Supplemental Financial Information (Unaudited)		113

Financial Statement Schedules for the Years Ended December 31, 2005, 2004 and 2003:
Schedule I - Condensed Financial Information of Registrant-IDACORP, Inc.		127-130
Schedule II-Consolidated Valuation and Qualifying Accounts-IDACORP, Inc.		131
Schedule II-Consolidated Valuation and Qualifying Accounts-Idaho Power Company		132

IDACORP, Inc.
Consolidated Statements of Income

					Year Ended December 31,
					2005		2004		2003
				(thousands of dollars except for per share amounts)
Operating Revenues:
	Electric utility:
		General business			$	667,270	$	635,835	$	670,969
		Off-system sales				142,794		121,148		71,573
		Other revenues				27,619		65,954		40,178
			Total electric utility revenues			837,683		822,937		782,720
	Other					21,805		21,554		40,282
		Total operating revenues				859,488		844,491		823,002

Operating Expenses:
	Electric utility:
		Purchased power				222,310		195,642		150,980
		Fuel expense				103,164		103,261		99,898
		Power cost adjustment				(2,995)		39,184		70,762
		Other operations and maintenance				241,209		255,867		220,983
		Depreciation				101,485		100,855		97,650
		Taxes other than income taxes				20,856		19,090		20,753
			Total electric utility expenses			686,029		713,899		661,026
	Other expense					35,440		37,341		77,914
	Goodwill impairment					10,270		-		-
			Total operating expenses			731,739		751,240		738,940

Operating Income (Loss):
	Electric utility					151,654		109,038		121,694
	Other					(23,905)		(15,787)		(37,632)
		Total operating income				127,749		93,251		84,062

Other Income						17,722		25,777		11,544

Earnings (Losses) of Unconsolidated Equity-method
	Investments					(713)		1,050		2,407

Other Expense						8,006		8,726		7,622

Interest Expense and Preferred Dividends:
	Interest on long-term debt					56,930		54,937		58,670
	Other interest					3,241		3,379		2,832
	Preferred dividends of Idaho Power Company					-		4,823		3,430
		Total interest expense and preferred dividends				60,171		63,139		64,932

Income Before Income Taxes						76,581		48,213		25,459

Income Tax Expense (Benefit)						12,920		(24,770)		(21,119)

Net Income					$	63,661	$	72,983	$	46,578

Weighted Average Common Shares Outstanding (000's)						42,279		38,361		38,228
Earnings Per Share of Common Stock (basic)					$	1.51	$	1.90	$	1.22
Earnings Per Share of Common Stock (diluted)					$	1.50	$	1.90	$	1.22
Dividends Paid Per Share of Common Stock					$	1.20	$	1.20	$	1.70

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets

			December 31,
			2005		2004
Assets			(thousands of dollars)

Current Assets:
	Cash and cash equivalents		$	52,356	$	23,403
	Receivables:
		Customer		97,476		92,258
		Allowance for uncollectible accounts		(33,078)		(43,108)
		Employee notes		2,951		3,523
		Other		22,631		8,806
	Energy marketing assets			23,859		9,203
	Accrued unbilled revenues			38,905		33,832
	Materials and supplies (at average cost)			32,289		28,008
	Fuel stock (at average cost)			11,739		6,539
	Prepayments			18,450		30,035
	Deferred income taxes			23,922		23,407
	Regulatory assets			3,064		5,510
	Other			2,956		-
		Total current assets		297,520		221,416

Investments				191,623		223,061

Property, Plant and Equipment:
	Utility plant in service			3,477,067		3,324,816
	Accumulated provision for depreciation			(1,364,640)		(1,316,125)
		Utility plant in service - net		2,112,427		2,008,691
	Construction work in progress			153,124		152,427
	Utility plant held for future use			2,906		2,636
	Other property, net of accumulated depreciation			45,802		45,708
		Property, plant and equipment - net		2,314,259		2,209,462

Other Assets:
	American Falls and Milner water rights			31,585		31,585
	Company-owned life insurance			35,401		35,765
	Energy marketing assets - long-term			22,189		16,635
	Regulatory assets			415,177		433,271
	Long-term receivables (net of allowance of $1,878 and $2,578)			4,015		2,895
	Employee notes			2,862		3,746
	Goodwill			3,428		13,659
	Other			46,067		42,677
		Total other assets		560,724		580,233

		Total	$	3,364,126	$	3,234,172

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Balance Sheets

				December 31,
				2005		2004
Liabilities and Shareholders' Equity				(thousands of dollars)

Current Liabilities:
	Current maturities of long-term debt			$	16,307	$	78,603
	Notes payable				60,100		36,270
	Accounts payable				83,744		79,156
	Energy marketing liabilities				24,093		9,420
	Taxes accrued				72,652		46,318
	Interest accrued				14,616		14,426
	Other				22,073		21,265
		Total current liabilities			293,585		285,458

Other Liabilities:
	Deferred income taxes				521,855		555,774
	Energy marketing liabilities - long-term				22,189		16,635
	Regulatory liabilities				345,109		275,854
	Other				132,557		112,616
		Total other liabilities			1,021,710		960,879

Long-Term Debt					1,023,580		979,549

Commitments and Contingencies (Note 8)

Shareholders' Equity:
	Common stock, no par value (shares authorized 120,000,000;
		42,656,393 and 42,373,758 shares issued, respectively)			598,706		589,440
	Retained earnings				437,284		424,312
	Accumulated other comprehensive loss				(3,425)		(888)
	Treasury stock (238,914 and 156,741 shares at cost, respectively)				(7,314)		(4,578)
		Total shareholders' equity			1,025,251		1,008,286

			Total	$	3,364,126	$	3,234,172

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Cash Flows

					Year Ended December 31,
					2005		2004		2003
Operating Activities:					(thousands of dollars)
	Net income				$	63,661	$	72,983	$	46,578
	Adjustments to reconcile net income to net cash provided by
		(used in) operating activities:
			Net non-cash loss on legal disputes			-		-		12,072
			Impairment of long-lived asset			-		9,075		3,498
			Impairment of goodwill			10,270		-		-
			Unrealized losses from energy marketing activities			17		131		42,517
			Provision for uncollectible accounts			(10,729)		(128)		2,538
			Depreciation and amortization			124,124		124,192		129,070
			Deferred income taxes and investment tax credits			(31,769)		(33,912)		(56,174)
			Change in regulatory assets and liabilities			7,275		16,788		68,358
			Undistributed (earnings) losses of subsidiaries			(16,762)		2,495		(3,456)
			Gain on sales of assets			(2,128)		(4,475)		-
			Gain on extinguishment of debt			-		(7,188)		-
			Other non-cash adjustments to net income			(4,361)		(3,248)		(3,510)
			Change in:
				Accounts receivables and prepayments		(6,436)		(1,314)		91,991
				Accounts payable and other accrued liabilities		1,821		15,806		(70,342)
				Taxes accrued		26,412		717		(16,797)
				Other current assets		(14,360)		(4,568)		7,020
				Other current liabilities		794		(1,309)		(6,412)
				Long-term receivable		-		-		51,394
			Other assets			(514)		2,058		2,439
			Other liabilities			14,181		6,593		12,065
			Net cash provided by operating activities			161,496		194,696		312,849
Investing Activities:
	Additions to property, plant and equipment					(193,314)		(199,770)		(149,643)
	Sale of non-utility assets					1,019		5,554		494
	Sale of emission allowances					70,757		-		-
	Investments in affordable housing projects					(4,992)		(7,655)		76
	Purchase of available-for-sale securities					(85,334)		(295,356)		(13,689)
	Sale of available-for-sale securities					120,026		266,331		14,040
	Purchase of held-to-maturity securities					(2,181)		(4,927)		(10,547)
	Maturity of held-to-maturity securities					2,840		7,730		7,571
	Other assets					2,229		-		(127)
	Other liabilities					-		(1,547)		(98)
			Net cash used in investing activities			(88,950)		(229,640)		(151,923)
Financing Activities:
	Issuance of long-term debt					64,992		106,442		255,292
	Retirement of long-term debt					(83,067)		(79,890)		(230,003)
	Retirement of preferred stock of Idaho Power Company					-		(52,351)		(860)
	Dividends on common stock					(50,690)		(45,838)		(64,726)
	Increase (decrease) in short-term borrowings, net					23,830		(58,250)		(82,550)
	Issuance of common stock					6,296		115,690		4,123
	Acquisition of treasury shares					-		(1,420)		(799)
	Other assets					(4,486)		(1,145)		(8,404)
	Other liabilities					(468)		(50)		(576)
			Net cash used in financing activities			(43,593)		(16,812)		(128,503)
Net increase (decrease) in cash and cash equivalents						28,953		(51,756)		32,423
Cash and cash equivalents at beginning of year						23,403		75,159		42,736
Cash and cash equivalents at end of year					$	52,356	$	23,403	$	75,159

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the year for:
		Income taxes			$	18,937	$	7,742	$	52,882
		Interest (net of amount capitalized)			$	57,466	$	55,122	$	58,931

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,
	2003		38,152	$		468,241	$	415,315		$	(7,109)	84	$	(1,620)	$	874,827

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

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

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

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

Net income			-			-		63,661			-	-		-		63,661
Common stock dividends
		($1.20 per share)	-			-		(50,690)			-	-		-		(50,690)
Issued			282			8,204		-			-	(14)		431		8,635
Acquired			-			-		-			-	75		(2,268)		(2,268)
Other			-			1,062		1			-	21		(899)		164
Unrealized loss on
	securities (net of tax)		-			-		-			(1,812)	-		-		(1,812)
Minimum pension
	liability adjustment
	(net of tax)		-			-		-			(725)	-		-		(725)

Balance at December 31,
	2005		42,656	$		598,706	$	437,284		$	(3,425)	239	$	(7,314)	$	1,025,251

The accompanying notes are an integral part of these statements.

IDACORP, Inc.
Consolidated Statements of Comprehensive Income

				Year Ended December 31,
				2005		2004		2003
				(thousands of dollars)

Net Income				$	63,661	$	72,983	$	46,578

Other Comprehensive Income (Loss):
	Unrealized (losses) gains on securities:
		Unrealized holding (losses) gains arising during the year,
			net of tax of ($96), $1,234 and $2,963		(457)		2,057		4,982
		Reclassification adjustment for (losses) gains included
			in net income, net of tax of ($870), ($768) and ($111)		(1,355)		(1,195)		(173)
			Net unrealized (losses) gains		(1,812)		862		4,809
	Minimum pension liability adjustment, net of tax of ($465),
		$565 and ($191)			(725)		880		(330)

Total Comprehensive Income				$	61,124	$	74,725	$	51,057

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Income

			Year Ended December 31,
			2005		2004		2003
			(thousands of dollars)
Operating Revenues:
	General business		$	667,270	$	635,835	$	670,969
	Off-system sales			142,794		121,148		71,573
	Other revenues			27,619		62,526		37,840
		Total operating revenues		837,683		819,509		780,382

Operating Expenses:
	Operation:
		Purchased power		222,310		195,642		150,980
		Fuel expense		103,164		103,261		99,898
		Power cost adjustment		(2,995)		39,184		70,762
		Other		181,670		194,073		156,030
	Maintenance			59,539		58,405		62,799
	Depreciation			101,485		100,855		97,650
	Taxes other than income taxes			20,856		19,090		20,753
		Total operating expenses		686,029		710,510		658,872

Income from Operations				151,654		108,999		121,510

Other Income (Expense):
	Allowance for equity funds used during construction			4,950		3,904		3,385
	Earnings of unconsolidated equity-method investments			10,369		12,313		11,336
	Other income			11,476		12,138		8,467
	Other expense			(8,610)		(9,074)		(8,326)
		Total other income		18,185		19,281		14,862

Interest Charges:
	Interest on long-term debt			53,339		50,317		54,645
	Other interest			3,527		3,980		4,718
	Allowance for borrowed funds used during
		construction		(2,791)		(2,953)		(3,310)
		Total interest charges		54,075		51,344		56,053

Income Before Income Taxes				115,764		76,936		80,319

Income Tax Expense				43,925		6,328		21,728

Net Income				71,839		70,608		58,591

	Dividends on preferred stock			-		4,823		3,430

Earnings on Common Stock			$	71,839	$	65,785	$	55,161

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets

Assets

				December 31,
				2005		2004
				(thousands of dollars)

Electric Plant:
	In service (at original cost)			$	3,477,067	$	3,324,816
		Accumulated provision for depreciation			(1,364,640)		(1,316,125)
		In service - net			2,112,427		2,008,691
	Construction work in progress				149,814		151,652
	Held for future use				2,906		2,636
			Electric plant - net		2,265,147		2,162,979

Investments and Other Property					68,049		86,086

Current Assets:
	Cash and cash equivalents				49,335		17,679
	Receivables:
		Customer			49,830		45,441
		Allowance for uncollectible accounts			(833)		(1,363)
		Notes			3,273		3,129
		Employee notes			2,951		3,523
		Related parties			637		1,298
		Other			7,399		5,253
	Accrued unbilled revenues				38,905		33,832
	Materials and supplies (at average cost)				30,451		26,065
	Fuel stock (at average cost)				11,739		6,539
	Prepayments				17,532		28,449
	Regulatory assets				3,064		5,510
			Total current assets		214,283		175,355

Deferred Debits:
	American Falls and Milner water rights				31,585		31,585
	Company-owned life insurance				35,401		35,765
	Regulatory assets				415,177		433,271
	Employee notes				2,862		3,746
	Other				42,187		40,425
			Total deferred debits		527,212		544,792

	Total			$	3,074,691	$	2,969,212

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Balance Sheets

Capitalization and Liabilities

				December 31,
				2005		2004
					(thousands of dollars)
Capitalization:
	Common stock equity:
		Common stock, $2.50 par value (50,000,000 shares
			authorized; 39,150,812 shares outstanding)	$	97,877	$	97,877
		Premium on capital stock			483,707		483,707
		Capital stock expense			(2,097)		(2,097)
		Retained earnings			361,256		340,107
		Accumulated other comprehensive loss			(3,425)		(888)
			Total common stock equity		937,318		918,706

	Long-term debt				983,720		923,910
			Total capitalization		1,921,038		1,842,616

Current Liabilities:
	Long-term debt due within one year				-		60,000
	Accounts payable				79,433		74,642
	Notes and accounts payable to related parties				153		278
	Taxes accrued				72,994		42,228
	Interest accrued				14,105		13,743
	Deferred income taxes				3,064		5,510
	Other				19,182		18,103
			Total current liabilities		188,931		214,504

Deferred Credits:
	Deferred income taxes				507,880		542,829
	Regulatory liabilities				345,109		275,854
	Other				111,733		93,409
			Total deferred credits		964,722		912,092

Commitments and Contingencies (Note 8)

			Total	$	3,074,691	$	2,969,212

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Capitalization

				December 31,
				2005		%		2004		%
				(thousands of dollars)
Common Stock Equity:
	Common stock			$	97,877			$	97,877
	Premium on capital stock				483,707				483,707
	Capital stock expense				(2,097)				(2,097)
	Retained earnings				361,256				340,107
	Accumulated other comprehensive loss				(3,425)				(888)
		Total common stock equity			937,318		49		918,706		50

Long-Term Debt:
	First mortgage bonds:
		5.83% Series due 2005			-				60,000
		7.38% Series due 2007			80,000				80,000
		7.20% Series due 2009			80,000				80,000
		6.60% Series due 2011			120,000				120,000
		4.75% Series due 2012			100,000				100,000
		4.25% Series due 2013			70,000				70,000
		6 % Series due 2032			100,000				100,000
		5.50% Series due 2033			70,000				70,000
		5.50% Series due 2034			50,000				50,000
		5.875% Series due 2034			55,000				55,000
		5.30% Series due 2035			60,000				-
			Total first mortgage bonds		785,000				785,000
		Amount due within one year			-				(60,000)
			Net first mortgage bonds		785,000				725,000

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

	American Falls bond guarantee				19,885				19,885
	Milner Dam note guarantee				11,700				11,700
	Unamortized premium/discount - Net				(3,325)				(3,135)
			Total long-term debt		983,720		51		923,910		50

Total Capitalization				$	1,921,038		100	$	1,842,616		100

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Cash Flows

				Year Ended December 31,
				2005		2004		2003
				(thousands of dollars)
Operating Activities:
	Net income			$	71,839	$	70,608	$	58,591
	Adjustments to reconcile net income to net cash provided by
	operating activities:
		Impairment of assets			-		9,075		-
		Depreciation and amortization			107,919		108,551		110,228
		Deferred income taxes and investment tax credits			(34,729)		(19,992)		(44,221)
		Change in regulatory assets and liabilities			7,275		16,788		68,358
		Undistributed (earnings) losses of subsidiary			(16,669)		1,990		(2,136)
		Provision for uncollectible accounts			(530)		(128)		(40)
		Gain on sale of assets			(672)		-		-
		Other non-cash adjustments to net income			(4,950)		(3,904)		(3,385)
		Change in:
			Accounts receivable and prepayments		5,290		(3,718)		24,487
			Accounts payable		2,578		29,112		(7,147)
			Taxes accrued		30,766		(13,155)		(33,707)
			Other current assets		(14,503)		(4,220)		7,263
			Other current liabilities		1,269		(2,029)		(1,427)
		Other assets			(698)		2,054		(255)
		Other liabilities			11,840		6,753		10,119
		Net cash provided by operating activities			166,025		197,785		186,728

Investing Activities:
	Additions to utility plant				(185,865)		(190,286)		(148,246)
	Note receivable payment from parent				-		-		19,282
	Sale of emission allowances				70,758		-		-
	Purchase of available-for-sale securities				(85,334)		(295,356)		(13,689)
	Sale of available-for-sale securities				120,026		266,331		14,040
	Other assets				1,181		(38)		685
		Net cash used in investing activities			(79,234)		(219,349)		(127,928)

Financing Activities:
	Issuance of long-term debt				60,000		105,000		189,800
	Retirement of long-term debt				(60,000)		(51,105)		(209,880)
	Retirement of preferred stock				-		(52,351)		(860)
	Common stock issued to parent				-		-		39,987
	Dividends on common stock				(50,690)		(46,413)		(64,726)
	Dividends on preferred stock				-		(4,823)		(3,430)
	Decrease in short-term borrowings				-		-		(10,500)
	Capital contribution from parent				-		85,920		-
	Other assets				(4,445)		(1,145)		(7,450)
	Other liabilities				-		129		(409)
		Net cash provided by (used in) financing activities			(55,135)		35,212		(67,468)

Net increase (decrease) in cash and cash equivalents					31,656		13,648		(8,668)
Cash and cash equivalents at beginning of year					17,679		4,031		12,699

Cash and cash equivalents at end of year				$	49,335	$	17,679	$	4,031

Supplemental Disclosure of Cash Flow Information:
	Cash paid during the year for:
		Income taxes paid to parent		$	48,545	$	39,190	$	99,879
		Interest (net of amount capitalized)			51,290		48,113		54,911

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Retained Earnings

		Year Ended December 31,
		2005		2004		2003
		(thousands of dollars)

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

Net Income			71,839		70,608		58,591

Dividends:
	Common stock		(50,690)		(46,413)		(64,726)
	Preferred stock		-		(4,823)		(3,430)

Retained Earnings, End of Year		$	361,256	$	340,107	$	320,735

The accompanying notes are an integral part of these statements.

Idaho Power Company
Consolidated Statements of Comprehensive Income

						Year Ended December 31,
						2005		2004		2003
						(thousands of dollars)

Net Income						$	71,839	$	70,608	$	58,591

Other Comprehensive Income (Loss):
	Unrealized (losses) gains on securities:
			Unrealized holding (losses) gains arising during the year,
					net of tax of ($96), $1,234 and $2,963		(457)		2,057		4,982
			Reclassification adjustment for (losses) gains included
					in net income, net of tax of ($870), ($768) and ($111)		(1,355)		(1,195)		(173)
					Net unrealized (losses) gains		(1,812)		862		4,809
		Minimum pension liability adjustment, net of tax of ($465),
				$565 and ($191)			(725)		880		(330)

Total Comprehensive Income						$	69,302	$	72,350	$	63,070

The accompanying notes are an integral part of these statements.

IDACORP, INC. AND IDAHO POWER COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

This Annual Report on Form 10-K is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (IPC). Therefore, the Notes to the Consolidated Financial Statements apply to both IDACORP and IPC. However, IPC makes no representation as to the information relating to IDACORP's other operations.

Nature of Business
IDACORP is a holding company formed in 1998 whose principal operating subsidiary is IPC. Due to the repeal of the Public Utility Holding Company Act of 1935 (1935 Act), effective February 8, 2006, IDACORP is no longer subject to any provisions under the 1935 Act. IDACORP is a holding company under the newly enacted Public Utility Holding Company Act of 2005 (2005 Act), which provides certain access to books and records to the Federal Energy Regulatory Commission (FERC) and state utility regulatory commissions and imposes certain record retention and reporting requirements on IDACORP.

IPC is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon. IPC is regulated by the FERC and the State regulatory commissions of Idaho and Oregon. IPC is the parent of Idaho Energy Resources Co., a joint venturer in Bridger Coal Company, which supplies coal to the Jim Bridger generating plant owned in part by IPC.

IDACORP's other subsidiaries include:

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

IdaTech, LLC (IdaTech) - developer of integrated fuel cell systems, over 90 percent owned by IDACORP's wholly-owned subsidiary IDACORP Technologies, Inc. (ITI);

IDACOMM, Inc. (IDACOMM) - provider of telecommunications services and commercial Internet services;

Ida-West Energy (Ida-West) - operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA). In 2003, Ida-West discontinued its project development operations and began managing its independent power projects with a reduced workforce; and

IDACORP Energy (IE), a marketer of electricity and natural gas, which wound down its operations during 2003.

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

The entities that IDACORP and IPC consolidate consist primarily of wholly-owned or controlled subsidiaries. In addition, IDACORP consolidates the following VIEs in accordance with Financial Accounting Standards Board Interpretation No. 46(R), "Consolidation of Variable Interest Entities - an interpretation of ARB No. 51:"

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

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

Through IFS, IDACORP also holds significant variable interests in VIEs for which it is not the primary beneficiary. These VIEs are historic rehabilitation and affordable housing developments in which IFS holds limited partnership interests ranging from five to 99 percent. These investments were acquired between 1996 and 2005. IFS's maximum exposure to loss in these developments totaled $100 million at December 31, 2005.

Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with accounting principles generally accepted in the United States of America. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual results could differ from those estimates.

System of Accounts
The accounting records of IPC conform to the Uniform System of Accounts prescribed by the FERC and adopted by the public utility commissions of Idaho, Oregon and Wyoming.

Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, Allowance for Funds Used During Construction (AFDC) and indirect charges for engineering, supervision and similar overhead items. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are expensed to operations. Repair and maintenance costs associated with planned major maintenance are recorded as these costs are incurred. For utility property replaced or renewed, the original cost plus removal cost less salvage is charged to accumulated provision for depreciation, while the cost of related replacements and renewals is added to property, plant and equipment.

All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual depreciation provisions as a percent of average depreciable utility plant in service approximated 2.91 percent in 2005, 2.96 percent in 2004 and 2.99 percent in 2003.

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

Allowance for Funds Used During Construction
AFDC represents the cost of financing construction projects with borrowed funds and equity funds. While cash is not realized currently from such allowance, it is realized under the rate-making process over the service life of the related property through increased revenues resulting from a higher rate base and higher depreciation expense. The component of AFDC attributable to borrowed funds is included as a reduction to interest expense, while the equity component is included in other income. IPC's weighted-average monthly AFDC rates for 2005, 2004 and 2003 were 7.4 percent, 6.9 percent and 8.3 percent, respectively. IPC's reductions to interest expense for AFDC were $3 million annually from 2003 to 2005. Other income included $5 million, $4 million and $3 million for 2005, 2004 and 2003, respectively.

Revenues
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.

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 application of SFAS 71 by IPC can result in IPC recording expenses in a period different than the period the expense would be recorded by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets on the balance sheet and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers.

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

Income Taxes
The liability method of computing deferred taxes is used on all temporary differences between the book and tax basis of assets and liabilities and deferred tax assets and liabilities are adjusted for enacted changes in tax laws or rates. Consistent with orders and directives of the Idaho Public Utilities Commission (IPUC), the regulatory authority having principal jurisdiction, IPC's deferred income taxes (commonly referred to as normalized accounting) are provided for the difference between income tax depreciation and straight-line depreciation computed using book lives on coal-fired generation facilities and properties acquired after 1980. On other facilities, deferred income taxes are provided for the difference between accelerated income tax depreciation and straight-line depreciation using tax guideline lives on assets acquired prior to 1981. Deferred income taxes are not provided for those income tax timing differences where the prescribed regulatory accounting methods do not provide for current recovery in rates. Regulated enterprises are required to recognize such adjustments as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. See Note 2 for more information.

The State of Idaho allows a three-percent investment tax credit on qualifying plant additions. Investment tax credits earned on regulated assets are deferred and amortized to income over the estimated service lives of the related properties. Credits earned on non-regulated assets or investments are recognized in the year earned.

Earnings Per Share
The computation of diluted earnings per share (EPS) differs from basic EPS only due to the inclusion of potentially dilutive shares related to stock-based compensation awards.

The diluted EPS computation excluded 1,014,437 common stock options in 2005, 818,600 in 2004 and 721,800 in 2003, because the options' exercise prices were greater than the average market price of the common stock during those years. In total, 1,421,914 options were outstanding at December 31, 2005, with expiration dates between 2010 and 2015.

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

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

			2005			2004		2003
			(thousands of dollars except for
			per share amounts)
IDACORP
Net income, as reported			$	63,661		$	72,983	$	46,578
Add: Stock-based employee compensation expense
	included in reported net income, net of related
	tax effects			359			399		(76)
Deduct: Stock-based employee compensation
	expense determined under fair value based
	method for all awards, net of related tax effects			1,214			1,169		1,169
		Pro forma net income	$	62,806		$	72,213	$	45,333
EPS of common stock:
	Basic - as reported		$	1.51		$	1.90	$	1.22
	Diluted - as reported			1.50			1.90		1.22
	Basic - pro forma			1.49			1.88		1.19
	Diluted - pro forma			1.48			1.88		1.19


			2005			2004		2003
			(thousands of dollars except for
			per share amounts)
IPC
Net income, as reported			$		71,839	$	70,608	$	58,591
Add: Stock-based employee compensation expense included in
	reported net income, net of related tax effects				108		276		(56)
Deduct: Stock-based employee compensation expense
	determined under fair value based method for all awards, net				108		276		(56)
	of related tax effects				568		977		1,073
		Pro forma net income	$		71,379		69,907	$	57,462

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

Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and highly liquid temporary investments with maturity dates at date of acquisition of three months or less.

Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options and swaps are used to manage exposure to commodity price risk in the electricity market. The objective of the risk management program is to mitigate the risk associated with the purchase and sale of electricity and natural gas. 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.

Comprehensive Income
Comprehensive income includes net income, unrealized holding gains and losses on marketable securities, IPC's proportionate share of unrealized holding gains and losses on marketable securities held by an equity investee and the changes in additional minimum liability under a deferred compensation plan for certain senior management employees and directors. The following table presents IDACORP's and IPC's accumulated other comprehensive loss balance at December 31:

		2005		2004
		(thousands of dollars)
Unrealized holding gains on securities		$	2,725	$	4,538
Minimum pension liability adjustment			(6,150)		(5,426)
	Total	$	(3,425)	$	(888)

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

The annual impairment tests were performed on IDACORP's goodwill balances, which are related to acquisitions made by ITI and IDACOMM. IDACORP's annual impairment tests were conducted as of June 30, and at that time no impairment was noted. The strategic decision to exit one of IDACOMM's lines of business, broadband-over-power line, triggered the requirement to conduct another impairment test. Based on the results of that test, IDACOMM's goodwill balance was considered impaired and a $10 million impairment charge was recorded in the fourth quarter of 2005. Impairment tests on the remaining ITI goodwill balance will continue to be performed at least annually, and more frequently if circumstances indicate a possible impairment.

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

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

In March 2005, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) 107 to provide additional guidance regarding the application of SFAS 123(R). SAB 107 permits registrants to choose an appropriate valuation technique or model to estimate the fair value of share options, assuming consistent application, and provides guidance for the development of assumptions used in the valuation process. Additionally, SAB 107 discusses disclosures to be made under "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the registrants' periodic reports.

Based upon Securities and Exchange Commission rules issued in April 2005, SFAS 123(R) is effective for fiscal years that begin after June 15, 2005 and will be adopted by IDACORP and IPC in the first quarter of 2006. Adoption is not expected to have a material effect on IDACORP's or IPC's financial statements.

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

SFAS 154: In May 2005 the FASB issued SFAS 154, "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3." SFAS 154 changes the requirements for the accounting for and reporting of a change in accounting principle. It applies to all voluntary changes in accounting principle and to changes required by an accounting pronouncement that does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, SFAS 154 requires that the new accounting principle be applied as if it were adopted prospectively from the earliest date practicable. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

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 2005 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 tax rate is as follows:

					IDACORP						IPC
					2005		2004		2003		2005		2004		2003
					(thousands of dollars)
Federal income tax expense at
	35% statutory rate			$	26,804	$	16,875	$	8,911	$	40,517	$	26,928	$	28,112
Change in taxes resulting from:
		AFDC			(2,709)		(2,400)		(2,343)		(2,709)		(2,400)		(2,343)
		Investment tax credits			(3,424)		(3,295)		(3,397)		(3,424)		(3,295)		(3,397)
		Repair allowance			(1,750)		(2,450)		(2,450)		(1,750)		(2,450)		(2,450)
		Removal costs			(1,490)		(1,244)		(1,101)		(1,490)		(1,244)		(1,101)
		Pension accrual			1,276		1,237		2,456		1,276		1,237		2,456
		Capitalized overhead costs			-		(3,658)		(3,658)		-		(3,658)		(3,658)
		Goodwill impairment			3,489		-		-		-		-		-
		Regulatory tax liability			-		(16,457)		-		-		(16,457)		-
		Settlement of prior years tax
			returns		(943)		(1,876)		(8,911)		(934)		(1,398)		(8,908)
		State income taxes, net of
			federal benefit		4,828		2,923		1,357		6,173		4,100		3,973
		Depreciation			5,603		4,350		10,237		5,603		4,350		10,237
		Affordable housing and
			historic tax credits		(20,205)		(21,717)		(20,345)		-		-		-
		Preferred dividends of IPC			-		1,688		1,200		-		-		-
		Valuation allowance			1,564		-		-		-		-		-
		Other, net			(123)		1,254		(3,075)		663		615		(1,193)
Total income tax expense (benefit)				$	12,920	$	(24,770)	$	(21,119)	$	43,925	$	6,328	$	21,728
		Effective tax rate			16.9%		(51.4%)		(83.0%)		37.9%		8.2%		27.1%

The items comprising income tax expense are as follows:

				IDACORP						IPC
				2005		2004		2003		2005		2004		2003
				(thousands of dollars)
Income taxes currently payable:
	Federal		$	37,667	$	6,087	$	26,356	$	69,479	$	19,003	$	55,034
	State			7,022		3,055		8,699		9,176		7,317		10,915
		Total		44,689		9,142		35,055		78,655		26,320		65,949
Income taxes deferred:
	Federal			(28,716)		(30,646)		(44,938)		(31,599)		(15,488)		(35,166)
	State			(5,003)		(2,313)		(11,465)		(5,081)		(3,551)		(9,284)
		Total		(33,719)		(32,959)		(56,403)		(36,680)		(19,039)		(44,450)
Investment tax credits:
	Deferred			5,374		2,342		3,627		5,374		2,700		3,627
	Restored			(3,424)		(3,295)		(3,398)		(3,424)		(3,653)		(3,398)
		Total		1,950		(953)		229		1,950		(953)		229
Total income tax expense (benefit)			$	12,920	$	(24,770)	$	(21,119)	$	43,925	$	6,328	$	21,728

The components of the net deferred tax liability are as follows:

			IDACORP				IPC
			2005		2004		2005		2004
			(thousands of dollars)
Deferred tax assets:
	Regulatory liabilities		$	41,627	$	40,447	$	41,627	$	40,447
	Advances for construction			6,881		5,357		6,881		5,357
	Deferred compensation			14,581		14,001		13,276		12,324
	Emission allowances			27,380		-		27,380		-
	Tax credits			26,715		28,211		-		-
	Other			16,078		15,737		14,496		14,584
		Total		133,262		103,753		103,660		72,712
Deferred tax liabilities:
	Property, plant and equipment			240,144		241,324		240,144		241,324
	Regulatory assets			346,117		344,220		346,117		344,220
	Conservation programs			5,705		6,972		5,705		6,972
	PCA			17,410		20,516		17,410		20,516
	Partnership investments			18,770		19,975		3,892		5,600
	Other			3,049		3,113		1,336		2,419
		Total		631,195		636,120		614,604		621,051
Net deferred tax liabilities			$	497,933	$	532,367	$	510,944	$	548,339

Amounts accrued by IPC for income taxes are payable to IDACORP, as IPC joins in the filing of IDACORP's federal and state consolidated income tax returns.

Status of Audit Proceedings
In March 2005, the Internal Revenue Service (IRS) began its examination of IDACORP's 2001 through 2003 tax years. On October 24, 2005, the Idaho State Tax Commission also began its examination of the same tax years. Management believes that an adequate provision for income taxes and related interest charges has been made for the open years 2001 and after. The accrued amounts are classified as a current liability in taxes accrued.

Generally, section 263A requires the capitalization of all direct costs and those indirect costs, known as "mixed service costs", which directly benefit or are incurred by reason of the production of property by a taxpayer. The treasury regulations for section 263A provide several "safe-harbor" methods taxpayers may adopt in order to comply with the statute. The simplified service cost method is one of the methods available for the calculation of indirect overhead ("mixed service costs") cost capitalization. IPC changed to the simplified service cost method for both the self-construction of utility plant and production of electricity beginning with its 2001 federal income tax return.

3. COMMON STOCK:

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

		2005	2004
Dividend reinvestment and stock purchase plan and employee savings plan		5,859,061	6,062,314
Restricted stock plan		314,114	314,114
Long-term incentive and compensation plan		3,013,217	2,042,600
Continuous equity program		2,500,000	-
	Total shares reserved	11,686,392	8,419,028

IDACORP issues shares of common stock for its Dividend Reinvestment and Stock Purchase Plan (DRIP) and Employee Savings Plan. Although no shares were issued in 2004, in 2005 and 2003, IDACORP issued 146,684 and 122,990 shares, respectively, for the DRIP and 56,569 and 65,932 shares, respectively, for the Employee Savings Plan.

In 2005, IDACORP issued 62,983 shares in connection with stock compensation awards and issued 16,400 shares pursuant to exercises of stock options granted to participants in the 2000 Long-Term Incentive and Compensation Plan (LTICP).

On December 15, 2005, IDACORP entered into a Sales Agency Agreement with BNY Capital Markets, Inc. (BNYCMI). Under terms of the Sales Agency Agreement, IDACORP may offer and sell up to 2,500,000 shares of its common stock, from time to time in at the market offerings through BNYCMI, as IDACORP's agent for such offer and sale.

Shareholder Rights Plan
IDACORP has a Shareholder Rights Plan (Plan) designed to ensure that all shareholders receive fair and equal treatment in the event of any proposal to acquire control of IDACORP. Under the Plan, IDACORP declared a distribution of one Preferred Share Purchase Right (Right) for each of its outstanding common shares held on October 1, 1998 or issued thereafter. The Rights are currently not exercisable and will be exercisable only if a person or group (Acquiring Person) either acquires ownership of 20 percent or more of IDACORP's voting stock or commences a tender offer that would result in ownership of 20 percent or more of such stock. IDACORP may redeem all, but not less than all, of the Rights at a price of $0.01 per Right or exchange the Rights for cash, securities (including common shares of IDACORP) or other assets at any time prior to the close of business on the tenth day after acquisition by an Acquiring Person of a 20 percent or greater position.

Additionally, the IDACORP Board of Directors created the A Series Preferred Stock, without par value, and reserved 1,200,000 shares for issuance upon exercise of the Rights.

Following the acquisition of a 20 percent or greater position, each Right will entitle its holder to purchase, for $95, that number of shares of common stock or preferred stock having a market value of $190.

If after the Rights become exercisable, IDACORP is acquired in a merger or other business combination, 50 percent or more of its consolidated assets or earnings power are sold, or the Acquiring Person engages in certain acts of self-dealing, each Right entitles the holder to purchase, for $95, shares of the acquiring company's common stock having a market value of $190.

Any Rights that are or were held by an Acquiring Person become void if any of these events occurs. The Rights expire on September 30, 2008.

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

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

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

IPC
In December 2004, IDACORP contributed $86 million of additional equity to IPC. No additional shares of IPC common stock were issued.

In December 2003, IPC issued 1,538,461 shares of $2.50 par value common stock to IDACORP for $40 million. Each share of IPC's common stock is entitled to one vote.

4. PREFERRED STOCK OF IDAHO POWER COMPANY:

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

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

5. LONG-TERM DEBT:

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

							2005		2004
							(thousands of dollars)
First mortgage bonds:
		5.83			%	Series due 2005	$	-	$	60,000
		7.38			%	Series due 2007		80,000		80,000
		7.20			%	Series due 2009		80,000		80,000
		6.60			%	Series due 2011		120,000		120,000
		4.75			%	Series due 2012		100,000		100,000
		4.25			%	Series due 2013		70,000		70,000
		6			%	Series due 2032		100,000		100,000
		5.50			%	Series due 2033		70,000		70,000
		5.50			%	Series due 2034		50,000		50,000
		5.875			%	Series due 2034		55,000		55,000
		5.30			%	Series due 2035		60,000		-
				Total first mortgage bonds				785,000		785,000
Pollution control revenue bonds:
		Variable Auction Rate Series 2003 due 2024 (a)						49,800		49,800
		6.05			%	Series 1996A due 2026		68,100		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
American Falls bond guarantee								19,885		19,885
Milner Dam note guarantee								11,700		11,700
Unamortized premium/discount - net								(3,325)		(3,135)
Debt related to investments in affordable housing								48,481		66,310
Other subsidiary debt								7,686		7,932
	Total							1,039,887		1,058,152
Current maturities of long-term debt								(16,307)		(78,603)
			Total long-term debt				$	1,023,580	$	979,549
(a) Humboldt County Pollution Control Revenue bonds are secured by first mortgage bonds, bringing the total of first mortgage
bonds outstanding at December 31, 2005 to $834.8 million.

At December 31, 2005, the maturities for the aggregate amount of long-term debt outstanding were (in thousands of dollars):

	2006		2007		2008		2009		2010		Thereafter

IPC	$	-	$	81,064	$	1,064	$	81,064	$	1,064	$	822,789
Other subsidiary debt		16,307		14,096		10,392		5,657		2,965		6,750
Total	$	16,307	$	95,160	$	11,456	$	86,721	$	4,029	$	829,539

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

On October 22, 2003, Humboldt County, Nevada issued, for the benefit of IPC, $49.8 million Pollution Control Revenue Refunding Bonds (Idaho Power Company Project) Series 2003 due December 1, 2024. IPC borrowed the proceeds from the issuance pursuant to a Loan Agreement with Humboldt County and is responsible for payment of principal, premium, if any, and interest on the bonds. The bonds are secured, as to principal and interest, by IPC first mortgage bonds and as to principal and interest when due, by an insurance policy issued by Ambac Assurance Corporation. The bonds were issued in an auction rate mode under which the interest rate is reset every 35 days. The initial auction rate was set at 0.95 percent. At December 31, 2005, the auction rate was 3.15 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 percent.

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

On January 19, 2005, IPC filed a $245 million shelf registration statement that could be used for first mortgage bonds (including medium-term notes) and debt securities, and when combined with the $55 million remaining from the March 14, 2003 shelf registration, provided for $300 million available in shelf registration form. On August 26, 2005 IPC issued $60 million First Mortgage Bonds 5.30% Series due 2035. Proceeds were invested in short-term investments, which were used on September 9, 2005 to pay at maturity the $60 million First Mortgage Bonds 5.83% Series due 2005. At December 31, 2005, $240 million remained available to be issued on this shelf registration statement

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

On August 30, 2005, IPC settled a forward-starting interest rate swap agreement by making a payment of $2.7 million to the counterparty of the agreement. In accordance with regulatory accounting practices under SFAS 71, IPC is amortizing this amount over the life of its 5.30% First Mortgage Bonds due 2035.

At December 31, 2005 and 2004, the overall effective cost of IPC's outstanding debt was 5.84 percent and 5.69 percent, respectively.

The amount of first mortgage bonds issuable by IPC is limited to a maximum of $1.1 billion and by property, earnings and other provisions of the mortgage and supplemental indentures thereto. IPC may amend the indenture and increase this amount without consent of the holders of the first mortgage bonds. Substantially all of the electric utility plant is subject to the lien of the mortgage. As of December 31, 2005, IPC could issue under the mortgage approximately $560 million of additional first mortgage bonds based on unfunded property additions and $452 million of additional first mortgage bonds based on retired first mortgage bonds. At December 31, 2005, unfunded property additions, which consist of electric property, were approximately $933 million.

At December 31, 2005, IFS had $48 million of debt related to investments in affordable housing with interest rates ranging from 3.65 percent to 8.59 percent due between 2006 and 2010. The investments in affordable housing developments that collateralize this debt had a net book value of $81 million at December 31, 2005. IFS's $14 million Series 2003-1 tax credit note is non-recourse to both IFS and IDACORP. The $8 million Series 2003-2 tax credit note and other outstanding debt are recourse only to IFS.

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

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

6. FAIR VALUE OF FINANCIAL INSTRUMENTS:

The estimated fair value of IDACORP's financial instruments has been determined using available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

Cash and cash equivalents, customer and other receivables, notes payable, accounts payable, interest accrued and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value. The estimated fair values for notes receivable, long-term debt and investments are based upon quoted market prices of the same or similar issues or discounted cash flow analyses as appropriate.

	December 31, 2005				December 31, 2004
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable	$	7,049	$	6,879	$	10,376	$	10,245
Investments		34,510		34,514		67,319		67,479

Liabilities:
Long-term debt	$	1,043,248	$	1,059,199	$	1,061,287	$	1,084,090

IPC
Assets:
Notes receivable	$	7,047	$	6,876	$	8,946	$	8,877
Investments		21,137		21,137		53,155		53,155

Liabilities:
Long-term debt	$	987,045	$	1,003,651	$	987,045	$	1,008,369

7. NOTES PAYABLE:

IDACORP has a $150 million credit facility that expires on March 31, 2010. Under this facility IDACORP pays a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's Investors Service (Moody's) and Standard & Poor's Ratings Services (S&P). Commercial paper may be issued up to the amounts supported by the bank credit facilities.

At December 31, 2005, IPC had regulatory authority to incur up to $250 million of short-term indebtedness. IPC has a $200 million credit facility that expires on March 31, 2010. Under this facility IPC pays a facility fee on the commitment, quarterly in arrears, based on its rating for senior unsecured long-term debt securities without third-party credit enhancement as provided by Moody's and S&P. IPC's commercial paper may be issued up to the amounts supported by the bank credit facilities. There was no commercial paper outstanding at December 31, 2005 or 2004.

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

	2005				2004
			Effective				Effective
	Amount		Interest Rate		Amount		Interest Rate
Commercial Paper	$	60,100		4.47%	$	35,400		2.52%
Notes Payable		-		-		870		3.24%
Balance	$	60,100			$	36,270

8. COMMITMENTS AND CONTINGENCIES:

As of December 31, 2005, IPC had agreements to purchase energy from 87 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 that it has the ability to receive at the facility's requested point of delivery on the IPC system. IPC purchased 715,209 megawatt-hours (MWh) at a cost of $43 million in 2005, 677,868 MWh at a cost of $40 million in 2004 and 654,131 MWh at a cost of $38 million in 2003.

At December 31, 2005, IPC had the following long-term commitments relating to purchases of energy, capacity, transmission rights and fuel:

		2006		2007		2008		2009		2010		Thereafter

Cogeneration and small
	power production		$ 59,719		$70,283		$70,283		$73,753		$73,753		$1,039,377
Power and transmission
	rights		148,818		14,362		8,762		6,193		3,714		13,001
Fuel			43,370		40,496		26,997		18,013		12,010		10,118

In addition, IDACORP has the following long-term commitments for lease guarantees, maintenance and services, and industry related fees.

		2006		2007		2008		2009		2010		Thereafter

Operating leases			$ 3,994		$3,994		$2,700		$ 771		$ 771		$3,716
Maintenance and service
	agreements		37,436		7,513		7,421		2,798		540		114
FERC and other industry
	related fees		10,219		5,278		5,262		5,094		5,094		24,367

IDACORP's expense for operating leases was approximately $4 million, $5 million and $4 million in 2005, 2004 and 2003, respectively.

IPC has agreed to guarantee the performance of reclamation activities at Bridger Coal Company of which Idaho Energy Resources Co., a subsidiary of IPC, owns a one-third interest. This guarantee, which is renewed each December, was $60 million at December 31, 2005. Bridger Coal Company has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. Bridger Coal Company and IPC expect that the fund will be sufficient to cover all such costs. Because of the existence of the fund, the estimated fair value of this guarantee is minimal.

In August 2003, IE sold its forward book of electricity trading contracts to Sempra Energy Trading. As part of the sale, IE entered into an Indemnity Agreement with Sempra Energy Trading guaranteeing the performance of one of the counterparties through 2009. The maximum amount payable by IE under the Indemnity Agreement is $20 million. The indemnity agreement has been accounted for in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and did not have a significant effect on IDACORP's financial statements.

From time to time IDACORP and IPC are a party to 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, taking into account existing reserves, will not have a material adverse effect on IDACORP's or IPC's consolidated financial positions, results of operations or cash flows.

Legal Proceedings
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.

On December 16, 2005, Judge Whaley issued an Order Setting Status Conference wherein, rather than expressly ruling on the companies' motion to dismiss Grays Harbor's amended complaint, he ruled that either Grays Harbor or the companies may, within 45 days of the date of the order, petition the FERC to weigh in on this case in light of "the extensive hearings . . . already undertaken by FERC in the Northwest refund proceeding" which may be relevant to this case. On January 27, 2006 Grays Harbor and the companies jointly filed a stipulation requesting that the court stay the action and extend the time in which the parties may petition the FERC by sixty days to March 31, 2006 stating that the parties felt the case was appropriate for mediation prior to further proceedings. On January 31, 2006 the court approved the stipulation staying the case until March 31, 2006 and setting a status conference for April 14, 2006. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

All defendants, including IPC and IDACORP, moved to dismiss the complaint in lieu of answering it. The motions were based on the ground that the complaint seeks to set alternative electrical rates, which are exclusively within the jurisdiction of the FERC and are barred by the filed-rate doctrine. A hearing on the motion to dismiss was heard on March 26, 2004. On May 28, 2004, the court granted IPC's and IDACORP's motion to dismiss. In June 2004, the Port of Seattle appealed the court's decision to the U.S. Court of Appeals for the Ninth Circuit. On July 19, 2005 the companies filed a motion for summary affirmance of the district court's order dismissing the Port of Seattle's complaint. The Ninth Circuit issued an order denying this motion on October 17, 2005. The appeal has been fully briefed; and oral argument has been scheduled for March 7, 2006. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

If the Court does not grant final approval for the Reliant settlement, Reliant may elect to reactivate its cross-complaint. Similarly, should the Court for any reason fail to approve the Reliant settlement by May 31, 2006, IE and IPC may withdraw from the stipulation agreement by giving ten days' advance written notice. The companies intend to vigorously defend their position in this proceeding and believe this matter will not have a material adverse effect on their consolidated financial positions, results of operations or cash flows.

Western Energy Proceedings at the FERC:
California Power Exchange Chargeback:
As a component of IPC's non-utility energy trading in the State of California, IPC, in January 1999, entered into a participation agreement with the California Power Exchange (CalPX), a California non-profit public benefit corporation. The CalPX, at that time, operated a wholesale electricity market in California by acting as a clearinghouse through which electricity was bought and sold. Pursuant to the participation agreement, IPC could sell power to the CalPX under the terms and conditions of the CalPX Tariff. Under the participation agreement, if a participant in the CalPX defaulted on a payment, the other participants were required to pay their allocated share of the default amount to the CalPX. The allocated shares were based upon the level of trading activity, which included both power sales and purchases, of each participant during the preceding three-month period.

On January 18, 2001, the CalPX sent IPC an invoice for $2 million - a "default share invoice" - as a result of an alleged Southern California Edison payment default of $215 million for power purchases. IPC made this payment. On January 24, 2001, IPC terminated its participation agreement with the CalPX. On February 8, 2001, the CalPX sent a further invoice for $5 million, due on February 20, 2001, as a result of alleged payment defaults by Southern California Edison, Pacific Gas and Electric Company and others. However, because the CalPX owed IPC $11 million for power sold to the CalPX in November and December 2000, IPC did not pay the February 8 invoice. The CalPX later reversed IPC's payment of the January 18, 2001 invoice, but on June 20, 2001 invoiced IPC for an additional $2 million which the CalPX has not reversed. The CalPX owes IPC $14 million for power sold in November and December including $2 million associated with the default share invoice dated June 20, 2001. IPC essentially discontinued energy trading with the CalPX and the California Independent System Operator (Cal ISO) in December 2000.

IPC believes that the default invoices were not proper and that IPC owes no further amounts to the CalPX. IPC has pursued all available remedies in its efforts to collect amounts owed to it by the CalPX. On February 20, 2001, IPC filed a petition with the FERC to intervene in a proceeding that requested the FERC to suspend the use of the CalPX chargeback methodology and provide for further oversight in the CalPX's implementation of its default mitigation procedures.

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

In April 2001, Pacific Gas and Electric Company filed for bankruptcy. The CalPX and the Cal ISO were among the creditors of Pacific Gas and Electric Company. To the extent that Pacific Gas and Electric Company's bankruptcy filing affects the collectibility of the receivables from the CalPX and the Cal ISO, the receivables from these entities are at greater risk.

The FERC issued an order on April 6, 2001 requiring the CalPX to rescind all chargeback actions related to Pacific Gas and Electric Company's and Southern California Edison's liabilities. Shortly after the issuance of that order, the CalPX segregated the CalPX chargeback amounts it had collected in a separate account. The CalPX claimed it was awaiting further orders from the FERC and the bankruptcy court before distributing the funds that it collected under its chargeback tariff mechanism. On October 7, 2004, the FERC issued an order determining that it would not require the disbursement of chargeback funds until the completion of the California refund proceedings. On November 8, 2004, IE, along with a number of other parties, sought rehearing of that order. On March 15, 2005, the FERC issued an order on rehearing confirming that the CalPX is to continue to hold the chargeback funds, but solely to offset seller-specific shortfalls in the seller's CalPX account at the conclusion of the California refund proceeding. Balances are to be returned to the respective sellers at the conclusion of a seller's participation in the refund proceeding. Powerex Corp. filed a petition for review of the Commission's order on March 24, 2005 in the D.C. Circuit. Neither a briefing schedule nor a date for oral argument has been set.

Based upon the settlement agreement filed with the FERC on February 17, 2006 between the California Parties and IE and IPC discussed below in "California Refund," the California Parties have agreed to support a request that the FERC authorize the CalPX to release $2.27 million related to the chargeback proceeding to IE and IPC.

California Refund:
In April 2001, the FERC issued an order stating that it was establishing price mitigation for sales in the California wholesale electricity market. Subsequently, in a June 19, 2001 order, the FERC expanded that price mitigation plan to the entire western United States electrically interconnected system. That plan included the potential for orders directing electricity sellers into California since October 2, 2000 to refund portions of their spot market sales prices if the FERC determined that those prices were not just and reasonable, and therefore not in compliance with the Federal Power Act. The June 19 order also required all buyers and sellers in the Cal ISO market during the subject time frame to participate in settlement discussions to explore the potential for resolution of these issues without further FERC action. The settlement discussions failed to bring resolution of the refund issue and as a result, the FERC's Chief Administrative Law Judge submitted a Report and Recommendation to the FERC recommending that the FERC adopt the methodology set forth in the report and set for evidentiary hearing an analysis of the Cal ISO's and the CalPX's spot markets to determine what refunds may be due upon application of that methodology.

On July 25, 2001, the FERC issued an order establishing evidentiary hearing procedures related to the scope and methodology for calculating refunds related to transactions in the spot markets operated by the Cal ISO and the CalPX during the period October 2, 2000 through June 20, 2001 (Refund Period).

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

The FERC issued its Order on Proposed Findings on Refund Liability on March 26, 2003. In large part, the FERC affirmed the recommendations of its Administrative Law Judge. However, the FERC changed a component of the formula the Administrative Law Judge was to apply when it adopted findings of its staff that published California spot market prices for gas did not reliably reflect the prices a gas market, that had not been manipulated, would have produced, despite the fact that many gas buyers paid those amounts. The findings of the Administrative Law Judge, as adjusted by the FERC's March 26, 2003 order, are expected to increase the offsets to amounts still owed by the Cal ISO and the CalPX to the companies. Calculations remain uncertain because (1) the FERC has required the Cal ISO to correct a number of defects in its calculations, (2) it is unclear what, if any, effect the ruling of the Ninth Circuit in Bonneville Power Administration v. FERC, described below, might have on the ISO's calculations, and (3) 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. On August 8, 2005, the FERC issued an Order establishing the framework for filings by sellers who elected to make such a cost showing. On September 14, 2005 IE and IPC made a joint cost filing, as did approximately thirty other sellers. On October 11, 2005, the California entities filed comments on the companies' cost filing and those made by other parties. IPC and IE submitted reply comments on October 19, 2005. The California entities filed supplemental comments on October 24, 2005 and IPC and IE filed supplemental reply comments on October 27, 2005. IPC and IE are unsure of the impact the FERC's rulings will have on the refunds due from California. However, as to potential refunds, if any, IPC and IE believe their exposure is likely to be offset by amounts due from California entities.

In December of 2005, IE and IPC reached a tentative agreement with the California Parties settling matters encompassed by the California Refund proceeding including IE and IPC's cost filing and refund obligation. On January 20, 2006, the Parties filed a request with the FERC asking that the FERC defer ruling on IE and IPC's cost filing for thirty days so the parties could complete and file the settlement agreement with the FERC. On January 26, 2006, the FERC granted the requested deferral and required that the settlement be filed by February 17, 2006. On February 17, 2006, IE and IPC jointly filed with the California Parties (Pacific Gas & Electric Company, San Diego Gas & Electric Company, Southern California Edison, the California Public Utilities Commission, the California Electricity Oversight Board, the California Department of Water Resources and the California Attorney General) an Offer of Settlement at the FERC. Final comments on the settlement are due to be filed by March 20, 2006, after which the FERC will determine whether to approve the settlement. If the settlement is approved by the FERC, IE and IPC will assign $24.25 million of the rights to accounts receivable from the Cal ISO and CalPX to the California Parties to pay into an escrow account for refunds to settling parties. Amounts from that escrow not used for settling parties and $1.5 million of the remaining IE and IPC receivables which are to be retained by the CalPX are available to fund, at least partially, payment of the claims of any non-settling parties if they prevail in the remaining litigation of this matter. Approximately $10.25 million of the remaining IE and IPC receivables are to be released to IE and IPC. In the fourth quarter of 2005 IE reduced by $9.5 million to $32 million its reserve against these receivables.

IE, along with a number of other parties, filed an application with the FERC on April 25, 2003 seeking rehearing of the March 26, 2003 order. On October 16, 2003, the FERC issued two orders denying rehearing of most contentions that had been advanced and directing the Cal ISO to prepare its compliance filing calculating revised Mitigated Market Clearing Prices and refund amounts within five months. The Cal ISO has since, on a number of occasions, requested additional time to complete its compliance filings. This Cal ISO compliance filing has been delayed until at least March 2006. The Cal ISO is required to update the FERC on its progress monthly.

On December 2, 2003, IE petitioned the U.S. Court of Appeals for the Ninth Circuit for review of the FERC's orders, and since that time, dozens of other petitions for review have been filed. The Ninth Circuit consolidated IE's and the other parties' petitions with the petitions for review arising from earlier FERC orders in this proceeding, bringing the total number of consolidated petitions to more than 100. The Ninth Circuit held the appeals in abeyance pending the disposition of the market manipulation claims discussed below and the development of a comprehensive plan to brief this complicated case. Certain parties also sought further rehearing and clarification before the FERC. On September 21, 2004, the Ninth Circuit convened case management proceedings, a procedure reserved to help organize complex cases. On October 22, 2004, the Ninth Circuit severed a subset of the stayed appeals in order that briefing could commence regarding cases related to: (1) which parties are subject to the FERC's refund jurisdiction under section 201(f) of the Federal Power Act; (2) the temporal scope of refunds under section 206 of the Federal Power Act; and (3) which categories of transactions are subject to refunds. Oral argument was held on April 12-13, 2005. On September 6, 2005 the Ninth Circuit issued its decision in one of the severed cases, Bonneville Power Administration v. FERC. In that decision, the Ninth Circuit concluded that the FERC lacked refund authority over wholesale electric energy sales made by governmental entities and non-public utilities. The time for requests for rehearing was to expire on October 21, 2005, but has been extended until 45 days after the Ninth Circuit issues its decision in the other severed cases. The companies cannot predict whether rehearing will be sought and, if sought, whether it will be granted or what action the FERC might take if the matter is remanded.

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

In June 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE. Effective with this transfer, the outstanding receivables and payables with the CalPX and the Cal ISO were assigned from IPC to IE. At December 31, 2005, 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 $32 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, 2005, IDACORP believes that the future collectibility of these receivables or any potential refunds ordered by the FERC would not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

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

On May 26, 2005 the California Parties filed a motion to lodge additional evidence, primarily audiotapes produced by Enron employees, in the California Refund Proceedings in Docket No. EL00-95. A number of parties, including IDACORP, answered in opposition to that motion.

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

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

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

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

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

On June 25, 2003, the FERC also issued an order instituting an investigation of anomalous bidding behavior and practices in the western wholesale power markets. In this investigation, the FERC was to review evidence of alleged economic withholding of generation. The FERC determined that all bids into the CalPX and the Cal ISO markets for more than $250 per MWh for the time period May 1, 2000 through October 1, 2000 would be considered prima facie evidence of economic withholding. The FERC Staff issued data requests in this investigation to over 60 market participants including IPC. IPC responded to the FERC's data requests. In a letter dated May 12, 2004, the FERC's Office of Market Oversight and Investigations advised that it was terminating the investigation as to IPC. In March 2005, the California Attorney General, the CPUC, the California Electricity Oversight Board and Pacific Gas and Electric Company sought judicial review in the Ninth Circuit of the FERC's termination of this investigation as to IPC and approximately 30 other market participants. IPC has moved to intervene in these proceedings. On April 25, 2005, Pacific Gas and Electric Company sought review in the Ninth Circuit of another FERC order in the same docketed proceeding confirming the agency's earlier decision not to allow the participation of the California Parties in what the FERC characterized as its non-public investigative proceeding.

The February 17, 2006 Offer of Settlement, if approved by the FERC, would terminate the investigations the FERC initiated without finding of wrongdoing by IE or IPC, and would provide for the disposition of the "gaming" settlement.

Pacific Northwest Refund:
On July 25, 2001, the FERC issued an order establishing another proceeding to explore whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001. The FERC Administrative Law Judge submitted recommendations and findings to the FERC on September 24, 2001. The Administrative Law Judge found that prices should be governed by the Mobile-Sierra standard of the public interest rather than the just and reasonable standard, that the Pacific Northwest spot markets were competitive and that no refunds should be allowed. Procedurally, the Administrative Law Judge's decision is a recommendation to the commissioners of the FERC. Multiple parties submitted comments to the FERC with respect to the Administrative Law Judge's recommendations. The Administrative Law Judge's recommended findings had been pending before the FERC, when at the request of the City of Tacoma and the Port of Seattle on December 19, 2002, the FERC reopened the proceedings to allow the submission of additional evidence related to alleged manipulation of the power market by Enron and others. As was the case in the California refund proceeding, at the conclusion of the discovery period, parties alleging market manipulation were to submit their claims to the FERC and responses were due on March 20, 2003. Grays Harbor, whose civil litigation claims were dismissed, as noted above, intervened in this FERC proceeding, asserting on March 3, 2003 that its six-month forward contract, for which performance had been completed, should be treated as a spot market contract for purposes of the FERC's consideration of refunds and is requesting refunds from IPC of $5 million. Grays Harbor did not suggest that there was any misconduct by IPC or IE. The companies submitted responsive testimony defending vigorously against Grays Harbor's refund claims.

In addition, the Port of Seattle, the City of Tacoma and the City of Seattle made filings with the FERC on March 3, 2003 claiming that because some market participants drove prices up throughout the west through acts of manipulation, prices for contracts throughout the Pacific Northwest market should be re-set starting in May 2000 using the same factors the FERC would use for California markets. Although the majority of these claims are generic, they named a number of power market suppliers, including IPC and IE, as having used parking services provided by other parties under FERC-approved tariffs and thus as being candidates for claims of improperly having received congestion revenues from the Cal ISO. On June 25, 2003, after having considered oral argument held earlier in the month, the FERC issued its Order Granting Rehearing, Denying Request to Withdraw Complaint and Terminating Proceeding, in which it terminated the proceeding and denied claims that refunds should be paid. The FERC denied rehearing on November 10, 2003, triggering the right to file for review. The Port of Seattle, the City of Tacoma, the City of Seattle, the California Attorney General, the CPUC and Puget Sound Energy, Inc. filed petitions for review in the Ninth Circuit. These petitions have been consolidated. Grays Harbor did not file a petition for review, although it has sought to intervene in the proceedings initiated by the petitions of others. On July 21, 2004, the City of Seattle submitted to the Ninth Circuit in the Pacific Northwest refund petition for review a motion requesting leave to offer additional evidence before the FERC in order to try to secure another opportunity for reconsideration by the FERC of its earlier rulings. The evidence that the City of Seattle seeks to introduce before the FERC consisted of audio tapes of what purports to be Enron trader conversations containing inflammatory language that have been the subject of coverage in the press. Under Section 313(b) of the Federal Power Act, a court is empowered to direct the introduction of additional evidence if it is material and could not have been introduced during the underlying proceeding. On September 29, 2004, the Ninth Circuit denied the City of Seattle's motion for leave to adduce evidence, without prejudice to renewing the request for remand in the briefing in the Pacific Northwest refund case. Briefing was completed on May 25, 2005; however, no date has been set for oral argument.

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

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

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

Powerex: On August 31, 2004, Powerex Corp., the wholly-owned power marketing subsidiary of BC Hydro, a Crown Corporation of the province of British Columbia, Canada, filed a lawsuit against IE and IDACORP in the U.S. District Court for the District of Idaho. Powerex Corp. alleges that IE breached an oral and written contract regarding the assignment of transmission capacity for electric power by IE to Powerex Corp. for a 14 month period and for intentional interference with Powerex Corp.'s alleged contract with IE. Powerex Corp. seeks damages in the amount of $14,254,811. On November 29, 2004, the companies filed an answer to Powerex Corp.'s complaint, denying all liability to the plaintiffs, and asserting certain affirmative defenses. The parties have completed factual (non-expert) discovery, and the companies filed a motion for summary judgment on February 28, 2006. The parties will participate in a court ordered mediation scheduled for March 23, 2006. If necessary, a trial date for the matter has been set for May 16, 2006. The companies intend to vigorously defend their position in this proceeding but cannot predict the outcome of this matter.

9. STOCK-BASED COMPENSATION:

IDACORP has two employee stock-based compensation plans, the 2000 Long-Term Incentive and Compensation Plan (LTICP) and the 1994 Restricted Stock Plan (RSP). These plans are intended to align employee and shareholder objectives related to its long-term growth. IDACORP also has one non-employee stock-based compensation plan, the Director Stock Plan (DSP). The purpose of the DSPis to increase directors' stock ownership through stock-based director compensation.

The LTICP for officers, key employees and directors, permits the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance units, performance shares and other awards. The RSP permits only the grant of restricted stock or performance-based restricted stock. At December 31, 2005, the maximum number of shares available under the LTICP and RSP were 1,552,802 and 74,839, respectively.

All options granted have 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.

IDACORP's stock option transactions are summarized as follows:

		2005			2004			2003
			Weighted			Weighted			Weighted
		Number	average		Number	average		Number	average
		of	exercise		of	exercise		of	exercise
		shares	price		shares	price		shares	price
Outstanding, beginning of year		1,254,550	$	32.55	1,145,400	$	32.69	846,000	$	38.50
	Granted	208,314		29.53	187,850		31.06	429,000		23.01
	Exercised	(16,400)		22.92	(7,400)		22.92	-		-
	Forfeited	(24,550)		31.53	(71,300)		31.81	(129,600)		38.57
Outstanding, end of year		1,421,914	$	32.24	1,254,550	$	32.55	1,145,400	$	32.69

Exercisable		698,920	$	34.80	472,600	$	35.57	266,000	$	37.91

IDACORP stock option transactions for shares granted to IPC employees are summarized as follows (these amounts are included in the table above):

		2005			2004			2003
			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		952,600	$	32.38	886,800	$	32.48	591,000	$	38.33
	Granted	157,837		29.75	110,500		31.21	343,000		22.95
	Exercised	-		-	(4,200)		22.92	-		-
	Forfeited	(16,300)		30.27	(40,500)		32.27	(47,200)		36.42
Outstanding, end of year		1,094,137	$	32.03	952,600	$	32.38	886,800	$	32.48

Exercisable		559,140	$	34.41	373,600	$	35.42	211,000	$	37.83

The following table summarizes information about stock options outstanding at December 31, 2005:

	Outstanding				Exercisable
				Weighted
		Weighted		average		Weighted
	Number	average		remaining	Number	average
	of	exercise		contractual	of	exercise
Exercise Price Ranges	shares	price		life	shares	price
$22.92 - $31.21	746,514	$	26.65	7.93 years	172,320	$	24.60
$35.81 - $40.31	675,400		38.41	5.37 years	526,600		38.13
IPC Employees
$22.92 - $31.21	575,537	$	26.27	7.87 years	147,340	$	24.09
$35.81 - $40.31	518,600	$	38.43	5.28 years	411,800	$	38.10

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

	2005	2004	2003
Dividend yield	4.07%	3.87%	8.09%
Expected stock price volatility	23%	29%	28%
Risk-free interest rate	4.22%	3.96%	3.94%
Expected option lives	7 years	7 years	7 years
Weighted average fair value of options granted	$5.86	$7.84	$3.90

Restricted stock grants have vesting periods up to four years. Performance share grants have a three-year vesting period with the final award amount dependent on the attainment of cumulative EPS performance goals.

Restricted stock and performance share awards are compensatory awards and IDACORP and IPC accrue compensation expense, which is charged to operations, based upon the market value of the granted shares. For 2005, 2004 and 2003, total compensation accrued under the plans was less than $1 million annually.

IDACORP's restricted stock and performance share activity is summarized as follows:

IDACORP	2005		2004		2003
Shares outstanding - beginning of year	144,722		94,363		87,669
Shares granted	96,708		83,366		52,517
Shares forfeited	(26,328)		(30,931)		(6,679)
Shares issued	(251)		(2,076)		(39,144)
Shares outstanding - end of year	214,851		144,722		94,363
Weighted average fair value of current year stock grants on grant date	$	29.71	$	31.16	$	23.01

IDACORP restricted stock and performance shares granted to IPC employees are summarized as follows: (These amounts are included in the table above.)

IPC	2005		2004		2003
Shares outstanding - beginning of year	121,420		80,454		77,192
Shares granted	87,620		67,056		41,945
Shares forfeited	(25,220)		(24,014)		(1,889)
Shares issued	(251)		(2,076)		(36,794)
Shares outstanding - end of year	183,569		121,420		80,454
Weighted average fair value of current year stock grants on grant date	$	29.75	$	31.15	$	22.95

10. BENEFIT PLANS:

Pension Plans
IPC has a noncontributory defined benefit pension plan covering most employees. The benefits under the plan are based on years of service and the employee's final average earnings. IPC's policy is to fund, with an independent corporate trustee, at least the minimum required under the Employee Retirement Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. IPC was not required to contribute to the plan in 2005, 2004 or 2003, and does not expect to make a contribution in 2006. The market-related value of assets for the plan is equal to market value.

In addition, IPC has a nonqualified, deferred compensation plan for certain senior management employees and directors. This plan was financed by purchasing life insurance policies and investments in marketable securities, all of which are held by a trustee. The cash value of the policies and investments exceed the projected benefit obligation of the plan but do not qualify as plan assets in the actuarial computation of the funded status.

IPC uses a December 31 measurement date for its plans.

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

		Pension Plan				Deferred Compensation Plan
		2005		2004		2005		2004
		(thousands of dollars)
Change in benefit obligation:
	Benefit obligation at January 1	$	374,333	$	339,121	$	38,645	$	38,870
	Service cost		13,129		11,809		1,170		1,358
	Interest cost		21,126		20,437		2,151		2,312
	Actuarial loss (gain)		11,399		16,626		2,799		(1,225)
	Benefits paid		(13,938)		(13,660)		(2,312)		(2,670)
	Plan amendments		-		-		270		-
	Benefit obligation at December 31		406,049		374,333		42,723		38,645
Change in plan assets:
	Fair value at January 1		356,217		335,229		-		-
	Actual return on plan assets		25,774		34,648		-		-
	Employer contributions		-		-		-		-
	Benefit payments		(13,938)		(13,660)		-		-
	Fair value at December 31		368,053		356,217		-		-

Funded status			(37,996)		(18,116)		(42,723)		(38,645)
Unrecognized actuarial loss			43,806		28,491		13,553		11,443
Unrecognized prior service cost			5,118		5,889		1,414		1,372
Unrecognized net transition liability			-		(126)		-		310
Net amount recognized		$	10,928	$	16,138	$	(27,756)	$	(25,520)
Amounts recognized in the statement of
	financial position consist of:
Prepaid (accrued) pension cost		$	10,928	$	16,138	$	(39,268)	$	(36,110)
Intangible asset			-		-		1,414		1,682
Accumulated other comprehensive income			-		-		10,098		8,908
Net amount recognized		$	10,928	$	16,138	$	(27,756)	$	(25,520)
Accumulated benefit obligation		$	340,007	$	316,498	$	39,268	$	36,110

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

	Pension Plan						Deferred Compensation Plan
	2005		2004		2003		2005		2004		2003
	(thousands of dollars)

Service cost	$	13,129	$	11,809	$	10,173	$	1,170	$	1,358	$	1,212
Interest cost		21,126		20,437		19,463		2,151		2,312		2,414
Expected return on assets		(29,690)		(27,935)		(23,445)		-		-		-
Recognized net actuarial loss		-		-		361		689		878		744
Amortization of prior service cost		771		770		729		228		(361)		(345)
Amortization of transition asset		(126)		(263)		(263)		310		613		613
Net periodic pension cost	$	5,210	$	4,818	$	7,018	$	4,548	$	4,800	$	4,638

Changes in the Deferred Compensation Plan minimum liability decreased other comprehensive income by $1 million in 2005, increased other comprehensive income by $1 million in 2004 and decreased other comprehensive income by $1 million in 2003.

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

		2006		2007		2008		2009		2010		2011-2015
Pension Plan	$	14,277	$	14,885	$	15,988	$	17,233	$	18,701	$	120,589
Deferred Compensation Plan	$	2,165	$	2,233	$	2,629	$	2,911	$	3,092	$	16,653

Plan Asset Allocations: IPC's pension plan and postretirement benefit plan weighted average asset allocations at December 31, 2005 and 2004, by asset category are as follows:

		Pension		Postretirement
		Plan		Benefits
Asset Category		2005	2004	2005	2004
Equity securities		66%	69%	-%	-%
Debt securities		21	21	-	3
Real estate		10	9	-	-
Other (a)		3	1	100	97
	Total	100%	100%	100%	100%
(a) The postretirement benefit plan assets are primarily life insurance contracts.

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

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

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

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

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

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

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

Maintain a prudent risk profile consistent with ERISA fiduciary standards.

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.

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

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

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

	2005		2004		2003
Service cost	$	1,392	$	1,400	$	1,207
Interest cost		3,381		3,974		4,017
Expected return on plan assets		(2,486)		(2,294)		(1,930)
Amortization of unrecognized transition obligation		2,040		2,040		2,040
Amortization of prior service cost		(535)		(523)		(563)
Recognized actuarial loss		754		1,489		1,402
Net periodic postretirement benefit cost	$	4,546	$	6,086	$	6,173

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

		2005		2004
Change in accumulated benefit obligation:
	Benefit obligation at January 1	$	71,105	$	67,090
	Service cost		1,392		1,400
	Interest cost		3,381		3,974
	Actuarial (gain) loss		(9,186)		2,201
	Benefits paid		(2,934)		(3,997)
	Plan Amendments		(125)		437
	Benefit obligation at December 31		63,633		71,105

Change in plan assets:
	Fair value of plan assets at January 1		29,723		26,603
	Actual return on plan assets		1,127		2,301
	Employer contributions		800		4,577
	Benefits paid		(1,757)		(3,758)
	Fair value of plan assets at December 31		29,893		29,723

Funded status			(33,740)		(41,382)
Unrecognized prior service cost			(3,677)		(4,087)
Unrecognized actuarial loss			15,978		24,559
Unrecognized transition obligation			14,280		16,320
Accrued benefit obligations included with other deferred credits		$	(7,159)	$	(4,590)

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

The measures of accumulated postretirement benefit obligation at December 31, 2004 and net periodic benefit cost for the years ended December 31, 2004 and 2003, do not reflect any amount associated with the subsidy, because IDACORP and IPC initially determined that the effect of the Medicare Act would not be material. Regulations published on January 28, 2005 provided more flexibility in determining actuarial equivalence to Medicare of the benefits provided by the plan than was initially estimated by IDACORP's and IPC's actuaries. Based on these new regulations, the effect of the Medicare Act is a reduction for IDACORP and IPC of $6 million to the accumulated postretirement benefit obligation at December 31, 2005 and $1 million to the 2005 periodic postretirement benefit cost.

The following table summarizes the expected future benefit payments of the postretirement benefit plan and expected Medicare Part D subsidy receipts (in thousand of dollars):

		2006		2007		2008		2009		2010		2001-2015

Expected benefit payments*		$	4,000	$	4,200	$	4,300	$	4,400	$	4,600	$	25,100
Expected Medicare Part D
	subsidy receipts	$	480	$	488	$	503	$	518	$	530	$	2,936
*Expected benefit payments are net of expected Medicare Part D subsidy receipts.

The assumed health care cost trend rate used to measure the expected cost of benefits covered by the plan was 6.75 percent in 2005 and 2004. A one-percentage point change in the assumed health care cost trend rate would have the following effect (in thousands of dollars):

	1-Percentage-Point
	increase		decrease

Effect on total of cost components	$	242	$	(184)
Effect on accumulated postretirement benefit obligation	$	2,397	$	(1,900)

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
	2005	2004	2005	2004
Discount rate	5.6%	5.75%	5.6%	5.75%
Expected long-term rate of return on assets	8.5%	8.5%	8.5%	8.5%
Rate of compensation increase	4.5%	4.5%	-	-
Medical trend rate	-	-	6.75%	6.75%
Expected working lifetime (years)	-	-	11	11

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
	2005	2004	2005	2004
Discount rate	5.75%	6.15%	5.75%	6.15%
Expected long-term rate of return on assets	8.5%	8.5%	8.5%	8.5%
Rate of compensation increase	4.5%	4.5%	-	-
Medical trend rate	-	-	6.75%	6.75%
Expected working lifetime (years)	-	-	11	11

Employee Savings Plan
IPC has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees. IPC matches specified percentages of employee contributions to the plan. Matching contributions amounted to $4 million in 2005 and $3 million in both 2004 and 2003.

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

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

	2005		2004
Included with regulatory assets	$	-	$	31
Included with other deferred credits	$	3,845	$	3,924

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 2005 and 2004 (in thousands of dollars):

		2005			2004
		Balance		Avg Rate	Balance		Avg Rate
Production		$	1,563,008	2.54%	$	1,482,517	2.51%
Transmission			580,382	2.19		560,303	2.18
Distribution			1,046,880	2.62		992,248	2.59
General and Other			286,797	8.94		289,748	10.02
	Total in service		3,477,067	2.91%		3,324,816	2.96%
Accumulated provision for depreciation			(1,364,640)			(1,316,125)
	In service - net	$	2,112,427		$	2,008,691

IPC has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating utility is responsible for financing its share of construction, operating and leasing costs. IPC's proportionate share of direct operation and maintenance expenses applicable to the projects is included in the Consolidated Statements of Income. These facilities, and the extent of IPC's participation, were as follows at December 31, 2005 (in thousands of dollars):

		Utility		Construction		Accumulated
		Plant In		Work in		Provision for
Name of Plant	Location	Service		Progress		Depreciation		%	MW
Jim Bridger Units 1-4	Rock Springs, WY	$	462,240	$	5,148	$	265,641	33	707
Boardman	Boardman, OR		69,385		454		46,160	10	59
Valmy Units 1 and 2	Winnemucca, NV		311,993		4,042		193,920	50	261

IPC's wholly-owned subsidiary, Idaho Energy Resources Co., is a joint venturer in Bridger Coal Company, which operates the mine supplying coal to the Jim Bridger generating plant. Coal purchased by IPC from the joint venture amounted to $43 million, $47 million and $44 million in 2005, 2004 and 2003, respectively.

IPC has contracts to purchase the energy from four PURPA Qualified Facilities that are 50 percent owned by Ida-West. Power purchased from these facilities amounted to $7 million annually in 2005, 2004 and 2003. See Note 1 for a discussion of the property of IDACORP's consolidated VIEs.

12. SEGMENT INFORMATION:

Information regarding segments is presented in accordance with SFAS 131, "Disclosure about Segments of an Enterprise and Related Information." Based on the criteria outlined in SFAS 131, IDACORP has identified four reportable segments in 2005: utility operations, IFS, ITI and IDACOMM. The utility operations segment has two primary sources of revenue: the regulated operations of IPC and income from Bridger Coal Company, an unconsolidated joint venture also subject to regulation. IPC's regulated operations include the generation, transmission, distribution, purchase and sale of electricity. IFS represents that subsidiary's investments in affordable housing developments and historic preservation projects. ITI is the parent company of IdaTech, a developer of fuel cell technology. IdaTech's research and development expenses were $9 million, $5 million and $5 million in 2005, 2004 and 2003, respectively. IDACOMM provides telecommunications and commercial Internet services.

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

														Consolidated
		Utility		IFS		ITI		IDACOMM		Other		Elimination		Total
		(thousands of dollars)
2005
Revenues		$	837,683	$	1,379	$	4,309	$	12,315	$	3,802	$	-	$	859,488
Operating income
	(loss)		151,654		(513)		(14,819)		(12,085)		3,512		-		127,749
Other income			4,623		368		-		-		786		(318)		5,459
Interest income			3,193		797		468		133		1,426		(1,760)		4,257
Equity method income
	(loss)		10,369		(12,851)		-		-		1,769		-		(713)
Interest expense and
	preferred dividends		54,075		3,691		24		419		4,040		(2,078)		60,171
Income (loss) before
	income taxes		115,764		(15,890)		(14,375)		(12,371)		3,453		-		76,581
Income tax expense
	(benefit)		43,925		(26,801)		(5,308)		617		487		-		12,920
Earnings (loss)			71,839		10,911		(9,067)		(12,988)		2,966		-		63,661
Total assets			3,074,691		139,306		12,968		24,525		184,038		(71,402)		3,364,126
Expenditures for long-
	lived assets		186,079		4,998		510		6,732		-		-		198,319
2004
Revenues		$	822,937	$	1,392	$	7,036	$	9,599	$	3,527	$	-	$	844,491
Operating income
	(loss)		109,038		(544)		(9,789)		(3,194)		(2,260)		-		93,251
Other income
	(expense)		4,516		4,857		(23)		49		4,298		(69)		13,628
Interest income			2,413		655		163		193		894		(895)		3,423
Equity method income
	(loss)		12,313		(12,502)		-		-		1,239		-		1,050
Interest expense and
	preferred dividends		56,167		4,719		-		16		3,201		(964)		63,139
Income (loss) before
	income taxes		72,113		(12,253)		(9,649)		(2,968)		970		-		48,213
Income tax expense
	(benefit)		6,328		(25,566)		(3,841)		(978)		(713)		-		(24,770)
Earnings (loss)			65,785		13,313		(5,808)		(1,990)		1,683		-		72,983
Total assets			2,969,212		145,279		23,155		31,893		156,072		(91,439)		3,234,172
Expenditures for long-
	lived assets		190,379		7,670		482		8,886		101		-		207,518
2003
Revenues		$	782,720	$	-	$	9,278	$	9,826	$	21,178	$	-	$	823,002
Operating income
	(loss)		121,694		(796)		(1,552)		(4,363)		(30,921)		-		84,062
Other income
	(expense)		105		71		-		451		(959)		(221)		(553)
Interest income			3,237		460		82		232		3,802		(3,338)		4,475
Equity method income
	(loss)		11,336		(10,461)		-		-		1,532		-		2,407
Interest expense and
	preferred dividends		59,483		5,821		448		6		2,733		(3,559)		64,932
Income (loss) before
	income taxes		76,889		(16,547)		(1,918)		(3,686)		(29,279)		-		25,459
Income tax expense
	(benefit)		21,728		(26,951)		(558)		(1,892)		(13,446)		-		(21,119)
Earnings (loss)			55,161		10,404		(1,360)		(1,794)		(15,833)		-		46,578
Total assets			2,820,711		141,286		16,466		31,728		165,537		(69,620)		3,106,108
Expenditures for long-
	lived assets		148,494		3		234		1,154		5		-		149,890

13. REGULATORY MATTERS:

Idaho General Rate Case
IPC filed a general rate case in October 2005, requesting the IPUC to approve an annual increase to its Idaho retail base rates of $44 million or 7.8 percent. Base rates primarily reflect IPC's cost of providing electrical service to its customers, including equipment, vehicles and infrastructure.

Oregon Rate Case
On September 21, 2004, IPC filed an application with the Oregon Public Utility Commission (OPUC) to increase general rates an average of 17.5 percent or approximately $4.4 million annually.

The OPUC issued its order on July 29, 2005 authorizing an increase of $0.6 million in annual revenues, an average of 2.37 percent. The significant decrease from IPC's requested amount was primarily related to differences in net power supply costs, which reduced IPC's initial rate request of $4.4 million by $2.4 million.

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

		2005		2004
Idaho PCA current year:
	Deferral for the 2005-2006 rate year	$	-	$	22,778
	Deferral for the 2006-2007 rate year		3,684		-
Irrigation Lost Revenues			-		13,290
Idaho PCA true-up awaiting recovery:
	Authorized May 2004		-		11,415
	Authorized May 2005*		28,567		-
Oregon deferral:
	2001 costs		8,411		12,047
	2005 costs		2,880		-
	Total deferral	$	43,542	$	59,530

*$28 million will be recovered with interest during the 2006-2007 PCA rate year.

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

On April 15, 2005, IPC filed the 2005-2006 PCA with the IPUC with a proposed effective date of June 1, 2005. The application proposed to hold the PCA component of customers' rates at the existing level, which is currently recovering $71 million above base rates. By IPUC order, the 2005 - 2006 PCA includes $12 million in lost revenues and $2 million in related interest resulting from IPC's Irrigation Load Reduction Program that was in place in 2001. IPC proposed to defer recovery of approximately $28 million of power supply costs, or 4.75 percent, for one year to help mitigate the impacts of the increases for the Bennett Mountain Power Plant and the rate case tax settlement adjustments, since all three were proposed to be effective June 1, 2005. The $28 million will be recovered during the 2006-2007 PCA rate year, and IPC will earn a two percent carrying charge on this balance. The IPUC accepted the company's PCA proposal.

On April 15, 2004, IPC filed its 2004-2005 PCA with the IPUC requesting recovery of $71 million above base rates and a proposed effective date of June 1, 2004. On May 25, 2004, the IPUC issued Order No. 29506 approving IPC's filing.

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

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

Oregon: On March 2, 2005 IPC filed for an accounting order to defer net power supply costs for the period of March 1, 2005 through February 28, 2006 in anticipation of continued low water conditions. The forecasted net system power supply costs included in this filing was $169 million, of which $3 million related to the Oregon jurisdiction. IPC is proposing to use the same methodology for this deferral filing that was accepted in 2002 for Oregon's share of IPC's 2001 net power supply expenses. On July 1, 2005, IPC, the OPUC staff and the Citizen's Utility Board entered into a stipulation requesting that the OPUC accept IPC's proposed methodology. Under this methodology, IPC will earn its Oregon authorized rate of return on the deferred balance and will recover the amount through rates in future years, as approved by the OPUC.

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

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

			As of December 31, 2005
												As of
			Remaining			Not		Pending				December
			Amortization	Earning		Earning		Regulatory		2005		31, 2004
Description			Period	a Return		a Return		Treatment		Total		Total
Regulatory Assets:
	Income Taxes			$	-	$	346,117	$	-	$	346,117	$	344,220
	Conservation		2010		14,592		-		-		14,592		17,836
	PCA Deferral		2007		32,251		-		-		32,251		34,193
	Oregon Deferral(1)				11,291		-		-		11,291		12,047
	Asset Retirement
		Obligations			-		8,363		-		8,363		8,372
	Tax Settlement
		Order	2006		4,994		-		-		4,994		7,119
	Irrigation Lost
		Revenues (2)	2007		-		-		-		-		13,290
	Incremental
		Security Costs	2008		575		-		-		575		813
	Other		Various
			thru 2007		41		17		-		58		891
		Total		$	63,744	$	354,497	$	-	$	418,241	$	438,781

Regulatory Liabilities:
	Income Taxes			$	-	$	41,627	$	-	$	41,627	$	40,447
	Conservation		2007		6,535		-		-		6,535		5,205
	Asset Retirement
		Obligations			-		152,683		-		152,683		147,700
	Deferred ITC				-		68,786		-		68,786		66,836
	IPUC Settlement
		Order	2006		4,021		-		-		4,021		13,671
	BPA Settlement		2006		1,393		-		-		1,393		1,833
	OPUC Settlement				-		-		-		-		100
	Emission
		Allowance			-		-		70,034		70,034		-
	Other		Various
			thru 2007		30		-		-		30		62
		Total		$	11,979	$	263,096	$	70,034	$	345,109	$	275,854

(1) Capped at 10 percent increase per year.
(2) Included in PCA amortization balance.

For further information on the asset retirement obligations amounts, see Note 17.

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

14. DERIVATIVE FINANCIAL INSTRUMENTS:

Energy Trading Contracts
The commodity transactions entered into by IE were classified as energy trading contracts or derivatives in accordance with SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" and Emerging Issues Task Force Issue 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." Under SFAS 133 as amended, these contracts are recorded on the balance sheet at fair market value. This accounting treatment is also referred to as mark-to-market accounting. Mark-to-market accounting treatment can create a disconnect between recorded earnings and realized cash flow. Marking a contract to market consists of reevaluating the market value of the entire term of the contract at each reporting period and reflecting the resulting gain or loss in earnings for the period. This change in value represents the difference between the contract price and the current market value of the contract. The change in market value of the contract could result in large gains or losses recorded in earnings at each subsequent reporting period unless there are offsetting changes in value of offsetting contracts. The gain or loss generated from the change in market value of the energy trading contracts is a non-cash event. If these contracts are held-to-maturity, the cash flow from the contracts, and their offsetting contracts, are realized over the life of the contract.

When determining the fair value of marketing and trading contracts, IE used actively quoted prices for contracts with similar terms as the quoted price, including specific delivery points and maturities. To determine fair value of contracts with terms that were not consistent with actively quoted prices IE used, when available, prices provided by other external sources. When prices from external sources were not available, IE determined prices by using internal pricing models that incorporated available current and historical pricing information. Finally, the fair market value of contracts was adjusted for the impact of market depth and liquidity, potential model error and expected credit losses at the counterparty level.

The following table details the gross margin for the energy marketing operations (in thousands of dollars):

			2005		2004		2003
Gross Margin:
	Realized or otherwise settled		$	12	$	82	$	61,183
	Unrealized			(17)		(131)		(42,517)
		Total	$	(5)	$	(49)	$	18,666

15. RESTRUCTURING COSTS:

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

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

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

		Severance		Lease
		and Other		Termination
		Benefits		Costs		Other		Total
Balance at December 31, 2002		$	4,171	$	2,485	$	195	$	6,851
	Amounts accrued		4,379		182		-		4,561
	Amounts paid		(6,594)		(645)		(162)		(7,401)
	Amounts reversed		(149)		-		-		(149)
Balance at December 31, 2003			1,807		2,022		33		3,862
	Amounts accrued		-		28		-		28
	Amounts paid		(1,807)		(657)		-		(2,464)
	Amounts reversed		-		-		(33)		(33)
Balance at December 31, 2004			-		1,393		-		1,393
	Amounts accrued		-		165		-		165
	Amounts paid		-		(495)		-		(495)
	Amounts reversed		-		-		-		-
Balance at December 31, 2005		$	-	$	1,063	$	-	$	1,063

16. INVESTMENTS:

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

			2005		2004
IPC Investments:
	Auction rate securities (available-for-sale)		$	-	$	31,650
	Equity method investment			38,764		25,028
	Available-for-sale equity securities			21,137		21,505
	Executive deferred compensation			6,201		6,002
	Other investments			1,025		808
		Total IPC investments		67,127		84,993
Investments in affordable housing				99,972		108,974
Equity method investments				8,764		8,670
Held-to-maturity debt securities				13,373		14,164
Executive deferred compensation				5,313		5,928
Other investments				30		332
		Total IDACORP investments	$	194,579	$	223,061

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

IFS invests in affordable housing developments that are accounted for in accordance with APB 18, "The Equity Method of Accounting for Investments in Common Stock" and Emerging Issues Task Force Issue 94-1, "Accounting for Tax Benefits Resulting from Investments in Affordable Housing Projects," and are presented as Investments on the Consolidated Balance Sheets. All projects are reviewed periodically for impairment.

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

		2005		2004		2003
Bridger Coal Company (IPC)		$	10,369	$	12,313	$	11,336
Ida-West projects			1,769		1,239		1,532
IFS affordable housing projects			(12,851)		(12,502)		(10,461)
	Total	$	(713)	$	1,050	$	2,407

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

IPC held $32 million of auction rate securities at December 31, 2004. Auction rate securities are long-term instruments whose interest rates or dividends are reset at specific frequencies. The typical reset periods are either 28 or 35 days. The rates or dividends are reset via a Dutch auction. The original maturities of these securities at the time of issuance ranged from 2007 to 2042. IDACORP and IPC did not hold any auction rate securities at December 31, 2005.

Investments classified as held-to-maturity securities are reported at amortized cost. Held-to-maturity securities are investments in debt securities for which the company has the positive intent and ability to hold the securities until maturity. These debt securities have maturities ranging from 2006 through 2025

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

		2005						2004
		Gross		Gross				Gross		Gross
		Unrealized		Unrealized		Fair		Unrealized		Unrealized		Fair
		Gain		Loss		Value		Gain		Loss		Value

Available-for-sale
	securities (IPC)	$	2,925	$	497	$	21,137	$	2,530	$	256	$	53,155
Held-to-maturity debt
	securities (IFS)		354		350		13,377		332		172		14,324

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

	2005		2004		2003

Proceeds from sales	$	120,026	$	266,331	$	14,040
Gross realized gains from sales		2,850		2,044		1,046
Gross realized losses from sales		643		634		1,169

Additionally, these investments are evaluated to determine whether they have experienced a decline in market value that is considered other-than-temporary. IDACORP and IPC analyze securities in loss positions as of the end of each reporting period. Any security with an unrealized loss of more than 20 percent is evaluated for other-than-temporary impairment. A security will generally be written down to market value if it has an unrealized loss of 20 percent or more for more than nine months. If additional information is available that indicates a security is other-than-temporarily impaired, it will be written down prior to the nine-month time period. In the alternative, if a security has been impaired for more than nine months but available information indicates that the impairment is temporary, the security will not be written down. IDACORP and IPC recognized an other-than-temporary impairment of $0.6 million in 2003. This decline is included in other income in the Consolidated Statements of Income. In 2005 and 2004, there were no other-than-temporary declines in market value recorded.

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

	Aggregate		Aggregate		Aggregate		Aggregate
	Unrealized		Related Fair		Unrealized		Related Fair
	Loss		Value		Loss		Value
	Less than 12 months				12 months or longer
2005:
Available for sale equity securities (IPC)	$	215	$	1,731	$	282	$	1,423
Held to maturity debt securities (IFS)		18		1,817		333		4,128

2004:
Available for sale equity securities (IPC)	$	181	$	2,934	$	75	$	362
Held to maturity debt securities (IFS)		97		4,071		75		1,794

The available-for-sale equity securities in unrealized loss positions are diversified investments in common stock of various companies used to fund IPC's Senior Management Security Plan. The held-to-maturity debt securities in unrealized loss positions are bonds, whose market values fluctuate based on the interest rate environment. At December 31, 2005, nine available-for-sale and 11 held-to-maturity securities were in an unrealized loss position. At December 31, 2004, ten available-for-sale and 14 held-to-maturity securities were in an unrealized loss position. At December 31, 2005 two available-for-sale securities had unrealized loss positions of greater than 20 percent. Both securities exceeded 20 percent for fewer than nine months. IDACORP and IPC do not consider these investments to be other-than-temporarily impaired at December 31, 2005 or 2004. Because IDACORP has the ability and intent to hold the debt securities until maturity, it does not consider them to be other-than-temporarily impaired at December 31, 2005 or 2004.

17. ASSET RETIREMENT OBLIGATIONS:

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

In 2005, IDACORP and IPC adopted FIN 47. This Interpretation clarifies that the term "conditional asset retirement obligation," as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional ARO should be recognized when incurred-generally upon acquisition, construction, or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional ARO should be factored into the measurement of the liability when sufficient information exists. FAS 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate the fair value of an ARO. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO.

FIN 47 became effective December 31, 2005. After reviewing the provisions of FIN 47, no significant additional AROs were identified at IPC. One ARO was identified at IDACOMM. Upon adoption, IDACOMM recorded an ARO liability of $0.4 million and an ARO asset of $0.4 million.

The regulated operations of IPC also collect removal costs in rates for certain assets that do not have associated AROs. The adoption of SFAS 143 required IPC to redesignate these removal costs as regulatory liabilities. As of December 31, 2005, IPC had $153 million of such costs recorded as regulatory liabilities on its Consolidated Balance Sheet.

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

	IDACORP				IPC
	2005		2004		2005		2004
Balance at beginning of year	$	9,288	$	7,140	$	9,288	$	7,140
Amount recorded on adoption		440		-				-
Accretion expense		531		421		531		421
Revisions in estimated cash flows		260		1,727		260		1,727
Balance at end of year	$	10,519	$	9,288	$	10,079	$	9,288

18. RELATED PARTY TRANSACTIONS (IPC):

IDACORP
In exchange for the transfer of Energy Marketing to IE in June 2001, IPC received a partnership interest in IE, which was then transferred to IDACORP in exchange for notes receivable from IDACORP totaling approximately $76 million. The notes receivable were due over periods of one to ten years, bore interest at IDACORP's overall variable short-term borrowing rate and were paid in full in 2003.

IPC performs corporate functions such as financial, legal and management services for IDACORP and its subsidiaries. IPC charges IDACORP for the costs of these services based on service agreements and other specifically identified costs. IPC billed IDACORP $4 million, $4 million and $3 million in 2005, 2004 and 2003, respectively, for these services.

IDACORP Energy
In 2003, IPC's sales to IE totaled $2.2 million. There were no purchases or sales between the entities in 2004 or 2005.

IDACOMM
IPC provides project management and engineering services to IDACOMM. IDACOMM also pays joint use fees to IPC. Total fees charged to IDACOMM were $0.3 million per year in 2005, 2004 and 2003.

Ida-West
IPC purchases all of the power generated by four of Ida-West's hydroelectric projects. IPC paid $7 million per year in 2005, 2004 and 2003.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of IDACORP, Inc. and subsidiaries (the "Company") as of December 31, 2005 and 2004, 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, 2005. Our audits also included the consolidated financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of IDACORP, Inc. and subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

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

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 6, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

DELOITTE & TOUCHE LLP

Boise, Idaho
March 6, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have audited the accompanying consolidated balance sheets and statements of capitalization of Idaho Power Company and subsidiary (the "Company") as of December 31, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

Boise, Idaho
March 6, 2006

SUPPLEMENTAL FINANCIAL INFORMATION, UNAUDITED

QUARTERLY FINANCIAL DATA:

The following unaudited information is presented for each quarter of 2005 and 2004 (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

2005
Revenues	$	195,774	$	204,651	$	248,414	$	210,649
Income from operations		34,926		23,811		43,117		25,895
Income tax expense		1,134		498		7,545		3,744
Net income		23,066		9,451		23,617		7,527
Earnings per share of common stock		0.55		0.22		0.56		0.18

2004
Revenues	$	188,189	$	211,872	$	246,677	$	197,752
Income from operations		36,194		15,407		18,933		22,717
Income tax expense (benefit)		4,685		(3,379)		(20,886)		(5,191)
Net income		19,659		12,992		26,067		14,266
Earnings per share of common stock		0.51		0.34		0.68		0.37

Idaho Power Company:

	Quarter Ended
	March 31		June 30		September 30		December 31

2005
Revenues	$	190,460	$	198,888	$	243,503	$	204,832
Income from operations		40,897		29,748		49,259		31,750
Income tax expense		12,472		6,362		19,529		5,562
Net income		21,509		12,876		20,969		16,485
Dividends on preferred stock		-		-		-		-
Earnings on common stock		21,509		12,876		20,969		16,485

2004
Revenues	$	183,326	$	205,693	$	240,219	$	190,271
Income from operations		40,854		18,411		20,396		29,338
Income tax expense (benefit)		13,169		273		(13,981)		6,867
Net income		20,263		8,790		26,995		14,560
Dividends on preferred stock		854		853		3,116		-
Earnings on common stock		19,409		7,937		23,879		14,560

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

None

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure controls and procedures:

IDACORP:

The Chief Executive Officer and Chief Financial Officer of IDACORP, based on their evaluation of IDACORP's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2005, have concluded that IDACORP's disclosure controls and procedures are effective.

IPC:

The Chief Executive Officer and Chief Financial Officer of IPC, based on their evaluation of IPC's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2005, have concluded that IPC's disclosure controls and procedures are effective.

Internal control over financial reporting:

IDACORP:

Management's Annual Report On Internal Control Over Financial Reporting
The management of IDACORP is responsible for establishing and maintaining adequate internal control over financial reporting for IDACORP. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company's principal executive and principal financial officers and effected by the company's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the company are being made only in accordance with the authorizations of management and directors of the company; and

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

IDACORP's management assessed the effectiveness of the company's internal control over financial reporting as of December 31, 2005. In making this assessment, the company's management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2005, IDACORP's internal control over financial reporting is effective based on those criteria.

IDACORP's independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2005 and issued a report, which appears on the next page and expresses an unqualified opinion on management's assessment and on the effectiveness of IDACORP's internal control over financial reporting as of December 31, 2005.

March 6, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited management's assessment, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting, that IDACORP, Inc. and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2005 of the Company and our report dated March 6, 2006 expressed an unqualified opinion on those financial statements and financial statement schedules and included an explanatory paragraph regarding the Company's adoption of Financial Accounting Standards Board Interpretation No. 46(R).

DELOITTE & TOUCHE LLP

Boise, Idaho
March 6, 2006

Idaho Power Company:

Management's Annual Report on Internal Control Over Financial Reporting
The management of Idaho Power Company (IPC) is responsible for establishing and maintaining adequate internal control over financial reporting of IPC. Internal control over financial reporting is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company's principal executive and principal financial officers and effected by the company's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

IPC's management assessed the effectiveness of the company's internal control over financial reporting as of December 31, 2005. In making this assessment, the company's management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2005, IPC's internal control over financial reporting is effective based on those criteria.

IPC's independent registered public accounting firm has audited the financial statements included in this Annual Report on Form 10-K for the year ended December 31, 2005 and issued a report, which appears on the next page and expresses an unqualified opinion on management's assessment and on the effectiveness of IPC's internal control over financial reporting as of December 31, 2005.

March 6, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Idaho Power Company
Boise, Idaho

We have audited management's assessment, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting, that Idaho Power Company and subsidiary (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2005 of the Company and our report dated March 6, 2006 expressed an unqualified opinion on those financial statements and financial statement schedule.

DELOITTE & TOUCHE LLP

Boise, Idaho
March 6, 2006

Changes in Internal Control Over Financial Reporting
There have been no changes in IDACORP's or IPC's internal control over financial reporting during the quarter ended December 31, 2005 requiring dislosure that have materially affected, or are reasonably likely to materially affect, IDACORP's or IPC's internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The portion of IDACORP's definitive proxy statement appearing under the captions "Election of Directors - Nominees For Election - Terms Expire 2009," "Election of Directors - Continuing Directors - Terms Expire 2008," "Election of Directors -Continuing Directors - Terms Expire 2007," "The Board of Directors and Committees - Committees - Audit Committee," "Section 16(a) Beneficial Ownership Reporting Compliance" and "Corporate Governance - Code of Ethics," to be filed pursuant to Regulation 14A for the 2006 Annual Meeting of Shareholders to be held on May 18, 2006 is hereby incorporated by reference.

ITEM 11. EXECUTIVE COMPENSATION

The portion of IDACORP's definitive proxy statement appearing under the caption "Compensation of Directors and Executive Officers" (except the Report of the Compensation Committee and the Performance Graph) to be filed pursuant to Regulation 14A for the 2006 Annual Meeting of Shareholders to be held on May 18, 2006 is hereby incorporated by reference.

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

The portion of IDACORP's definitive proxy statement appearing under the caption "Security Ownership of Directors and Executive Officers" to be filed pursuant to Regulation 14A for the 2006 Annual Meeting of Shareholders to be held on May 18, 2006 is hereby incorporated by reference.

The following table includes information as of December 31, 2005 with respect to equity compensation plans where equity securities of IDACORP may be issued. These plans are the 1994 Restricted Stock Plan (RSP), the IDACORP 2000 Long-Term Incentive and Compensation Plan (LTICP) and the Non-Employee Director Stock Compensation Plan (DSP).

			(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 security
Plan Category			warrants and rights	warrants and rights		reflected in column (a))
Equity compensation
	plans approved by
	shareholders(1)		1,421,914	$	32.24	1,627,641(2)(3)
Equity compensation
	plans not approved
	by shareholders(4)		-	$	-	53,699
		Total	1,421,914	$	32.24	1,681,340

(1)	Consists of the RSP and the LTICP.
(2)	In addition to being available for future issuance upon exercise of options, 1,552,802 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)	74,839 shares remain available for future issuance under the RSP.
(4)	Consists of shares available for future issuance under the DSP.

Equity Compensation Plans Not Approved by IDACORP Shareholders:
The DSP was adopted by the Board of Directors effective May 17, 1999. The purpose of the DSP is to increase directors' stock ownership through stock-based compensation. The DSP initially provided for an annual stock grant in June of each year valued at $6,000 with a maximum number of shares available under the plan of 10,500. Effective January 1, 2000, the DSP was amended to increase the annual grant to stock valued at $8,000. Effective April 1, 2002, the number of shares available under the plan was increased to 100,000 and the annual grant was increased to $16,000 in part to offset the termination of the director's non-qualified deferred compensation plan. On January 20, 2005, the annual grant was increased to stock valued at $40,000 and the grant date changed to February of each year. 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

None

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

IDACORP:

The portion of IDACORP's definitive proxy statement appearing under the caption "Independent Accountant Billings" in the proxy statement to be filed pursuant to Regulation 14A for the 2006 Annual Meeting of Shareholders to be held on May 18, 2006 is hereby incorporated by reference.

IPC:

The following table presents fees billed for professional services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, Deloitte & Touche), for the fiscal years ended December 31, 2005 and 2004. The amounts presented below reflect allocations from IDACORP for IPC's portion of the fees, as well as amounts billed directly to IPC.

			2005		2004
Audit fees			$	704,360	$	760,496
Audit-related fees ⁽¹⁾				47,250		74,243
Tax fees ⁽²⁾				14,045		140,472
All other fees				-		-
Total			$	765,655	$	975,211

⁽¹⁾	Includes fees for audits of IPC's benefit plans, officer certification assistance, Sarbanes-Oxley section 404 readiness assistance in 2004 and work
		in connection with regulatory inquiries.
⁽²⁾	Includes fees for tax compliance and tax consulting in connection with IRS account analysis.

Policy on Audit Committee Pre-Approval
IPC and the Audit Committee are committed to ensuring the independence of the independent registered public accounting firm, both in fact and in appearance. In this regard, on February 4, 2004, the Audit Committee established a pre-approval policy in accordance with applicable securities rules. All fees were pre-approved by the Audit Committee in 2005.

In addition to the audits of IPC's consolidated financial statements, the independent public accounting firm may be engaged to provide certain audit-related, tax and other services. The Audit Committee must pre-approve all services performed by the independent public accounting firm to assure that the provision of those services does not impair the public accounting firm's independence. The services that the Audit Committee will consider include audit services such as attest services, changes in the scope of the audit of the financial statements, and the issuance of comfort letters and consents in connection with financings; audit-related services such as internal control reviews and assistance with internal control reporting requirements; attest services related to financial reporting that are not required by statute or regulation, and accounting consultations and audits related to proposed transactions and new or proposed accounting rules, standards and interpretations; and tax compliance and planning services. Unless a type of service to be provided by the independent public accounting firm has received general pre-approval, it will require specific pre-approval by the Audit Committee. In addition, any proposed services exceeding pre-approved cost levels will require specific pre-approval by the Audit Committee. Under the pre-approval policy, the Audit Committee has delegated to the Chairman of the Audit Committee pre-approval authority for proposed audit and audit-related services. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting.

Any request to engage the independent public accounting firm to provide a service which has not received general pre-approval must be submitted as a written proposal to IPC's Chief Financial Officer with a copy to the General Counsel. The request must include a detailed description of the service to be provided, the proposed fee and the business reasons for engaging the independent public accounting firm to provide the service. Upon approval by the Chief Financial Officer, the General Counsel and the independent public accounting firm that the proposed engagement complies with the terms of the pre-approval policy and the applicable rules and regulations, the request will be presented to the Audit Committee or the Committee Chairman, as the case may be, for pre-approval.

In determining whether to pre-approve the engagement of the independent public accounting firm, the Audit Committee or the Committee Chairman, as the case may be, must consider, among other things, the pre-approval policy, applicable rules and regulations and whether the nature of the engagement and the related fees are consistent with the following principles, as stated in the SEC's adopting release for the rules on auditor independence:

the independent public accounting firm cannot function in the role of management of IPC;

the independent public accounting firm cannot audit its own work; and

the independent public accounting firm cannot serve in any advocacy role on behalf of IPC.

The appendices to the pre-approval policy describe the specific audit, audit related, tax and other services that have the general pre-approval of the Audit Committee. The term of any pre-approval is 12 months from the date of pre-approval, unless the Audit Committee specifically provides for a different period. The Audit Committee will periodically revise the list of pre-approved services, based on subsequent determinations.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1) and (2) Please refer to Part II, Item 8 - - "Financial Statements and Supplementary Data" for a complete listing of all consolidated financial statements and financial statement schedules.

(3) Exhibits.

*Previously Filed and Incorporated Herein by Reference

*2	Agreement and Plan of Exchange between IDACORP, Inc., and IPC dated as of February 2, 1998. File number 333-48031, Form S-4, filed on 3/16/98, as Exhibit 2.

*3(a)	Restated Articles of Incorporation of IPC as filed with the Secretary of State of Idaho on June 30, 1989. File number 33-00440, Post-Effective Amendment No. 2 to Form S-3, filed on 6/30/89, as Exhibit 4(a)(xiii).

*3(a)(i)	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. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(a)(ii).

*3(a)(ii)	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. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(a)(iii).

*3(a)(iii)	Articles of Amendment to Restated Articles of Incorporation of IPC, as amended, as filed with the Secretary of State of Idaho on January 21, 2005. File number 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 3.3.

*3(b)	Amended Bylaws of IPC, amended on January 20, 2005, and presently in effect. File number 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 3.2.

*3(c)	Articles of Share Exchange, as filed with the Secretary of State of Idaho on September 29, 1998. File number 33-56071-99, Post-Effective Amendment No. 1 to Form S-8, filed on 10/1/98, as Exhibit 3(d).

*3(d)	Articles of Incorporation of IDACORP, Inc. File number 333-64737, Amendment No. 1 to Form S-3, filed on 11/4/98, as Exhibit 3.1.

*3(d)(i)	Articles of Amendment to Articles of Incorporation of IDACORP, Inc. as filed with the Secretary of State of Idaho on March 9, 1998. File number 333-64737, Amendment No. 1 to Form S-3, filed on 11/4/98, as Exhibit 3.2.

*3(d)(ii)	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. File number 333-00139-99, Post-Effective Amendment No. 1 to Form S-3, filed on 9/22/98, as Exhibit 3(b).

*3(e)	Amended Bylaws of IDACORP, Inc., amended on January 20, 2005, and presently in effect. File number 1-14456, Form 8-K, filed on 1/26/05 , as Exhibit 3.1.

*4(a)(i)	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. File number 2-3413, as Exhibit B-2.

*4(a)(ii)	IPC Supplemental Indentures to Mortgage and Deed of Trust:

	File number 1-MD, as Exhibit B-2-a, First, July 1, 1939
	File number 2-5395, as Exhibit 7-a-3, Second, November 15, 1943
	File number 2-7237, as Exhibit 7-a-4, Third, February 1, 1947
	File number 2-7502, as Exhibit 7-a-5, Fourth, May 1, 1948
	File number 2-8398, as Exhibit 7-a-6, Fifth, November 1, 1949
	File number 2-8973, as Exhibit 7-a-7, Sixth, October 1, 1951
	File number 2-12941, as Exhibit 2-C-8, Seventh, January 1, 1957
	File number 2-13688, as Exhibit 4-J, Eighth, July 15, 1957
	File number 2-13689, as Exhibit 4-K, Ninth, November 15, 1957
	File number 2-14245, as Exhibit 4-L, Tenth, April 1, 1958
	File number 2-14366, as Exhibit 2-L, Eleventh, October 15, 1958
	File number 2-14935, as Exhibit 4-N, Twelfth, May 15, 1959
	File number 2-18976, as Exhibit 4-O, Thirteenth, November 15, 1960
	File number 2-18977, as Exhibit 4-Q, Fourteenth, November 1, 1961
	File number 2-22988, as Exhibit 4-B-16, Fifteenth, September 15, 1964
	File number 2-24578, as Exhibit 4-B-17, Sixteenth, April 1, 1966
	File number 2-25479, as Exhibit 4-B-18, Seventeenth, October 1, 1966
	File number 2-45260, as Exhibit 2(c), Eighteenth, September 1, 1972
	File number 2-49854, as Exhibit 2(c), Nineteenth, January 15, 1974
	File number 2-51722, as Exhibit 2(c)(i), Twentieth, August 1, 1974
	File number 2-51722, as Exhibit 2(c)(ii), Twenty-first, October 15, 1974
	File number 2-57374, as Exhibit 2(c), Twenty-second, November 15, 1976
	File number 2-62035, as Exhibit 2(c), Twenty-third, August 15, 1978
	File number 33-34222, as Exhibit 4(d)(iii), Twenty-fourth, September 1, 1979
	File number 33-34222, as Exhibit 4(d)(iv), Twenty-fifth, November 1, 1981
	File number 33-34222, as Exhibit 4(d)(v), Twenty-sixth, May 1, 1982
	File number 33-34222, as Exhibit 4(d)(vi), Twenty-seventh, May 1, 1986
	File number 33-00440, as Exhibit 4(c)(iv), Twenty-eighth, June 30, 1989
	File number 33-34222, as Exhibit 4(d)(vii), Twenty-ninth, January 1, 1990
	File number 33-65720, as Exhibit 4(d)(iii), Thirtieth, January 1, 1991
	File number 33-65720, as Exhibit 4(d)(iv), Thirty-first, August 15, 1991
	File number 33-65720, as Exhibit 4(d)(v), Thirty-second, March 15, 1992
	File number 33-65720, as Exhibit 4(d)(vi), Thirty-third, April 1, 1993
	File number 1-3198, Form 8-K, filed on 12/20/93, as Exhibit 4, Thirty-fourth, December 1, 1993
	File number 1-3198, Form 8-K, filed on 11/21/00, as Exhibit 4, Thirty-fifth, November 1, 2000
	File number 1-3198, Form 8-K, filed on 10/1/01, as Exhibit 4, Thirty-sixth, October 1, 2001
	File number 1-3198, Form 8-K, filed on 4/16/03, as Exhibit 4, Thirty-seventh, April 1, 2003
	File number 1-3198, Form 10-Q for the quarter ended 6/30/03, filed on 8/7/03, as Exhibit 4(a)(iii), Thirty-eighth, May 15, 2003
	File number 1-3198, Form 10-Q for the quarter ended 9/30/03, filed on 11/6/03, as Exhibit 4(a)(iii), Thirty-ninth, October 1, 2003
	File number 1-3198, Form 8-K filed 5/10/05, as Exhibit 4, Fortieth, May 1, 2005.

*4(b)	Instruments relating to IPC American Falls bond guarantee (see Exhibit 10(c)). File number 1-3198, Form 10-Q for the quarter ended 6/30/00, filed on 8/4/00, as Exhibit 4(b).

*4(c)(i)	Agreement of IPC to furnish certain debt instruments. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 4(f).

*4(c)(ii)	Agreement of IDACORP, Inc. to furnish certain debt instruments. File number 1-14465, Form 10-Q for the quarter ended 9/30/03, filed on 11/6/03, as Exhibit 4(c)(ii).

*4(d)	Agreement and Plan of Merger dated March 10, 1989, between Idaho Power Company, a Maine Corporation, and Idaho Power Migrating Corporation. Post-Effective Amendment No. 2 to Form S-3, File number 33-00440, filed on 6/30/89, as Exhibit 2(a)(iii).

*4(e)	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. File number 1-14465, Form 8-K, filed on 9/15/98, as Exhibit 4.

*4(f)	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. File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.1.

*4(g)	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. File number 1-14465, Form 8-K, filed on 2/28/01, as Exhibit 4.2.

*4(h)	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. File number 333-67748, Form S-3, filed on 8/16/01, as Exhibit 4.13.

*10(a)	Agreements, dated September 22, 1969, between IPC and Pacific Power & Light Company relating to the operation, construction and ownership of the Jim Bridger Project. File number 2-49584, as Exhibit 5(b).

*10(a)(i)	Amendment, dated February 1, 1974, relating to operation agreement filed as Exhibit 10(a). File number 2-51762, as Exhibit 5(c).

*10(b)	Agreement, dated as of October 11, 1973, between IPC and Pacific Power & Light Company. File number 2-49584, as Exhibit 5(c).

*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. File number 1-3198, Form 10-Q for the quarter ended 6/30/00, filed on 8/4/00, as Exhibit 10(c).

*10(d)	Guaranty Agreement, dated as of August 30, 1974, between IPC and Pacific Power & Light Company. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(r).

*10(e)	Letter Agreement, dated January 23, 1976, between IPC and Portland General Electric Company. File number 2-56513, as Exhibit 5(i).

*10(e)(i)	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. File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(s).

*10(e)(ii)	Amendment, dated September 30, 1977, relating to agreement filed as Exhibit 10(e). File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(t).
*10(e)(iii)	Amendment, dated October 31, 1977, relating to agreement filed as Exhibit 10(e). File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(u).

*10(e)(iv)	Amendment, dated January 23, 1978, relating to agreement filed as Exhibit 10(e). File number 2-62034, as Exhibit 5(v). File number 2-62034, Form S-7 filed on 6/30/78, as Exhibit 5(v).

*10(e)(v)	Amendment, dated February 15, 1978, relating to agreement filed as Exhibit 10(e). File number 2-62034, Form S-7, filed on 6/30/78, as Exhibit 5(w).

*10(e)(vi)	Amendment, dated September 1, 1979, relating to agreement filed as Exhibit 10(e). File number 2-68574, Form S-7, filed on 7/23/80, as Exhibit 5(x).

*10(f)	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. File number 2-68574, Form S-7, filed on 7/23/80, as Exhibit 5(z).

*10(g)	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. File number 2-64910, Form S-7 filed on 6/29/79, as Exhibit 5(y).

*10(h)(i) 1	The Revised Security Plan for Senior Management Employees - a non-qualified, deferred compensation plan, amended and restated effective November 20, 2003. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/04, filed on 5/6/04, as Exhibit 10(h)(i).

*10(h)(ii) 1	2005 IDACORP, Inc. Executive Incentive Plan. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.2.

*10(h)(iii) 1	The 1994 Restricted Stock Plan for officers and key executives of IDACORP, Inc. and IPC effective July 1, 1994. File number 1-3198, Form 10-K for the year ended 12/31/94, filed on 3/10/95, as Exhibit 10(n)(iii).

*10(h)(iv) 1	Form of Restricted Stock Award Agreement. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04, filed on 11/4/04, as Exhibit 10(h)(iv).

*10(h)(v) 1	Form of Performance Share Award Agreement. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04, filed on 11/4/04, as Exhibit 10(h)(v).

*10(h)(vi) 1	The Revised Security Plan for Board of Directors - a non-qualified, deferred compensation plan effective August 1, 1996, revised March 8, 1999, as amended. File number 1-14465, 1-3198, Form 10-K for the year ended 12/31/98, filed on 3/19/99, as Exhibit 10(h)(iv).

*10(h)(vii) 1	IDACORP, Inc. Non-Employee Directors Stock Compensation Plan, as amended on January 20, 2005. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.9.

*10(h)(viii)1	Form of Change in Control Agreement between IDACORP, Inc. and all Officers of IDACORP and IPC. File number 1-14465, Form 10-Q for the quarter ended 9/30/99, filed on 11/5/99, as Exhibit 10(h).

*10(h)(ix) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan, as amended as of March 17, 2005. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as Exhibit 10(h)(ix).

*10(h)(x) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - Form of Stock Option Award Agreement. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 9/30/04, filed on 11/4/04, as Exhibit 10(h)(x).

*10(h)(xi)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan-Form of Restricted Stock Award Agreement (time vesting). File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.4.

*10(h)(xii)1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan-Form of Restricted Stock Award Agreement (performance vesting). File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.5.

*10(h)(xiii)1	Form of Officer Indemnification Agreement as signed by all Officers of IDACORP, Inc. and IPC. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 6/30/04, filed on 8/5/04, as Exhibit 10(h)(viii).

*10(h)(xiv)1	Form of Director Indemnification Agreement as signed by all Directors of IDACORP, Inc. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 6/30/04, filed on 8/5/04, as Exhibit 10(h)(ix).

*10(h)(xv)1	IDACORP, Inc. and Idaho Power Company NEO 2005 Base Compensation Table. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.1.

*10(h)(xvii)1	2005 IDACORP, Inc. Executive Incentive Plan NEO Award Opportunity Chart. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.3.

*10(h)(xviix) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - 2005 Restricted Stock Awards (time vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.6.

*10(h)(xviii) 1	IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan - 2005 Restricted Stock Awards (performance vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.7.

*10(h)(xix) 1	IDACORP, Inc. and IPC 2005 Compensation for Non-Employee Directors of the Board of Directors. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.8.

*10(h)(xx) 1	Jan B. Packwood 2005 Restricted Stock Award Agreement. File number 1-14465, 1-3198, Form 8-K, filed on 1/26/05, as Exhibit 10.10.

*10(h)(xxi)1	Offer of employment letter dated July 9, 2004, to Thomas R. Saldin from IDACORP, Inc. File number 1-14465, 1-3198, Form 10-K for the year ended 12/31/04, filed on 3/9/05, as Exhibit 10(h)(xxiv).

*10(h)(xxii)1	IDACORP, Inc. and IPC 2006 NEO Base Compensation Table. File Number 1-14465, 1-3198, Form 8-K, filed on 1/25/06, as Exhibit 10.1.

*10(h)(xxiii) 1	IDACORP, Inc. 2006 Revised Executive Incentive Plan. File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06, as Exhibit 10.1.

*10(h)(xxiv)1	IDACORP, Inc. 2006 Revised Executive Incentive Plan NEO Award Opportunity Chart. File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06, as Exhibit 10.2

*10(h)(xxv)1	IPC 1994 Restricted Stock Plan - Form of Restricted Stock Agreement (time-vesting). File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06 as Exhibit 10.3.

*10(h)(xxvi)1	IPC 1994 Restricted Stock Plan - Restricted Stock Awards (time-vesting) to NEOs Chart. File number 1-14465, 1-3198, Form 8-K, filed on 2/9/06 as Exhibit 10.4.

*10(i)	Framework Agreement, dated October 1, 1984, between the State of Idaho and IPC relating to IPC's Swan Falls and Snake River water rights. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h).

*10(i)(i)	Agreement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h)(i).

*10(i)(ii)	Contract to Implement, dated October 25, 1984, between the State of Idaho and IPC relating to the agreement filed as Exhibit 10(i). File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(h)(ii).

*10(j)	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. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m).

*10(j)(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. File number 33-65720, Form S-3, filed on 7/7/93, as Exhibit 10(m)(i).

*10(k)	Power Purchase Agreement between IPC and PPL Montana, LLC, dated March 1, 2003 and Revised Confirmation Agreement dated May 9, 2003. File number 1-3198, Form 10-Q for the quarter ended 6/30/03, filed on 8/7/03, as Exhibit 10(k).

*10(l)	$150 Million Five-Year Credit Agreement, dated as of May 3, 2005, among IDACORP, Inc, various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as Exhibit 10(l).

*10(m)	$200 Million Five-Year Credit Agreement, dated as of May 3, 2005, among Idaho Power Company, various lenders, Wachovia Bank, National Association, as joint lead arranger and administrative agent and JP Morgan Chase Bank, NA, as joint lead arranger and syndication agent and Wachovia Capital Markets, LLC and J.P. Morgan Securities Inc., as joint lead arrangers and joint book runners. File number 1-14465, 1-3198, Form 10-Q for the quarter ended 3/31/05, filed on 5/5/05, as Exhibit 10(m).

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)

*21	Subsidiaries of IDACORP, Inc., File number 1-14465, 1-3198, Form 10-K for the year ended 12/31/04, filed on 3/9/05, as Exhibit 21.

23	Consent of Independent Registered Public Accounting Firm.

31(a)	IDACORP, Inc. Rule 13a-14(a) certification.

31(b)	IDACORP, Inc. Rule 13a-14(a) certification.

31(c)	IPC Rule 13a-14(a) certification.

31(d)	IPC Rule 13a-14(a) certification.

32(a)	IDACORP, Inc. Section 1350 certification.

32(b)	IPC Section 1350 certification.

1 Management contract or compensatory plan or arrangement

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF INCOME

				Year Ended December 31,
				2005		2004		2003
				(thousands of dollars)
Income:
	Equity in income of subsidiaries			$	67,946	$	76,482	$	48,163
	Other income				721		535		2,309
			Total income		68,667		77,017		50,472

Expenses:
	Operating expenses				5,189		5,782		5,340
	Interest expense				3,816		1,221		1,088
	Other expense				231		994		1,570
		Total expenses			9,236		7,997		7,998

Income Before Income Taxes					59,431		69,020		42,474

Income Tax Benefit					(4,230)		(3,963)		(4,104)

Net Income				$	63,661		72,983	$	46,578

The accompanying note is an integral part of these statements.

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

					December 31,
					2005		2004
					(thousands of dollars)
Assets

Current Assets:
	Cash and cash equivalents				$	1,234	$	2,637
	Receivables					1,304		1,467
	Taxes receivable					6,897		-
	Deferred income taxes					27,997		28,211
	Other					335		692
			Total current assets			37,767		33,007

Investment in subsidiaries						1,049,276		1,033,141

Other Assets
	Intercompany notes receivable					35,306		35,753
	Other					883		1,396
		Total other assets				36,189		37,149

				Total	$	1,123,232	$	1,103,297



Liabilities and Shareholders' Equity

Current Liabilities:
	Notes payable				$	60,100	$	35,400
	Accounts payable					3,162		3,127
	Taxes accrued					-		4,242
	Other					-		1
			Total current liabilities			63,262		42,770

Other Liabilities:
	Intercompany notes payable					33,265		51,537
	Other					1,454		704
		Total other liabilities				34,719		52,241

Shareholders' Equity						1,025,251		1,008,286

	Total				$	1,123,232	$	1,103,297

The accompanying note is an integral part of these statements.

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

			Year Ended December 31,
			2005		2004		2003
			(thousands of dollars)

Operating Activities:
	Net cash provided by operating activities		$	35,462	$	23,958	$	131,533

Investing Activities:
	Contributions to subsidiaries			-		(100,456)		(40,237)
	Distributions from subsidiaries			-		-		77,792
	Change in intercompany notes receivable			1,271		12,407		66,286
	Other			-		(53)		158
		Net cash provided by (used in) investing activities		1,271		(88,102)		103,999

Financing Activities:
	Issuance of common stock			6,296		115,690		4,123
	Dividends on common stock			(50,690)		(45,838)		(64,726)
	Increase (decrease) in short-term borrowings			24,700		(58,250)		(72,050)
	Change in intercompany notes payable			(17,971)		(4,323)		(41,025)
	Other			(471)		(1,419)		(1,227)
		Net cash provided by (used in) financing activities		(38,136)		5,860		(174,905)

Net increase (decrease) in cash and cash equivalents				(1,403)		(58,284)		60,627

Cash and cash equivalents at beginning of year				2,637		60,921		294

Cash and cash equivalents at end of year			$	1,234	$	2,637	$	60,921

The accompanying note is an integral part of these statements.

IDACORP, Inc.
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

Pursuant to rules and regulations of the Securities and Exchange Commission, the unconsolidated condensed financial statements of IDACORP, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and related notes included in the 2005 Form 10-K, Part II, Item 8.

Accounting for subsidiaries
IDACORP has accounted for the earnings of its subsidiaries under the equity method in the unconsolidated condensed financial statements.

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

Years Ended December 31, 2005, 2004 and 2003

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)

2005:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	43,108	$	1,026	$	-	$		11,056	$		33,078
		Reserve for uncollectible notes			2,578		-		-			699			1,879
		Deferred tax assets			-		1,565		-			-			1,565
Other Reserves:
	Rate refunds				400		-		-			400			-
	Injuries and damages reserve				1,797		10,064		-			10,223			1,638
	Miscellaneous operating reserves				35		2		-			1			36

2004:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	43,210	$	3,010	$	-	$		3,112	$		43,108
		Reserve for uncollectible notes			2,578		-		-			-			2,578
Other Reserves:
	Rate refunds				1,514		-		-			1,114			400
	Injuries and damages reserve				831		1,801		-			835			1,797
	Miscellaneous operating reserves				61		-		-			26			35

2003:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	43,311	$	3,958	$	-	$		4,059	$		43,210
		Reserve for uncollectible notes			-		2,578		-			-			2,578
Other Reserves:
	Rate refunds				-		1,514		-			-			1,514
	Injuries and damages reserve				1,936		111		-			1,216			831
	Miscellaneous operating reserves				-		61		-			-			61

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, 2005, 2004 and 2003

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)

2005:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	1,363	$	1,026	$	-	$	1,556	$		833
Other Reserves:
	Rate refunds				400		-		-		400			-
	Injuries and damages reserve				1,797		6,973		-		7,579			1,191
	Miscellaneous operating reserves				35		2		-		1			36

2004:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	1,466	$	3,010	$	-	$	3,113	$		1,363
Other Reserves:
	Rate refunds				1,514		-		-		1,114			400
	Injuries and damages reserve				831		1,801		-		835			1,797
	Miscellaneous operating reserves				61		-		-		26			35

2003:
Reserves Deducted From
	Applicable Assets:
		Reserve for uncollectible accounts		$	1,566	$	3,958	$	-	$	4,058	$		1,466
Other Reserves:
	Rate refunds				-		1,514		-		-			1,514
	Injuries and damages reserve				1,936		111		-		1,216			831
	Miscellaneous operating reserves				-		61		-		-			61

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 7, 2006

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		Chairman of the Board	March 7, 2006
	Jon H. Miller


By:	/s/Jan B. Packwood		President and Chief Executive	"
	Jan B. Packwood		Officer and Director
			(Principal Executive Officer)
By:	/s/J. LaMont Keen
	J. LaMont Keen		Executive Vice President	"
			and Director

By:	/s/Darrel T. Anderson		Senior Vice President - Administrative	"
	Darrel T. Anderson		Services and Chief Financial Officer
			(Principal Financial Officer)
			(Principal Accounting Officer)

By:	/s/Rotchford L. Barker	By:	/s/Richard G. Reiten	"
	Rotchford L. Barker		Richard G. Reiten
	Director		Director

By:		By:	/s/Joan H. Smith	"
	Jack K. Lemley		Joan H. Smith
	Director		Director

By:	/s/Gary G. Michael	By:	/s/Robert A. Tinstman	"
	Gary G. Michael		Robert A. Tinstman
	Director		Director

By:	/s/Peter S. O'Neill	By:	/s/Thomas J. Wilford	"
	Peter S. O'Neill		Thomas J. Wilford
	Director		Director

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 7, 2006

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

By:	/s/Jon H. Miller		Chairman of the Board	March 7, 2006
	Jon H. Miller


By:	/s/J. LaMont Keen		President and Chief Executive	"
By:	J. LaMont Keen		Officer and Director
			(Principal Executive Officer)

By:	/s/Darrel T. Anderson		Senior Vice President - Administrative	"
	Darrel T. Anderson		Services and Chief Financial Officer
			(Principal Financial Officer)
			(Principal Accounting Officer)

By:	/s/Rotchford L. Barker	By:	/s/Richard G. Reiten	"
	Rotchford L. Barker		Richard G. Reiten
	Director		Director

By:		By:	/s/Joan H. Smith	"
	Jack K. Lemley		Joan H. Smith
	Director		Director

By:	/s/Gary G. Michael	By:	/s/Robert A. Tinstman	"
	Gary G. Michael		Robert A. Tinstman
	Director		Director

By:	/s/Peter S. O'Neill	By:	/s/Thomas J. Wilford	"
	Peter S. O'Neill		Thomas J. Wilford
	Director		Director

By:	/s/Jan B. Packwood
	Jan B. Packwood
	Director

EXHIBIT INDEX

Exhibit Number

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)

23		Consent of Independent Registered Public Accounting Firm.

31(a)		Rule 13a-14(a) certification.

31(b)		Rule 13a-14(a) certification.

31(c)		Rule 13a-14(a) certification.

31(d)		Rule 13a-14(a) certification.

32(a)		Section 1350 certification.

32(b)		Section 1350 certification.

		Exact name of registrants as specified in
Commission		their charters, address of principal executive	IRS Employer
File Number		offices, zip code and telephone number	Identification Number
1-14465		IDACORP, Inc.	82-0505802
1-3198		Idaho Power Company	82-0130980
		1221 W. Idaho Street
		Boise, ID 83702-5627
		(208) 388-2200
State of incorporation: Idaho
Websites: www.idacorpinc.com and www.idahopower.com
			Name of exchange on
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:			which registered
IDACORP, Inc.:	Common Stock, without par value		New York
	Preferred Share Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company:	Preferred Stock

IDACORP, Inc.:
	Large accelerated filer	( X )	Accelerated filer	( )	Non-accelerated filer	( )
Idaho Power Company:
	Large accelerated filer	( )	Accelerated filer	( )	Non-accelerated filer	( X )

Documents Incorporated by Reference:
Part III, Items 10 - 14	Portions of IDACORP, Inc.'s definitive proxy statement to be filed pursuant to Regulation
	14A for the 2006 Annual Meeting of Shareholders to be held on May 18, 2006.

TABLE OF CONTENTS
				Page
Part I

	Item 1.	Business		1-11
	Item 1A.	Risk Factors		11-13
	Item 1B.	Unresolved Staff Comments		13
	Item 2.	Properties		13-14
	Item 3.	Legal Proceedings		15
	Item 4.	Submission of Matters to a Vote of Security Holders		15

	Executive Officers of the Registrant			15

Part II

	Item 5.	Market for Registrant's Common Equity, Related Stockholder
			Matters and Issuer Purchases of Equity Securities	16
	Item 6.	Selected Financial Data		17
	Item 7.	Management's Discussion and Analysis of Financial Condition and
			Results of Operations	17-58
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		58-59
	Item 8.	Financial Statements and Supplementary Data		60
	Item 9.	Changes in and Disagreements with Accountants on Accounting and
			Financial Disclosure	60-114
	Item 9A.	Controls and Procedures		114-119
	Item 9B.	Other Information		119

Part III

	Item 10.	Directors and Executive Officers of the Registrant*		119
	Item 11.	Executive Compensation*		119
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related
			Stockholder Matters*	119-120
	Item 13.	Certain Relationships and Related Transactions*		120
	Item 14.	Principal Accountant Fees and Services*		120-121

Part IV

	Item 15.	Exhibits and Financial Statement Schedules		121-126

	Signatures			133-134



	*Except as indicated in Item 12, IDACORP, Inc. information is incorporated by reference to IDACORP, Inc.'s
	definitive proxy statement for the 2006 Annual Meeting of Shareholders.

X		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
		THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2005

	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934

IDACORP, Inc.:	42,491,802
Idaho Power Company:	39,150,812 all held by IDACORP, Inc.

COMMONLY USED TERMS
AFDC	-	Allowance for Funds Used During Construction
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CSPP	-	Cogeneration and Small Power Production
Energy Act	-	Energy Policy Act of 2005
EPS	-	Earnings per share
ESA	-	Endangered Species Act
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FIN	-	Financial Accounting Standards Board Interpretation
Fitch	-	Fitch, Inc.
FPA	-	Federal Power Act
FSP	-	Financial Accounting Standards Board Staff Position
GAAP	-	Accounting Principles Generally Accepted in the United States of America
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
ITI	-	IDACORP Technologies, Inc.
kW	-	Kilowatt
maf	-	Million acre feet
MD&A	-	Management's Discussion and Analysis of Financial Condition and Results of Operations
Moody's	-	Moody's Investors Service
MW	-	Megawatt
MWh	-	Megawatt-hour
NEPA	-	National Environmental Policy Act of 1996
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PM&E	-	Protection, Mitigation and Enhancement
PURPA	-	Public Utility Regulatory Policies Act of 1978
RFP	-	Request for Proposal
RTO	-	Regional Transmission Organization
S&P	-	Standard & Poor's Ratings Services
SFAS	-	Statement of Financial Accounting Standards
SO₂	-	Sulfur Dioxide
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

			Twelve Months Ended
			December 31,
			(Thousands of Dollars)

			2001		2002		2003		2004		2005

Earnings, as defined:
	Income before income taxes		$	189,860	$	10,525	$	25,459	$	48,213	$	76,582
	Adjust for distributed income of equity
		investees		(1,620)		(2,544)		(20,536)		26,616		4,069
	Equity in loss of equity method
		investments		296		-		-		-		-
	Minority interest in losses of majority
		owned subsidiaries		(612)		(211)		(435)		(48)		-
	Fixed charges, as below			85,034		62,658		68,134		66,137		64,379
		Total earnings, as defined	$	272,958	$	70,428	$	72,622	$	140,918	$	145,030

Fixed charges, as defined:
	Interest charges		$	75,305	$	60,031	$	64,813	$	61,269	$	62,962
	Preferred stock dividends of
		subsidiaries - gross up -
		IDACORP rate		8,142		857		1,915		3,216		-
	Rental interest factor			1,587		1,770		1,406		1,652		1,417
		Total fixed charges, as defined	$	85,034	$	62,658	$	68,134	$	66,137	$	64,379

Ratio of earnings to fixed charges				3.21x		1.12x		1.07x		2.13x		2.25x

Date	March 7, 2006	By:	/s /Jan B. Packwood
			Jan B. Packwood
			President and Chief Executive Officer

Date:	March 7, 2006	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

Quarter Ended