UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K

(Mark One)

X		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2002

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from ................... to ..................................................................

			Exact name of registrants as specified in
Commission			their charters, address of principal executive			IRS Employer
File Number			offices and telephone number			Identification Number
1-14465			IDACORP, Inc.			82-0505802
1-3198			Idaho Power Company			82-0130980
			1221 W. Idaho Street
			Boise, ID 83702-5627
			(208) 388-2200
State or other jurisdiction of incorporation:  Idaho
							Name of exchange on
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:							which registered
IDACORP, Inc.:	Common Stock, without par value						New York and Pacific
	Preferred Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Idaho Power Company:	Preferred Stock

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes  ( X  )  No  (    )

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   (X )

Indicate by check mark whether the registrants are accelerated filers (as defined in Rule 12b-2 of the Act).

IDACORP, Inc.	Yes	( X )	No	(    )
Idaho Power Company		(    )		( X )

 

Aggregate market value of voting and non-voting common stock held by nonaffiliates (June 30, 2002):

IDACORP, Inc.:	$1,038,521,475
Idaho Power Company:	None

 

Number of shares of common stock outstanding at February 28, 2003:

IDACORP, Inc.:	38,201,873
Idaho Power Company:	37,612,351 all held by IDACORP, Inc.

 

Documents Incorporated by Reference:
Part III, Item 10 - 13	Portions of the joint definitive proxy statement of IDACORP, Inc. and Idaho Power Company to be
	filed pursuant to Regulation 14A for the 2003 Annual Meeting of Shareholders to be held on May
	15, 2003.

 

This Combined Form 10-K represents separate filings by IDACORP, Inc. and Idaho Power Company.  Information contained herein relating to an individual registrant is filed by that registrant on its own behalf.  Idaho Power Company makes no representation as to the information relating to IDACORP, Inc.'s other operations.

COMMONLY USED TERMS
AFDC	-	Allowance for Funds Used During Construction
APB	-	Accounting Principles Board
BPA	-	Bonneville Power Administration
Cal ISO	-	California Independent System Operator
CalPX	-	California Power Exchange
CSPP	-	Cogeneration and Small Power Production
DSM	-	Demand-Side Management
EITF	-	Emerging Issues Task Force
EPA	-	Environmental Protection Agency
EPS	-	Earning per share
FASB	-	Financial Accounting Standards Board
FERC	-	Federal Energy Regulatory Commission
FPA	-	Federal Power Act
Garnet	-	Garnet Energy LLC, a subsidiary of Ida-West
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPC	-	Idaho Power Company, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
kW	-	kilowatt
kWh	-	kilowatt-hour
LTICP	-	Long-Term Incentive and Compensation Plan
MD&A	-	Management's Discussion and Analysis
MMbtu	-	Million British Thermal Units
MW	-	Megawatt
MWh	-	Megawatt-hour
OPUC	-	Oregon Public Utility Commission
Overton	-	Overton Power District No. 5
PCA	-	Power Cost Adjustment
PG&E	-	Pacific Gas and Electric Company
PURPA	-	Public Utilities Regulatory Policy Act
REA	-	Rural Electrification Administration
RMC	-	Risk Management Committee
RTOs	-	Regional Transmission Organizations
SCE	-	Southern California Edison
SFAS	-	Statement of Financial Accounting Standards
SPPCo	-	Sierra Pacific Power Company
Valmy	-	North Valmy Steam Electric Generating Plant

 

 

 

 

 

TABLE OF CONTENTS
				Page
Part I
	Item 1.	Business		1-12
	Item 2.	Properties		13-15
	Item 3.	Legal Proceedings		15
	Item 4.	Submission of Matters to a Vote of Security Holders		15
	Executive Officers of the Registrants			16-17
Part II
	Item 5.	Market for the Registrant's Common Stock and Related Stockholder
			Matters	18
	Item 6.	Selected Financial Data		19
	Item 7.	Management's Discussion and Analysis of Financial Condition and
			Results of Operations	20-47
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		48-50
	Item 8.	Financial Statements and Supplementary Data		51-102
	Item 9.	Changes in and Disagreements with Accountants on Accounting and
			Financial Disclosure	102
Part III
	Item 10.	Directors and Executive Officers of the Registrants*
	Item 11.	Executive Compensation*
	Item 12.	Security Ownership of Certain Beneficial Owners and Management
			and Related Stockholder Matters*	103
	Item 13.	Certain Relationships and Related Transactions*
	Item 14.	Controls and Procedures		104
Part IV
	Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		104-111
	Signatures			112-113
	Certifications			114-117
	Exhibit Index			118
	*Incorporated by reference, except for the Equity Compensation Plan information in Item 12.

 

 

 

 

 

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SAFE HARBOR STATEMENT
This Form 10-K contains "forward-looking statements" intended to qualify for safe harbor from liability established by the Private Securities Litigation Reform Act of 1995.  Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-K at Part II, Item 7- "Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) - Forward-Looking Information."  Forward-looking statements are all statements other than statements of historical fact, including without limitation those that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," and similar expressions.

PART I - IDACORP, Inc. and Idaho Power Company

ITEM 1.  BUSINESS

OVERVIEW:

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

IDACORP announced in 2002 that IE, a marketer of electricity and natural gas, would wind down its operations.

IDACORP's other subsidiaries include:

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

IdaTech - - developer of integrated fuel cell systems;

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

Velocitus - - commercial and residential Internet service provider; and

IDACOMM - - provider of telecommunications services.

 

At December 31, 2002, IDACORP had 1,942 full-time employees.  Of these employees, 1,700 are employed by IPC.

IDACORP has identified two reportable business segments, the regulated utility operations of IPC and the energy marketing activities of IE.  IPC and IE contributed 94 percent and five percent to consolidated operating revenues, respectively, during the year ended December 31, 2002.  Financial information relating to amounts of sales, revenue, net income and total assets of IDACORP's operating segments is presented in Note 12 to the Consolidated Financial Statements and below in "Utility Operations" and "Energy Marketing."

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

UTILITY OPERATIONS:

IPC was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. IPC is involved in the generation, purchase, transmission, distribution and sale of electric energy in a 20,000 square mile area in southern Idaho and eastern Oregon, with an estimated population of 855,000.  IPC holds franchises in 70 cities in Idaho and nine cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and three counties in Oregon.  As of December 31, 2002, IPC supplied electric energy to over 412,000 general business customers.

IPC owns and operates 17 hydroelectric power plants and one natural gas-fired plant and shares ownership in three coal-fired generating plants.  These generating plants and their capacities are listed in Item 2 - "Properties."  IPC's coal-fired plants are in Wyoming, Oregon and Nevada, and use low-sulfur coal from Wyoming and Utah.

IPC relies heavily on hydroelectric power for its generating needs and is one of the nation's few investor-owned utilities with a predominantly hydroelectric generating base.  Because of its reliance on hydro generation, IPC's generation operations can be significantly affected by the weather.  The availability of inexpensive hydroelectric power depends on snowpack in the mountains above IPC's hydro facilities, precipitation and other weather and streamflow management considerations. When hydroelectric generation decreases and/or customer demand increases, IPC increases its use of more expensive thermal generation and purchased power.

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

IPC's principal commercial and industrial customers are involved in food processing, electronics and general manufacturing, lumber, beet sugar refining and the skiing industry.  FMC/Astaris, previously IPC's largest volume customer, closed its Pocatello manufacturing plant late in 2001.  IPC entered into a load reduction agreement with FMC/Astaris in 2001.  See further discussion of FMC/Astaris in Part II, Item 7 - "MD&A - REGULATORY ISSUES - FMC/Astaris Settlement Agreement."

Regulation
IPC is under the regulatory jurisdiction (as to rates, service, accounting and other general matters of utility operation) of the FERC, the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC).  IPC is also under the regulatory jurisdiction of the IPUC, OPUC and the Public Service Commission of Wyoming as to the issuance of securities.  IPC is subject to the provisions of the Federal Power Act  (FPA) as a "licensee" and "public utility" as therein defined.  IPC's retail rates are established under the jurisdiction of the state regulatory agencies and its wholesale and transmission rates are regulated by the FERC (see "Rates" below).  Pursuant to the requirements of Section 210 of the Public Utilities Regulatory Policy Act of 1978 (PURPA), the state regulatory agencies have each issued orders and rules regulating IPC's purchase of power from cogeneration and small power production (CSPP) facilities.

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

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

Rates
The rates IPC charges to its general business customers are determined by the various regulatory authorities.  Approximately 97 percent of IPC's general business revenue comes from customers in Idaho.  The rates charged to these customers are adjusted annually by a Power Cost Adjustment (PCA) mechanism.  The PCA adjusts rates to reflect the changes in costs incurred by IPC to supply power.  Throughout the year, IPC compares its actual power supply costs to the amounts it is recovering in rates.  Most, but not all, of this difference is deferred and included in the calculation of rates for future years. See further discussion of rates in Part II, Item 7 - "MD&A - REGULATORY ISSUES - Deferred Power Supply Costs," and Note 13 to the Consolidated Financial Statements.

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

IPC's system is dual peaking, with the larger peak demand generally occurring in the summer.  The system peak demand for 2002 was 2,963 megawatts (MW), set on July 12, 2002.  Peak demands in 2001 and 2000 were 2,570 MW and 2,919 MW, respectively.  IPC expects total system energy requirements to grow 3.4 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
		2002		2001		2000		2002		2001		2000
Hydroelectric		6,069		5,638		8,500		45%		43%		52%
Thermal		7,286		7,622		7,701		55		57		48
	Total system generation	13,355		13,260		16,201		100%		100%		100%

 

The amounts of electricity IPC is able to generate from its hydro plants depend on a number of factors, primarily snowpack in the mountains above its hydro facilities, reservoir storage and streamflow conditions.  When these factors are favorable, IPC can generate more electricity using its hydroelectric plants.  When these factors are unfavorable, IPC must increase its reliance on more expensive thermal plants and purchased power.

Below normal streamflow conditions in 2002 yielded a system generation mix of 45 percent hydro and 55 percent thermal.  Under normal streamflow conditions, IPC's system generation mix is approximately 57 percent hydro and 43 percent thermal.

Current Snake River basin snowpack numbers suggest that streamflow conditions for 2003 will remain below normal.  IPC's March 2003 accumulations were 78 percent of normal, compared to 85 percent at the same time a year earlier.  With snowpack and upstream reservoir storage below normal, IPC is expecting its fourth consecutive year of below normal water conditions.

Seasonal exchanges of winter-for-summer power are included among the contracted resources to maximize the firm load carrying capability.  An exchange arrangement is currently in place with NorthWestern Energy under a contract that expires in December 2003.

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

Garnet Power Purchase Agreement:  IPC and Garnet Energy LLC (Garnet), a wholly-owned subsidiary of Ida-West, entered into a power purchase agreement (PPA) on December 14, 2001 for IPC to purchase energy produced by Garnet's proposed natural gas generation facility.  IPC filed an application with the IPUC for an order approving the PPA and an accounting order authorizing the inclusion in the PCA of power supply expenses associated with the purchase of capacity and energy from Garnet.  Prior to the actual hearing date, Garnet informed IPC that there was a substantial likelihood that it would be unable to obtain the financing at acceptable terms necessary to construct the facility.

On July 24, 2002, the IPUC closed the proceeding involving IPC's petition to enter into a PPA with Garnet and directed IPC to return in 90 days with a report on the status of Garnet's progress in obtaining financing for the project and how IPC proposed to meet future power requirements if the Garnet facility is not built.  On October 30, 2002, IPC submitted its compliance report to the IPUC, which included (1) Ida-West's notification that due to dramatic changes in the electricity industry, financing the project on acceptable terms under the PPA was impracticable, (2) Ida-West's offering of three alternatives to allow the project to go forward and (3) IPC's revised plan for meeting future load requirements absent the PPA associated with the Garnet project, including wholesale power purchases, energy exchanges, obtaining certain transmission rights or constructing or acquiring generation resources located in IPC's service territory.  Following the IPUC's acceptance of the 2002 Integrated Resource Plan (IRP) (see below), IPC continues to work on identifying and securing resources necessary to meet future power requirements.  The original Garnet PPA was mutually terminated on March 5, 2003, however, the site remains viable as a future generation development.

Ida-West had capitalized $11 million related to the Garnet project as of third quarter 2002.  During fourth quarter 2002, Ida-West recorded an $8 million partial write-down of its investment in equipment for this project.  This partial write-down reflects the drop in prices for and increased availability of generating equipment due to the collapse of the merchant power plant development business.

Integrated Resource Plan:  Every two years, IPC is required to file with the IPUC and OPUC an IRP, a comprehensive look at IPC's present and future demands for electricity and plans for meeting that demand.  The 2002 IRP identified the need for additional resources to address potential electricity shortfalls within IPC's utility service territory by mid-2005.  The new resources expected to be in place at that time were the previously identified 250 MW power purchase from the Garnet project, an additional 100 MW generation resource to be determined and a 100 MW transmission upgrade to increase import capability.  These resources would be used to satisfy energy demand during IPC's peak periods.  Prior to 2005, IPC will continue to use purchases from the energy markets as necessary to meet short-term energy needs.

The IPUC Staff and several other interested parties filed comments responding to IPC's proposed 2002 IRP.  The comments urge the IPUC not to acknowledge the IRP until (1) the Garnet issue is resolved, and (2) IPC provides additional detail on potential conservation measures that could be implemented.  IPC filed reply comments on October 30, 2002 addressing those issues.  The above mentioned Garnet compliance report, submitted to the IPUC on October 30, 2002, was included in those reply comments by reference.  On February 11, 2003, the IPUC issued Order No. 29189, which accepted and acknowledged IPC's 2002 IRP as modified and directed IPC to implement certain changes in its 2004 IRP related to both the public process and the evaluation of demand-side options.  The accepted IRP indicated the purchase of 100 MW from the wholesale market for IPC's retail customers during June, July, November and December.  On February 24, 2003, IPC issued a formal Request for Proposals seeking bids for the construction of up to 200 MW of additional generation to support the growing seasonal demand for electricity in IPC's service area.  Notice of an intent to bid must be submitted to IPC by March 14, 2003.

CSPP Purchases:  As a result of the enactment of the PURPA and the adoption of avoided cost standards by the IPUC and OPUC, IPC has entered into contracts for the purchase of energy from private developers.  Because IPC's service territory encompasses substantial irrigation canal development, forest product production facilities, mountain streams and food processing facilities, considerable amounts of energy are available from these sources.  Such energy comes from hydropower producers who own and operate small plants and from cogenerators converting waste heat or steam from industrial processes into electricity.  IPC is currently purchasing energy from 67 on-line CSPP facilities with contracts ranging from one to 30 years.  Under these contracts IPC is required to purchase all of the output from these facilities.  During 2002, IPC purchased 692,414 Megawatt hours (MWh) from these projects at a cost of $44 million, resulting in a blended price of 6.3 cents per kilowatt hour.

In 2002, the IPUC issued various orders impacting the terms and conditions available for new CSPP projects.  Currently, new projects up to ten MW are eligible for Published Avoided Costs for up to a 20-year contract term.  IPC is required to negotiate PPAs with all qualifying CSPP projects greater than ten MW.

Wholesale Power Sales:  IPC has four firm wholesale power sales contracts and one wholesale contract for load following services.  These contracts are for various amounts of energy, up to 36 average MW, and are of various lengths expiring between 2003 and 2005.  As these contracts expire, IPC will use this power to meet its system requirements.

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

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

Fuel
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-third interest in the Bridger Coal Company, which owns the Jim Bridger mine supplying coal to the Jim Bridger generating plant in Wyoming.  The mine, located near the Jim Bridger plant, operates under a long-term sales agreement that provides for delivery of coal over a 51-year period ending in 2025.  The Jim Bridger mine has sufficient reserves to provide coal deliveries 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 allows the plant to take advantage of potentially lower-cost coal from outside mines for tonnage requirements above established contract minimums.

SPPCo, with whom IPC is a joint (50/50) participant in the ownership and operation of the North Valmy Steam Electric Generating Plant (Valmy), has a long-term coal contract with Southern Utah Fuel Company, a subsidiary of Canyon Fuel Co., LLC.  This contract, which expires on June 30, 2003, calls for the delivery of up to 17.5 million tons of low-sulfur coal from a mine near Salina, Utah, for Valmy Unit No. 1.

SSPCo has signed an agreement with Arch Coal Sales Company, Inc. to supply coal to the Valmy plant from 2002 through 2006.  This agreement will provide fuel to the plant following the expiration of the above contract with Southern Utah Fuel Company.  IPC is obligated to purchase one-half of the coal, ranging from approximately 515,000 tons to 762,500 tons annually, under the Arch Coal Sales Company agreement.

Water Rights
Except as discussed below, IPC has acquired valid water rights under applicable state law for all waters used in its hydroelectric generating facilities.  In addition, IPC holds water rights for domestic, irrigation, commercial and other necessary purposes related to other land and facility holdings within the state.  The exercise and use of all of these water rights are subject to prior rights and, with respect to certain hydroelectric facilities, IPC's water rights for power generation are subordinated to future upstream diversions of water for irrigation and other recognized consumptive uses.

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

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

See also Item 2 - "Properties," and Part II, Item 7 - "MD&A - REGULATORY ISSUES - Relicensing of Hydroelectric Projects."

Environmental Regulation
Environmental regulation at the federal, state, regional and local levels is having a continuing impact on IPC's operations due to the cost of installation and operation of equipment and facilities required for compliance with such regulations and the modification of system operations to accommodate such regulation.

Based upon present environmental laws and regulations, IPC estimates its 2003 capital expenditures for environmental matters, excluding Allowance for Funds Used During Construction (AFDC), will total $27 million.  Studies and measures related to environmental concerns at IPC's hydro facilities account for $23 million and investments in environmental equipment and facilities at the thermal plants account for $4 million.  From 2004 through 2005, environmental-related capital expenditures, excluding AFDC, are estimated to be $32 million.  Anticipated expenses related to IPC's hydro facilities account for $25 million and thermal plant expenses are expected to total $7 million.

IPC anticipates $12 million in annual operating costs for environmental facilities during 2003.  Hydro facility expenses account for $8 million of this total and $4 million is related to thermal plant operating expenses.  From 2004 through 2005, total environmental related operating costs are estimated to be $25 million.  Anticipated expenses related to the hydro facilities account for $17 million and thermal plant expenses are expected to total $8 million during this period.

Clean Air:  IPC has analyzed the Clean Air Act legislation and its effects upon IPC and its customers.  IPC's coal-fired plants in Oregon and Nevada already meet the federal emission rate standards for sulfur dioxide (SO₂) and IPC's coal-fired plant in Wyoming meets that state's even more stringent SO₂ regulations.  IPC has sufficient SO₂ allowances to provide compliance for all three coal-fired facilities and its Danskin natural gas-fired facility.  At the end of 2002, IPC had 59,000 allowances in excess of the amount needed for Clean Air Act compliance.  Currently, IPC has been granted an annual allotment of allowances ranging from 15,524 to 72,713 through 2032.  These amounts are in excess of IPC's annual compliance requirements of 13,600.  Any excess allowances owned by IPC may be held for future use as they do not expire.  Accordingly, IPC does not foresee any material adverse effects upon its operations with regard to SO₂ emissions.

In July 1997, the Environmental Protection Agency (EPA) announced the National Ambient Air Quality Standards for ozone and Particulate Matter (PM) and in July 1999, announced regional haze regulations for protection of visibility in national parks and wilderness areas.  On May 14, 1999, a federal court ruling blocked implementation of these standards.  In November 2000, the EPA appealed to the U.S. Supreme Court to reconsider that decision.  The Supreme Court has ruled in favor of the EPA.  The EPA has not yet implemented tighter regulations on PM, regional haze or ozone.  It is anticipated that new regulations will be in place by 2005.  The impacts of tighter ozone, PM and regional haze regulations on IPC's thermal operations are not known at this time.

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

The Danskin gas turbine plant in Mountain Home, Idaho is operating in compliance with a "permit to construct" issued by the Idaho Department of Environmental Quality (DEQ).  IPC has applied for a Title V Operating Permit from the Idaho DEQ expected during mid to late 2003.  The units are fitted with dry-low-NO_x burners and a continuous emissions monitoring system.  This should ensure that the facility will operate within the permitted federal and state NO_x and carbon monoxide limits.

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

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

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

IPC owns and finances the operation of anadromous fish hatcheries and related facilities to mitigate the effects of its hydroelectric dams on fish populations.  In connection with its fish facilities, IPC sponsors ongoing programs for the control of fish disease and improvement of fish production.  IPC's anadromous fish facilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs continue to be operated by the Idaho Department of Fish and Game.  At December 31, 2002, the investment in these facilities was $10 million and the annual cost of operation pursuant to FERC License 1971 was $3 million.

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

Hazardous/Toxic Wastes and Substances:  Under the Toxic Substances Control Act (TSCA), the EPA has adopted regulations governing the use, storage, inspection and disposal of electrical equipment that contain polychlorinated biphenyls (PCBs).  The regulations permit the continued use and servicing of certain electrical equipment (including transformers and capacitors) that contain PCBs.  IPC continues to meet all federal requirements of the TSCA for the continued use of equipment containing PCBs.  IPC continues to eliminate PCBs as part of its long-term strategy.  This program will save costs associated with the long-term monitoring and testing of equipment and grounds for PCB contamination as well as being good for the environment.  Total costs for the identification and disposal of PCBs from IPC's system were less than $1 million annually from 2000 to 2002.  IPC believes that all generation facilities are presently PCB-free.

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.  In 1999, the Oregon legislature passed legislation restructuring the electric utility industry, but exempted IPC's service territory.

Wholesale:  The 1992 National Energy Policy Act (Energy Act) and the FERC's rulemaking activities have established the regulatory framework to open the wholesale energy market to competition.  The Energy Act permits utilities to develop independent electric generating plants for sales to wholesale customers, and authorizes the FERC to order transmission access for third parties to transmission facilities owned by another entity.  The Energy Act does not, however, permit the FERC to require transmission access to retail customers.  Open-access transmission for wholesale customers provides energy suppliers with opportunities to sell and deliver electricity at market-based prices.

In December 1999, the FERC, in its landmark Order No. 2000, said that all companies with transmission assets must file to form RTOs or explain why they cannot.  Order No. 2000 is a follow up to Order Nos. 888 and 889 issued in 1996, which required transmission owners to provide non-discriminatory transmission service to third parties.  By encouraging the formation of RTOs, the FERC seeks to further facilitate the formation of efficient, competitive wholesale electricity markets.

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

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

In July 2002, the FERC issued a Notice of Proposed Rulemaking (NOPR) on Standard Market Design for regulated utilities.  If implemented as proposed, the NOPR will substantially change how wholesale markets operate throughout the United States.  The proposed rulemaking expands the FERC's intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets.  The proposed rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff.  The proposed rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets to manage congestion.  The market would be administered by RTOs, or Independent Transmission Providers.  RTOs would also be responsible for putting together regional plans that identify opportunities to construct new transmission, generation or demand-side programs to reduce transmission constraints and meet regional energy requirements.  Finally, the proposed rule envisions the development of regional market monitors responsible for ensuring that individual participants do not exercise unlawful market power.  Comments to the proposed rules were due during the last months of 2002 and additional comments are due the first part of 2003.  The FERC currently anticipates that the final rules will be in place in mid-2003 and the contemplated market changes will take place in 2003 and 2004.

Utility Operating Statistics
The following table presents IPC's revenues and energy use for the last three years:

			Years Ended December 31,
			2002			2001			2000
Revenues (thousands of dollars)
	Residential		$	305,827		$	260,251		$	225,336
	Commercial			196,454			164,019			132,023
	Industrial			176,648			154,318			133,171
	Irrigation			93,106			72,020			74,827
		Total general business		772,035			650,608			565,357
	Off system sales			55,031			219,966			229,986
	Other			39,981			41,738			40,319
		Total	$	867,047		$	912,312		$	835,662
Energy use (thousands of MWh)
	Residential			4,387			4,307			4,393
	Commercial			3,460			3,380			3,404
	Industrial			3,226			3,925			4,808
	Irrigation			1,821			1,419			1,993
		Total general business		12,894			13,031			14,598
	Off system sales			2,069			2,387			4,529
		Total		14,963			15,418			19,127

 

ENERGY MARKETING:

In January 1997, IPC began implementing a strategy to become a competitive energy provider throughout the western markets.  In order to compete as an energy provider of choice, IPC built a trading operation to participate in the electricity, natural gas and other related markets.  In 1997, IPC developed natural gas trading operations that were transferred to IE in 1999.  In June 2001, IPC transferred its non-utility wholesale electricity marketing operations to IE.  Over the last six years IDACORP, through IPC then through IE, marketed electricity and natural gas, and offered risk management and asset optimization services to wholesale customers in 31 states and two Canadian provinces.

Wind Down of Energy Marketing
IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations, stating that IE would not seek new electric customers; would limit its maximum value at risk to less than $3 million; would target a reduction of working capital requirements to less than $100 million by the end of 2003; and would reduce its workforce at its Boise operations by approximately 50 percent.  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, and because of its link to the natural gas platform, would shut down its natural gas trading operation in Houston by March 2003.  The announcement concluded that IE's continued wind down of its energy marketing operations would result in additional workforce reductions at IE's Boise operations through mid-2003.  Since the June 21, 2002 announcement, IE has reduced its workforce by over 60 percent and will continue to reduce its workforce as contractual obligations terminate.

See further discussion of energy marketing wind down in Part II, Item 7 - "MD&A - RESULTS OF OPERATIONS - Energy Marketing" and Note 13 to the Consolidated Financial Statements and Note 16 to the Consolidated Financial Statements of IPC.

Risk Management
When buying and selling energy, the volatility of energy prices can have a significant negative impact on profitability if not appropriately managed.  Also, counterparty creditworthiness is key to ensuring that transactions entered into can withstand potentially dramatic market fluctuations.  To manage the risks inherent in the energy commodity industry, IE's Risk Management Committee (RMC), comprised of IDACORP and IE officers, oversees IE's risk management program as defined in the risk management policy.  The program is intended to manage the impact to earnings caused by the volatility of energy prices by mitigating commodity price risk, credit risk and other risks related to the energy commodity business.

To manage the risks inherent in its portfolio, IE has established risk limits.  Market and credit risk is measured and reported daily to the members of the RMC.   Other tools used to manage credit risk are the holding of collateral in the form of cash or letters of credit and the use of margining agreements with counterparties when credit risk exceeds certain pre-determined thresholds.  Because of the volatile nature of energy market prices, margining agreements can require the posting of large amounts of cash between counterparties to hold as collateral against the value of the energy contracts.  This practice mitigates credit risk but increases the need for cash or other liquid securities to ensure the ability to meet all margin requirements when the markets are most volatile.

At year-end 2002, 63 percent of the credit exposure related to IE's unrealized positions was with investment grade counterparties, two percent was with non-investment grade counterparties and the remaining 35 percent was with non-rated counterparties.  The majority of the non-rated entities are municipalities, public utility districts and electric cooperatives.

See further discussion in Part II, Item 7A - "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK."

Supply
IE's supply of electricity and natural gas is purchased directly from producers, including IPC until August 2002, and other energy marketers. Sales of energy are made to other marketers, investor owned utilities, municipalities and cooperatives as well as large commercial and industrial customers in regions that allow retail customer choice. Approximately 72 percent of IE's marketing and trading business in 2002 was with other marketing companies. This is an increase from 55 percent in 2001 due to the elimination of deal origination activity as part of the wind down of the business.

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

			Years Ended December 31,
			2002			2001			2000
Net Revenues (thousands of dollars)
	Electricity		$	42,304		$	330,793		$	182,326
	Gas			4,106			17,870			7,790
		Total	$	46,410		$	348,663		$	190,116
Operating Volumes (settled)
	Electricity (MWh)			39,526,630			34,936,951			23,518,484
	Gas (MMbtu)			35,895,039			97,327,432			80,728,530

 

IDA-WEST:

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

Ida-West had planned to develop the 273MW Garnet energy facility.  See discussion above in "Power Supply - Garnet Power Purchase Agreement."

In 2001, the Friant Power Authority redeemed early, bonds that represented Ida-West's investment in the Friant Power Project, a 27.4 MW project located in California.  The Friant bonds were originally acquired in 1996.  Ida-West recorded a pre-tax gain of $5 million on this transaction in 2001.

In 2000, Ida-West sold its interest in the Hermiston Power project, a 536 MW gas-fired project near Hermiston, Oregon.  Ida-West was responsible for managing all permitting and development activities relating to the project since its inception in 1993.  Ida-West recorded a pre-tax gain of $14 million on this transaction in 2000.

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

IDATECH:

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

IdaTech is focused on the commercialization of fuel processor technology and integrated proton exchange membrane (PEM) fuel cell solutions.  IdaTech's products under development include fuel processors, integrated fuel cell systems and integration and maintenance services.  IdaTech's fuel processors are capable of operating on liquid and gaseous hydrocarbon fuels including natural gas, propane, liquified petroleum gas, diesel, methanol and kerosene.

IdaTech has integrated its multi-fuel fuel processors with a number of PEM fuel cell stacks into one to ten kilowatt (kW) fuel cell systems for stationary and portable electric power generation and has developed fully integrated systems with outputs ranging from one to five kW.

Currently, these systems are being field-tested and evaluated with various European utilities, the Japanese trading company Tokyo Boeki, Ltd., the Propane Education and Research Council and the U.S. Army Communications Electronics Command.

IDACOMM AND VELOCITUS:

In August 2000, IDACORP formed IDACOMM, Inc. and acquired Velocitus, Inc., a Boise, Idaho-based Internet service provider founded in 1992.  IDACOMM and Velocitus provide a wide range of integrated communication services to business and residential customers in 28 markets across eight western states, Virginia and New York.

IDACOMM, a facility-based integrated communication provider, delivers high-speed connectivity, using fiber optic network technology.  IDACOMM's technologies enable high-speed voice, Internet and data communications, including video conferencing, voice-over Internet protocol, off-site training and gigabit Ethernet service.  IDACOMM's customers include companies in industries such as manufacturing, health care, food processing and retail as well as government entities and school districts.  IDACOMM's metropolitan area network in Idaho's Treasure Valley serves Boise, Meridian, Nampa and Caldwell.

Velocitus operates as a Managed Service Provider by offering high-speed Internet access, Internet system support and other related services such as virtual private networks, firewalls and web hosting to more than 25,000 customers.  Velocitus Internet serves the traditional residential and general consumer segment. Velocitus Broadband targets small to medium size business clients with high-speed connectivity and security solutions, including fixed wireless technology.

IDACORP FINANCIAL SERVICES, INC.:

IFS invests primarily in affordable housing projects, which provide a return principally by reducing federal and state income taxes through tax credits and tax depreciation benefits.  IFS's portfolio also includes historic rehabilitation projects such as the El Cortez Hotel in San Diego, California and the Empire Building in Boise.

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, 2002, IFS's total portfolio exceeded $160 million in tax credit investments.  These investments cover 49 states, Puerto Rico and the U.S. Virgin Islands.  The underlying investments include over 700 individual properties, of which all but four are administered through syndicated funds.

RESEARCH AND DEVELOPMENT:

In 2002, IdaTech spent approximately $7 million for research and development of fuel cell technology.  IdaTech's research and development program is focused on the adaptation of its methanol fuel processor to operate on all commercially important fuels, as well as the development of fully integrated fuel cell systems.  Highest priority is given to natural gas, liquified petroleum gas, propane, kerosene and diesel fuels.

IdaTech continues to pursue patent protection of its technology in North America, Europe, South America, Asia and Australia.  The patents issued to IdaTech address the design and operation of fuel reformers and two stage hydrogen purification devices based on a hydrogen selective metal membrane.  Cost reduction through improved designs and reduced use of expensive materials are useful objectives of these patents.  Additionally, one patent issued to IdaTech in 2001 protects an optimized method for purging hydrogen from the anode compartment of a Proton Exchange Membrane Fuel Cell (PEMFC) stack so as to minimize the loss of hydrogen fuel without adversely affecting the electrical power output from the PEMFC stack.  IdaTech also received notice in 2002 from the U.S. Patent and Trademark Office (PTO) that the PTO has allowed all claims of an IdaTech patent application for a metal alloy composition that yields a durable and economical membrane for hydrogen purification.  The broad patent will be issued in early 2003.  Currently, 16 20-year U.S. patents have been issued to IdaTech.  IdaTech also has more than 100 pending domestic and foreign patent applications addressing various aspects of fuel processor and system design, operation, materials and integration with fuel cell stacks.  These patents will help IdaTech to bring its technology to commercialization.  The patents also provide the potential for licensing of IdaTech's technology in the future.

In 2002, IPC spent nearly $2 million to promote energy efficiency. Roughly two-thirds of these expenditures went to fund the Northwest Energy Efficiency Alliance, which strives to transform the regional marketplace through demonstration of innovative technologies, collaboration with firms that market energy-saving products and services and training and information services. IPC's other energy-efficiency programs include compact fluorescent lighting, manufactured home performance testing and duct sealing and low-income weatherization assistance. Much of the funding for these programs came from the new Idaho tariff rider for demand-side management programs and from the conservation and renewables discount provided by the BPA.

ITEM 2.  PROPERTIES

IPC's system includes 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, one natural gas-fired plant located in southern Idaho and interests in three coal-fired steam electric generating plants.  The system also includes approximately 4,657 miles of high voltage transmission lines; 22 step-up transmission substations located at power plants; 18 transmission substations; seven transmission switching stations; and 208 energized distribution substations (excluding mobile substations and dispatch centers).

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

 

(a)  Renewed on a year-to-year basis; application for relicense is pending.
(b)  IPC's ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman.  Amounts shown represent IPC's share only.

At December 31, 2002, the composite average ages of the principal parts of IPC's system, based on dollar investment, were: production plant, 22 years; transmission system and substations, 20 years; and distribution lines and substations, 16 years.  IPC considers its properties to be well maintained and in good operating condition.

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

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

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

RELICENSING OF HYDROELECTRIC PROJECTS:

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

IPC is actively pursuing the relicensing of these projects, a process that may continue for the next ten to 15 years. IPC has filed applications seeking renewal of licenses for the Bliss, Upper Salmon Falls, Lower Salmon Falls, CJ Strike, Shoshone Falls and Upper and Lower Malad Hydroelectric projects. The licenses for the Hells Canyon Complex (Brownlee, Oxbow and Hells Canyon) and the Swan Falls project expire in 2005 and 2010, respectively. IPC is currently engaged in procedures necessary to file timely license applications for these projects. Although various federal and state requirements and issues must be resolved through the license renewal process, IPC anticipates that it will relicense each of the eight projects.

Final Environmental Impact Statements (EIS) have been issued for the Bliss, Upper Salmon Falls, Lower Salmon Falls and Shoshone Falls projects.  New FERC licenses are anticipated in 2003.  While the actual environmental costs of protection, mitigation and enhancement (PM&E) measures and other costs associated with the relicensing of the projects will not be known until the new licenses are issued by the FERC, costs associated with these licenses (assuming 30-year licenses) are expected to total approximately $8 million during the first five years of the licenses and $28 million over the following 25 years.

A final EIS has been issued in October 2002 for the CJ Strike project and a new FERC license is expected in 2003.  While the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC, costs associated with the license (assuming a 30-year license) are expected to total approximately $9 million during the first five years of the license and $38 million over the following 25 years.

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

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

The most significant relicensing effort is the Hells Canyon Complex, which provides 68 percent of IPC's hydro generation capacity and 40 percent of its total generating capacity.  IPC developed its draft license application with the assistance of a collaborative team made up of individuals representing state and federal agencies, businesses, environmental, tribal, customer, local government and local landowner interests.  The draft license application was issued in September 2002 and the final application will be filed in July 2003.  The draft application includes proposed PM&E measures estimated to total approximately (assuming a 30-year license) $78 million during the first five years of the license and $100 million during the following 25 years.  However, the actual costs of PM&E measures and other costs associated with the relicensing of the project will not be known until the new license is issued by the FERC.

At December 31, 2002, $50 million of pre-relicensing costs were included in Construction Work in Progress (CWIP) and $6 million of pre-relicensing costs were included in Electric Plant in Service.  The pre-relicensing costs are recorded and held in CWIP until a new permanent license or annual license is issued by the FERC, at which time the charges are transferred to Electric Plant in Service.  Pre-relicensing costs as well as costs related to the new licenses, as referenced above, will be submitted to regulators for recovery through the rate-making process.

ITEM 3.  LEGAL PROCEEDINGS

Reference is made to Note 8 to the Consolidated Financial Statements.

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

None

 

 

 

EXECUTIVE OFFICERS OF THE REGISTRANTS

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

IDACORP, Inc.

Name, Age and Position	Business Experience During Past Five Years
Jan B. Packwood, 59 President and Chief Executive Officer	Appointed May 30, 1999.  Mr. Packwood was President and Chief Operating Officer from February 2, 1998 to May 30, 1999.
J. LaMont Keen, 50 Ex