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, 2003

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

Yes

(    )

No

( X )

 

Aggregate market value of voting and non-voting common stock held by nonaffiliates (June 30, 2003):

IDACORP, Inc.:

$999,034,371

Idaho Power Company:

None

 

Number of shares of common stock outstanding at February 27, 2004:

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

 

Documents Incorporated by Reference:
Part III, Items 10 - 14	Portions of the joint definitive proxy statement of IDACORP, Inc. and Idaho Power Company to be
	filed pursuant to Regulation 14A for the 2004 Annual Meeting of Shareholders to be held on May 20,
	2004.

 

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

 

 

 

 

 

 

 

 

TABLE OF CONTENTS
				Page
Part I
	Item 1.	Business		1-11
	Item 2.	Properties		12-14
	Item 3.	Legal Proceedings		14
	Item 4.	Submission of Matters to a Vote of Security Holders		14
	Executive Officers of the Registrants			15-16
Part II
	Item 5.	Market for the Registrant's Common Equity and Related Stockholder
			Matters	17
	Item 6.	Selected Financial Data		18-19
	Item 7.	Management's Discussion and Analysis of Financial Condition and
			Results of Operations	20-46
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		47-48
	Item 8.	Financial Statements and Supplementary Data		49-100
	Item 9.	Changes in and Disagreements with Accountants on Accounting and
			Financial Disclosure	101
	Item 9A.	Controls and Procedures		101
Part III
	Item 10.	Directors and Executive Officers of the Registrants*		102
	Item 11.	Executive Compensation*		102
	Item 12.	Security Ownership of Certain Beneficial Owners and Management
			and Related Stockholder Matters*	103
	Item 13.	Certain Relationships and Related Transactions*		103
	Item 14.	Principal Accounting Fees and Services*		103
Part IV
	Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		104-111
	Signatures			112-113
	Exhibit Index			114
	*Incorporated by reference to the joint definitive proxy statement of IDACORP, Inc. and Idaho Power Company
	for the 2004 Annual Meeting of Shareholders, except for the Code of Ethics information in Item 10 and the
	Equity Compensation Plan information in Item 12.

 

 

 

 

 

 

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

PART I - IDACORP, Inc. and Idaho Power Company

ITEM 1.  BUSINESS

OVERVIEW:

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

IDACORP's other operating subsidiaries include:

IdaTech - - developer of integrated fuel cell systems;

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

Velocitus - - commercial and residential Internet service provider;

IDACOMM - - provider of telecommunications services;

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

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

 

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

During 2003, IDACORP refocused on a strategy called "Electricity Plus," a back-to-basics strategy that emphasizes IPC as IDACORP's core business.  IPC continues to experience strong growth in its service area, and this revised corporate strategy recognizes that IPC must make substantial investments in infrastructure to ensure adequate supply and reliable service.   The "Plus" recognizes that through modest investments in IdaTech and IDACOMM, IDACORP can preserve the potential for additional growth in shareowner value.  IFS, with its federal income tax credits, remains a key component of the revised corporate strategy.

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

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

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

UTILITY OPERATIONS:

IPC was incorporated under the laws of the state of Idaho in 1989 as successor to a Maine corporation organized in 1915. IPC is involved in the generation, purchase, transmission, distribution and sale of electric energy in a 20,000 square mile area in southern Idaho and eastern Oregon, with an estimated population of 883,000.  IPC holds franchises in 71 cities in Idaho and nine cities in Oregon and holds certificates from the respective public utility regulatory authorities to serve all or a portion of 25 counties in Idaho and three counties in Oregon.  As of December 31, 2003, IPC supplied electric energy to approximately 427,000 general business customers.

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

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

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

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

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

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

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

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

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

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

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

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

IPC's system is dual peaking, with the larger peak demand generally occurring in the summer.  The all-time system peak demand was 2,963 megawatts (MW), set on July 12, 2002.  Peak demand in 2003 was 2,944 MW, set on July 22, 2003.  IPC expects total system energy requirements to grow 2.3 percent annually over the next three years.

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

		MWh						Percent of total generation
		2003		2002		2001		2003		2002		2001
		(thousands of MWhs)
Hydroelectric		6,149		6,069		5,638		47%		45%		43%
Thermal		6,914		7,286		7,622		53%		55%		57%
	Total system generation	13,063		13,355		13,260		100%		100%		100%

 

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

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

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

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

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

Integrated Resource Plan:  Every two years, IPC is required to file an Integrated Resource Plan (IRP) with both the IPUC and the OPUC.  An IRP is a comprehensive analysis of IPC's present and future demands for electricity and the plan for meeting that demand.  IPC last filed an IRP in June 2002.

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

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

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

CSPP Purchases:  As mandated by the enactment of PURPA and the adoption of avoided costs standards by the IPUC and the OPUC, IPC has entered into contracts for the purchase of energy from a number of private developers.  Because IPC's service territory encompasses substantial irrigation canal development, forest product production facilities, mountain streams and food processing facilities, a considerable amount of CSPP facility development potential exists.  As of December 31, 2003, IPC had signed agreements to purchase energy from 69 CSPP facilities with contracts ranging from one to 30 years.  Of these facilities, 68 were on-line at the end of 2003; the other facility under contract is due to come on-line in May 2004.  Under these contracts, IPC is required to purchase all of the output from the facilities located inside the IPC service territory.  For projects located outside the IPC service territory, IPC is required to purchase the output that IPC has the ability to receive at the facility's requested point of delivery on the IPC system.  During 2003, IPC purchased 654,131 megawatt hours (MWh) from these projects at a cost of $38 million, resulting in a blended price of 5.8 cents per kilowatt hour (kWh).

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

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

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

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

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

Fuel
IPC, through its subsidiary Idaho Energy Resources Co., owns a one-third interest in Bridger Coal Company, which owns the Jim Bridger mine supplying coal to the Jim Bridger generating plant in Wyoming.  The mine, located near the Jim Bridger plant, operates under a long-term sales agreement that provides for delivery of coal over a 51-year period ending in 2025.  The Jim Bridger mine has sufficient reserves to provide coal deliveries for the term of the sales agreement.  IPC also has a coal supply contract providing for annual deliveries of coal through 2009 from the Black Butte Coal Company's Black Butte and Leucite Hills mines located near the Jim Bridger plant.  This contract supplements the Bridger Coal Company deliveries and provides another coal supply to operate the Jim Bridger plant.  The Jim Bridger plant's rail load-in facility, the coal car unloading point, and unit coal train allow the plant to take advantage of potentially lower-cost coal from outside mines for tonnage requirements above established contract minimums.

SPPCo has signed an agreement with Arch Coal Sales Company, Inc. to supply coal to the North Valmy Steam Electric Generating Plant (Valmy) from 2002 through 2006.  IPC is obligated to purchase one-half of the coal, ranging from approximately 515,000 tons to 762,500 tons annually, under the Arch Coal Sales Company agreement.

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

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

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

IPC's water rights for power generation are subordinated to future upstream diversions of water for irrigation and other recognized consumptive uses.

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

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

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

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

Based upon present environmental laws and regulations, IPC estimates its 2004 capital expenditures for environmental matters, excluding Allowance for Funds Used During Construction (AFDC), will total $21 million.  Studies and measures related to environmental concerns at IPC's hydroelectric facilities account for $18 million and investments in environmental equipment and facilities at the thermal plants account for $3 million.  From 2005 through 2006, environmental-related capital expenditures, excluding AFDC, are estimated to be $47 million.  Anticipated expenses related to IPC's hydroelectric facilities account for $36 million and thermal plant expenses are expected to total $11 million.

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

Clean Air:  IPC has analyzed the Clean Air Act legislation and its effects upon IPC and its customers.  IPC's coal-fired plants in Oregon and Nevada already meet the federal emission rate standards for sulfur dioxide (SO₂) and IPC's coal-fired plant in Wyoming meets that state's even more stringent SO₂ regulations.  IPC has sufficient SO₂ allowances to provide compliance for all three coal-fired facilities and its Danskin natural gas-fired facility.  At the end of 2003, IPC had 61,425 allowances in excess of the amount needed for Clean Air Act compliance.  Currently, IPC has been granted an annual allotment of allowances ranging from 15,524 to 28,628 through 2032.  These amounts are in excess of IPC's annual compliance requirements of up to 14,500.  Any excess allowances owned by IPC may be held for future use as they do not expire.  Allowances determined to be excess can be sold to other companies.  Accordingly, IPC does not foresee any material adverse effects upon its operations with regard to SO₂ emissions.

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

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

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

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

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

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

IPC owns and finances the operation of anadromous fish hatcheries and related facilities to mitigate the effects of its hydroelectric dams on fish populations.  In connection with its fish facilities, IPC sponsors ongoing programs for the control of fish disease and improvement of fish production.  IPC's anadromous fish facilities at Hells Canyon, Oxbow, Rapid River, Pahsimeroi and Niagara Springs continue to be operated by the Idaho Department of Fish and Game.  At December 31, 2003, the investment in these facilities was $10 million and the annual cost of operation pursuant to FERC License 1971 was $3 million.

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

Hazardous/Toxic Wastes and Substances:  Under the Toxic Substances Control Act (TSCA), the EPA has adopted regulations governing the use, storage, inspection and disposal of electrical equipment that contains polychlorinated biphenyls (PCBs).  The regulations permit the continued use and servicing of certain equipment (including transformers and capacitors) that contain PCBs.  IPC continues to meet all federal requirements of the TSCA for the continued use of equipment containing PCBs.  IPC continues to eliminate PCBs as part of its long-term strategy.  This program will reduce costs associated with the long-term monitoring of PCB-containing equipment, responding to spills and reporting to the EPA.  Total costs for the identification and disposal of PCBs from IPC's system were less than $1 million annually from 2000 to 2002.  In 2003, IPC spent approximately $1.4 million identifying and eliminating PCBs.

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

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

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

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

In October 2000 and March 2002, in response to FERC Order No. 2000, IPC and other regional transmission owners filed Stage One and Stage Two plans to form RTO West, an entity that would operate the transmission grid in seven western states.  RTO West will have its own independent governing board.  The participating transmission owners will retain ownership of the lines, but will not have a role in operating the grid.  IPC has been an active participant in the development of RTO West.  See Part II, Item 7 - "MD&A - REGULATORY ISSUES - Regional Transmission Organizations." 

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

			Years Ended December 31,
			2003			2002			2001
Revenues (thousands of dollars)
	Residential		$	275,920		$	305,827		$	260,251
	Commercial			173,820			196,454			164,019
	Industrial			128,620			176,648			154,318
	Irrigation			92,609			93,106			72,020
		Total general business		670,969			772,035			650,608
	Off-system sales			71,573			55,031			219,966
	Other			37,840			39,981			41,738
		Total	$	780,382		$	867,047		$	912,312
Energy use (thousands of MWh)
	Residential			4,427			4,387			4,307
	Commercial			3,511			3,460			3,380
	Industrial			3,206			3,226			3,925
	Irrigation			1,836			1,821			1,419
		Total general business		12,980			12,894			13,031
	Off-system sales			1,830			2,069			2,387
		Total		14,810			14,963			15,418

 

ENERGY MARKETING:
IDACORP announced on June 21, 2002 that IE would wind down its power marketing operations due to changing liquidity requirements brought on by rating agencies, continued uncertainty in the regulatory and political environment and the reduction of creditworthy counterparties.  Nearing the conclusion of the wind down process, IE sold its forward book of electricity trading contracts in August 2003 to Sempra Energy Trading (SET).

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

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

				2003			2002			2001
Net Revenues (thousands of dollars)
	Electricity			$	19,267		$	42,304		$	330,793
	Gas				649			4,106			17,870
		Total		$	19,916		$	46,410		$	348,663
Operating Volumes (settled)
	Electricity (MWh)			13,045,863			39,526,630			34,936,951
	Gas (MMbtu)			2,255,881			35,895,039			97,327,432

 

IDACORP FINANCIAL SERVICES, INC.:

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

IFS has focused on a diversified approach to its investment strategy in order to limit both geographic and operational risk.  Over 90 percent of IFS's investments have been made through syndicated transactions.  At December 31, 2003, IFS's total portfolio exceeded $160 million in tax credit investments.  These investments cover 49 states, Puerto Rico and the U.S. Virgin Islands.  The underlying investments include over 700 individual properties, of which all but four are administered through syndicated funds.

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

IDA-WEST:

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

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

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

IDATECH:

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

IdaTech is a global fuel cell provider focused on the commercialization of fuel processor technology and integrated proton exchange membrane (PEM) fuel cell systems. IdaTech's products under development include components such as multi-fuel fuel processors, fuel cell stack technology, automated fuel cell systems and integration and maintenance services. IdaTech's fuel processors are capable of operating on alcohols and liquid and gaseous hydrocarbon fuels including natural gas, liquefied petroleum gas, diesel and kerosene.

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

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

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

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

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

IDACOMM AND VELOCITUS:

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

IDACOMM, a facility-based integrated communication provider, delivers high-speed network connectivity using fiber optic network technology.  IDACOMM's technologies enable high-speed voice, Internet and data communications, including video conferencing, voice-over Internet protocol, off-site training and gigabit ethernet service.  IDACOMM is conducting a broadband-over-powerline (BPL) technical trial in Boise and will be testing the commercial marketability of the product in 2004.  BPL will provide broadband Internet access to power outlets in homes and businesses by transporting data over medium-voltage and low-voltage power lines directly to the end-user's computer.  IDACOMM's customers include companies in industries such as manufacturing, health care, food processing and retail as well as government entities and school districts.  IDACOMM's metropolitan area network in Idaho's Treasure Valley serves Boise, Meridian, Nampa and Caldwell.

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

RESEARCH AND DEVELOPMENT:

In 2003, IdaTech spent approximately $5 million for research and development of fuel cell technology.  IdaTech's research and development program is focused on the adaptation of its methanol fuel processor to operate on all commercially important fuels, as well as the development of fully integrated fuel cell systems.  Highest priority is given to natural gas, liquefied petroleum gas, kerosene and diesel fuels.

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

In 2003, IPC spent nearly $3 million to promote energy efficiency and summer peak reduction.  Just over $1 million of those expenditures went to fund the Northwest Energy Efficiency Alliance, which strives to transform the regional marketplace through demonstration of innovative technologies, collaboration with firms that market energy-saving products and services and training and information services. IPC's other energy efficiency programs target efficiencies in the areas of residential lighting and air conditioning, manufactured homes and duct sealing.  Low-income weatherization assistance and Oregon residential weatherization efforts were also funded in 2003. In addition to IPC's on-going programs, funding was also allocated to the research and development of new energy efficiency and summer peak reduction options in the commercial and residential sectors.  Most of the funding for these programs and program development comes from the Idaho tariff rider for demand-side management (DSM) programs and from the Conservation and Renewable Discount Program of the BPA.

ITEM 2.  PROPERTIES

IPC's system includes 17 hydroelectric generating plants located in southern Idaho and eastern Oregon, one natural gas-fired plant located in southern Idaho and interests in three coal-fired steam electric generating plants.  The system also includes approximately 4,655 miles of high voltage transmission lines; 22 step-up transmission substations located at power plants; 18 transmission substations; seven transmission switching stations; and 208 energized distribution substations (excluding mobile substations and dispatch centers).

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

				Estimated
				Non-
				Coincident
				Maximum		Nameplate
				Operating		Capacity		License
Project				Capacity (kW)		(kW)		Expiration
Hydroelectric:
	Properties subject to federal licenses:
			Lower Salmon		70,000		60,000		1997	(a)
			Bliss		80,000		75,000		1998	(a)
			Upper Salmon		39,000		34,500		1999	(a)
			Shoshone Falls		12,500		12,500		1999	(a)
			CJ Strike		89,000		82,800		2000	(a)
			Upper Malad		9,000		8,270		2004
			Lower Malad		15,000		13,500		2004
			Brownlee-Oxbow-Hells Canyon		1,398,000		1,166,900		2005
			Swan Falls		25,547		25,000		2010
			American Falls		112,420		92,340		2025
			Cascade		14,000		12,420		2031
			Milner		59,448		59,448		2038
			Twin Falls		54,300		52,737		2040
	Other Hydroelectric				10,400		11,300
Steam and Other Generating Plants:
			Jim Bridger (coal-fired) (b)		706,667		770,501
			Valmy (coal-fired) (b)		260,650		283,500
			Boardman (coal-fired) (b)		55,200		56,050
			Danskin (gas-fired)		100,000		90,000
			Salmon (diesel-internal combustion)		5,500		5,000
(a)  Licensed on a year-to-year basis while application for new multi-year license is pending.
(b)  IPC's ownership interests are 33 percent for Jim Bridger, 50 percent for Valmy and 10 percent for Boardman.  Amounts
		shown represent IPC's share only.

 

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

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

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

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

RELICENSING OF HYDROELECTRIC PROJECTS:

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

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

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

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

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

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

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

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

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

ITEM 3.  LEGAL PROCEEDINGS

Please refer to Note 8 of IDACORP's Consolidated Financial Statements.

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

None

 

 

 

 

 

 

 

EXECUTIVE OFFICERS OF THE REGISTRANTS

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

IDACORP, Inc.

Name, Age and Position	Business Experience During Past Five Years
Jan B. Packwood, 60 President and Chief Executive Officer	Appointed May 30, 1999.  Mr. Packwood was President and Chief Operating Officer from February 2, 1998 to May 30, 1999.
J. LaMont Keen, 51 Executive Vice President	Appointed March 1, 2002.  Mr. Keen was Senior Vice President, Administration and Chief Financial Officer from May 5, 1999 to March 1, 2002, Senior Vice President-Administration, Chief Financial Officer and Treasurer from March 15, 1999 to May 5, 1999 and Vice President, Chief Financial Officer and Treasurer from February 2, 1998 to March 15, 1999.
*Darrel T. Anderson, 45 Vice President, Chief Financial Officer and Treasurer	Appointed March 1, 2002.  Mr. Anderson was Vice President, Finance and Treasurer from May 5, 1999 to March 1, 2002.
*Bryan A. B. Kearney, 41 Vice President and Chief Information Officer	Appointed March 15, 2001.
*Gregory W. Panter, 55 Vice President - Public Affairs	Appointed April 1, 2001.