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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

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____________ TO __________

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of Registrant as specified in its charter)


Washington		91-0462470

(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

1411 East Mission Avenue, Spokane, Washington		99202-2600

(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: 509-489-0500

Web site: http://www.avistacorp.com

Securities registered pursuant to Section 12(b) of the Act:


		Name of Each Exchange
Title of Class		on Which Registered

Common Stock, no par value, together with		New York Stock Exchange
Preferred Share Purchase Rights appurtenant thereto		Pacific Stock Exchange

7 7/8% Trust Originated Preferred Securities, Series A		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Title of Class

Preferred Stock, Cumulative, Without Par Value

Indicate by check mark whether the Registrant (1) has 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 Registrant was required to file such reports), and (2) has 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 (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s 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 Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act):

Yes [X] No [ ]

The aggregate market value of the Registrant’s outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $682,953,104 based on the last reported sale price thereof on the consolidated tape on June 30, 2003.

As of March 1, 2004, 48,347,751 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

Documents Incorporated By Reference


		Part of Form 10-K into Which
Document		Document is Incorporated

Proxy Statement to be filed in		Part III, Items 10, 11,
connection with the annual meeting		12, 13 and 14
of shareholders to be held May 13, 2004

TABLE OF CONTENTS


PART I
	Available Information
	Item 1. Business
		Company Overview
		Avista Utilities
		General
		Electric Operations
		Electric Requirements
		Electric Resources
		Future Resource Needs
		Forecasted Electric Energy Requirements and Resources
		Hydroelectric Relicensing
		Natural Gas Operations
		Natural Gas Resources
		Regulatory Issues
		Industry Restructuring
		Federal Level
		Regional Transmission Organizations
		Wholesale Power Market Design
		State Level
		Automated Meter Reading
		Environmental Issues
		AVISTA UTILITIES OPERATING STATISTICS
		Energy Marketing and Resource Management
		Avista Energy
		Avista Power
		Avista Advantage
		Other
		Discontinued Operations
		Avista Labs
		Avista Communications
	Item 2. Properties
		Avista Utilities
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
	Item 6. Selected Financial Data
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
		Safe Harbor for Forward-Looking Statements
		Avista Corp. Business Segments
		Executive Level Summary
		Avista Utilities - Resource Optimization
		Avista Utilities - Regulatory Matters
		Power Market Issues
		Results of Operations
		Diluted Earnings (Loss) per Common Share by Business Segments
		Overall Operations
		Avista Utilities
		Energy Marketing and Resource Management
		Avista Advantage
		Other
		Discontinued Operations
		Transactions with Mirant Corporation
		New Accounting Standards
		Critical Accounting Policies and Estimates
		Liquidity and Capital Resources
		Review of Cash Flow Statement
		Overall Liquidity
		Capital Resources
		Inter-Company Debt; Subordination
		Pension Plan
		Off-Balance Sheet Arrangements
		Spokane Energy, LLC
		Credit Ratings
		Avista Utilities Operations
		Energy Marketing and Resource Management Operations
		Avista Advantage Operations
		Other Operations
		Contractual Obligations
		Competition
		Business Risk
		Risk Management
		Economic and Load Growth
		Management Succession and Employee Issues
		Environmental Issues and Other Contingencies
		Dividends
	Item 7a. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data
		INDEPENDENT AUDITORS’ REPORT
		CONSOLIDATED STATEMENTS OF INCOME
		CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
		SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	Item 9a. Controls and Procedures
PART III
	Item 10. Directors and Executive Officers of the Registrant
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	Item 13. Certain Relationships and Related Transactions
	Item 14. Principal Accountant Fees and Services
PART IV
	Item 15. Financial Statements, Financial Statement Schedules, Exhibits and Reports on Form 8-K
SIGNATURES
INDEPENDENT AUDITORS’ CONSENT
EXHIBIT INDEX
Exhibit 3(b)
EXHIBIT 10(L)
Exhibit 12
Exhibit 21
Exhibit 31(a)
Exhibit 31(b)
Exhibit 32

AVISTA CORPORATION

INDEX


Item						Page
No.						No.

		Acronyms and Terms				iv
					Part I
		Available Information					1
	1.	Business					1
			Company Overview				1
			Avista Utilities				3
			General				3
			Electric Operations				3
			Electric Requirements				4
			Electric Resources				4
			Future Resource Needs				6
			Forecasted Electric Energy Requirements and Resources				6
			Hydroelectric Relicensing				7
			Natural Gas Operations				7
			Natural Gas Resources				8
			Regulatory Issues				8
			Industry Restructuring				10
			Federal Level				10
			Regional Transmission Organizations				12
			Wholesale Power Market Design				12
			State Level				12
			Automated Meter Reading				13
			Environmental Issues				13
			Avista Utilities Operating Statistics				15
			Energy Marketing and Resource Management				17
			Avista Energy				17
			Avista Power				18
			Avista Advantage				18
			Other				19
			Discontinued Operations				19
	2.	Properties					20
			Avista Utilities				20
	3.	Legal Proceedings					21
	4.	Submission of Matters to a Vote of Security Holders					21
				Part II
	5.	Market for Registrant’s Common Equity and Related Stockholder Matters					22
	6.	Selected Financial Data					23
	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations					24
			Safe Harbor for Forward-Looking Statements				24
			Avista Corp. Business Segments				25
			Executive Level Summary				25
			Avista Utilities – Resource Optimization				26
			Avista Utilities – Regulatory Matters				27
			Power Market Issues				30
			Results of Operations				32
			Diluted Earnings (Loss) per Common Share by Business Segments				32
			Overall Operations				32
			Avista Utilities				36
			Energy Marketing and Resource Management				42
			Avista Advantage				45
			Other				45
			Discontinued Operations				46

AVISTA CORPORATION


Item					Page
No.					No.

			Transactions with Mirant Corporation			46
			New Accounting Standards			47
			Critical Accounting Policies and Estimates			47
			Liquidity and Capital Resources			50
			Review of Cash Flow Statement			50
			Overall Liquidity			50
			Capital Resources			51
			Inter-Company Debt; Subordination			53
			Pension Plan			53
			Off-Balance Sheet Arrangements			53
			Spokane Energy, LLC			53
			Credit Ratings			54
			Avista Utilities Operations			54
			Energy Marketing and Resource Management Operations			55
			Avista Advantage Operations			56
			Other Operations			56
			Contractual Obligations			56
			Competition			57
			Business Risk			57
			Risk Management			60
			Economic and Load Growth			61
			Management Succession and Employee Issues			62
			Environmental Issues and Other Contingencies			62
			Dividends			62
	7a.	Quantitative and Qualitative Disclosure about Market Risk				62
	8.	Financial Statements and Supplementary Data				62
			Independent Auditors’ Report			63
			Financial Statements			64-70
			Consolidated Statements of Income			64
			Consolidated Statements of Comprehensive Income			65
			Consolidated Balance Sheets			66-67
			Consolidated Statements of Cash Flows			68
			Consolidated Statements of Stockholders’ Equity			69
			Schedule of Information by Business Segments			70
			Notes to Consolidated Financial Statements			71
	9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure				*
	9a.	Controls and Procedures				109
				Part III
	10.	Directors and Executive Officers of the Registrant				109
	11.	Executive Compensation				111
	12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters				111
	13.	Certain Relationships and Related Transactions				111
	14.	Principal Accountant Fees and Services				112
				Part IV
	15.	Financial Statements, Financial Statement Schedules, Exhibits and Reports on Form 8-K				112
		Signatures				113
		Independent Auditors’ Consent				114
		Exhibit Index				115

* = not an applicable item in the 2003 calendar year for the Company

iii

AVISTA CORPORATION

ACRONYMS AND TERMS
(The following acronyms and terms are found in multiple locations within the document)


Acronym/Term		Meaning

aMW	-	Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time

AFUDC	-	Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period

AM&D	-	Advanced Manufacturing and Development

APB	-	Accounting Principles Board

Avista Capital	-	Parent company to the Company’s non-utility businesses

Avista Corp.	-	Avista Corporation, the Company

BPA	-	Bonneville Power Administration

Capacity	-	the rate at which a particular generating source produces energy, measured in KW or MW

Cabinet Gorge	-	the Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho

Centralia	-	the coal-fired Centralia Power Plant in western Washington State

Colstrip	-	the coal-fired Colstrip Generating Plant in southeastern Montana

Coyote Springs 2	-	the natural gas-fired Coyote Springs 2 Generating Plant located near Boardman, Oregon

CFTC	-	U.S. Commodity Futures Trading Commission

CPUC	-	California Public Utilities Commission

CT	-	Combustion turbine

Dekatherm	-	Unit of measurement for natural gas; a therm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy)

DOE	-	the State of Washington’s Department of Ecology

Energy	-	the amount of electricity produced or consumed over a period of time, measured in KWH or MWH

EITF	-	Emerging Issues Task Force

ERM	-	the Energy Recovery Mechanism in the State of Washington

FASB	-	Financial Accounting Standards Board

FERC	-	Federal Energy Regulatory Commission

IPUC	-	Idaho Public Utilities Commission

AVISTA CORPORATION


Acronym/Term		Meaning

KV	-	Kilovolt - a measure of capacity on transmission lines

KW, KWH	-	Kilowatt, kilowatt-hour, 1000 watts or 1000 watt hours

MW, MWH	-	Megawatt, megawatt-hour, 1000 KW or 1000 KWH

NERC	-	North American Electricity Reliability Council

Noxon Rapids	-	the Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana

OPUC	-	Oregon Public Utility Commission

PCA	-	the Power Cost Adjustment mechanism in the State of Idaho

PGA	-	Purchased Gas Adjustment

PGE	-	Portland General Electric Corporation

PLP	-	Potentially liable party

PUD	-	Public Utility District

PURPA	-	the Public Utilities Regulatory Policies Act of 1978

RTO	-	Regional Transmission Organization

SFAS	-	Statement of Financial Accounting Standards

Therm	-	Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)

VAR	-	Value-at-Risk, measures the expected risk of portfolio loss under hypothetical adverse price movements, over a given time interval within a given confidence level

Watt	-	Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt

WECC	-	Western Electricity Coordinating Council

WUTC	-	Washington Utilities and Transportation Commission

AVISTA CORPORATION

PART I

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Annual Report on Form 10-K at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including without limitation those that are identified by the use of words such as, but not limited to, “will,” “anticipates,” “seeks to,” “estimates,” “expects,” “intends,” “plans,” “predicts,” and similar expressions. Such statements are inherently subject to a variety of risks and uncertainties that could cause actual results to differ materially from those expressed. Most of these risks and uncertainties are beyond Avista Corporation’s control.

Available Information

The Web site address of Avista Corporation (Avista Corp. or the Company) is www.avistacorp.com. Avista Corp. makes available free of charge, on or through its Web site, its annual, quarterly and current reports, and any amendments to those reports, as soon as reasonably practicable after electronically filing such reports with the Securities and Exchange Commission. Information contained on Avista Corp.’s Web site is not part of this report.

Item 1. Business

Company Overview

Avista Corp., incorporated in the State of Washington in 1889, is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. As of December 31, 2003, the Company employed approximately 1,450 people in its utility operations and approximately 450 people in its subsidiary businesses. The Company’s corporate headquarters are in Spokane, Washington, center of the Inland Northwest geographic region. Agriculture, mining and lumber were the primary industries in the Inland Northwest for many years; today health care, education, finance, electronic and other manufacturing, tourism and the service sectors are growing in importance.

The Company’s operations are exposed to risks including, but not limited to, the price and supply of purchased power, fuel and natural gas, regulatory allowance of the recovery of power and natural gas costs, operating costs and capital investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale purchases and sales.

The Company has four business segments – Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. As of December 31, 2003, the Company had common equity investments of $494.0 million and $257.2 million in Avista Utilities and Avista Capital, respectively.

Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations that started in 1889. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Utilities also engages in wholesale purchases and sales of electric capacity and energy. Avista Utilities will seek to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. The utility business is expected to grow modestly, consistent with historical trends. Expansion is expected to result primarily from economic and population growth in its service territory. It is Avista Utilities’ strategy to own or to have contracts that provide a sufficient amount of resources to meet its retail and wholesale energy requirements under a range of operating conditions.

The Energy Marketing and Resource Management business segment is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy, which commenced operations in 1997, is an electricity and natural gas marketing, trading and resource management business, operating primarily within the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states and the provinces of British Columbia and Alberta, Canada. Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric and natural gas transmission and transportation arrangements. Avista Energy is also involved in trading

AVISTA CORPORATION

electricity and natural gas, including derivative commodity instruments. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. Avista Power is an investor in certain generation assets, primarily its 49 percent interest in a 270-megawatt (MW) natural gas-fired combustion turbine plant in northern Idaho (Lancaster Project).

Avista Advantage, Inc. (Avista Advantage), which commenced operations in 1998, is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. Avista Advantage remains focused on increasing revenues, improving margins and continuously enhancing client satisfaction.

The Other business segment includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development and certain other operations of Avista Capital. The Company continues to limit its future investment in the Other business segment. Over time as opportunities arise, the Company plans to dispose of assets and phase out of operations in the Other business segment.

The Company’s current business segments, and the companies included within them, are illustrated below:

(FLOW CHART)

o - denotes a business entity, Avista Advantage is also a business segment.

O - denotes business segment.

See “Item 6. Selected Financial Data” and “Schedule of Information by Business Segments in the Consolidated Financial Statements” for information with respect to the operating performance of each business segment.

AVISTA CORPORATION

Avista Utilities

General

Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. Avista Utilities also engages in wholesale purchases and sales of electric capacity and energy as part of its resource management and load-serving obligations.

Avista Utilities provides electric distribution and transmission as well as natural gas distribution services in a 26,000 square mile area in eastern Washington and northern Idaho with a population of approximately 850,000. It also provides natural gas distribution service in a combined 4,000 square mile area in northeast and southwest Oregon and the South Lake Tahoe region of California with a population of approximately 495,000. At the end of 2003, Avista Utilities supplied retail electric service to a total of 325,000 customers and retail natural gas service to a total of 298,000 customers across its entire service territory.

Avista Utilities anticipates residential and commercial electric load growth to average between 2.0 and 2.5 percent annually for the next four years, primarily due to expected population increases and business growth in its service territory. While the number of electric customers is expected to increase, the average annual usage by residential customers is expected to remain steady. For the next four years, Avista Utilities expects natural gas load growth to average between 4.0 and 4.5 percent annually in its Washington and Idaho service territory and 2.5 and 3.0 percent in its Oregon and California service territory. The natural gas load growth is primarily expected through conversions to natural gas from competing space and water heating energy sources, and population increases and business growth in Avista Utilities’ service territories. Natural gas loads for space heating vary significantly with annual fluctuations in weather within Avista Utilities’ service territories. Electric and natural gas load growth projections are based on purchased economic forecasts, publicly available studies, and internal analysis of company-specific data, such as energy consumption patterns and internal business plans. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Economic and Load Growth” for additional information.

In recent years, the Company has experienced a decrease in use per customer for both electric and natural gas retail customers exclusive of weather related factors. This appears to be due to the conservation efforts of individual customers as well as a response to rate increases.

Electric Operations

In addition to providing electric transmission and distribution services, Avista Utilities generates electricity from its owned facilities. Avista Utilities owns and operates eight hydroelectric projects, a wood-waste fueled generating station, a two-unit natural gas-fired combustion turbine (CT) generating facility and two small generating facilities. In July 2003, the combined cycle natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) was placed into operation. Avista Utilities has a 50 percent ownership interest in Coyote Springs 2. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities-Developments with Coyote Springs 2” for information with respect to a transformer failure at Coyote Springs 2. Avista Utilities also owns a 15 percent share in a two-unit coal-fired generating facility and leases and operates a two-unit natural gas-fired CT generating facility. WP Funding LP, an entity that is included in Avista Corp.’s consolidated financial statements and included in the Avista Utilities business segment, owns the two-unit natural gas-fired CT generating facility that is leased by Avista Utilities. In addition to company-owned resources, Avista Utilities has a number of long-term power purchase and exchange contracts that increase its available resources. See “Item 2. Properties” for further information with respect to generation properties.

Avista Utilities engages in an ongoing process of resource optimization, which involves the pursuit of economic resources to serve load obligations and using existing resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy to and from utilities and other entities as part of the process of acquiring resources to serve its retail and wholesale load obligations. These transactions range from a term as short as one hour up to long-term contracts that extend beyond one year. Avista Utilities makes continuing projections of (1) future retail and wholesale loads based on, among other things, forward estimates of factors such as customer usage and weather as well as historical data and contract terms and (2) resource availability based on, among other things, estimates of streamflows, generating unit availability, historic and forward market information and experience. On the basis of these continuing projections, Avista Utilities makes purchases and sales of energy on an annual, quarterly, monthly, daily and hourly basis to match expected resources to expected energy requirements. Resource optimization also includes transactions such as purchasing fuel to run thermal generation and, when economic, selling fuel and substituting wholesale market purchases for the operation of Avista Utilities’ own resources, as well as other wholesale transactions

AVISTA CORPORATION

to capture the value of available generation and transmission resources. This optimization process includes entering into financial and physical hedging transactions as a means of managing risks.

Participants in the electric wholesale market include other utilities, federal marketing agencies and energy trading and marketing companies. The electric wholesale market has changed significantly over the last few years with respect to market participants involved, level of activity, variability in market prices, liquidity, Federal Energy Regulatory Commission (FERC)-imposed price caps, and counterparty credit issues. During 2000 and the first half of 2001, the electric wholesale market in the WECC region was more turbulent than previously experienced and marked by significant volatility, service disruptions and defaults by certain participants. During the second half of 2001 and 2002 wholesale market prices decreased to levels similar to those experienced before 2000. Wholesale market prices and volatility increased in 2003 as compared to 2002; however, prices and volatility during 2003 did not increase to levels experienced during 2000 and the first half of 2001. Currently, many energy companies are facing liquidity issues, and counterparty credit exposure is of concern to market participants. During 2002 and 2003, as compared to 2000 and the first half of 2001, electric and natural gas trading volumes decreased and fewer creditworthy counterparties participated in the energy markets. Avista Utilities is actively monitoring energy industry developments with a focus on liquidity, volatility of energy trading markets and counterparty credit exposure. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Power Market Issues” for more information.

Challenges facing Avista Utilities’ electric operations include, among other things, the timing and approval of the recovery of deferred power costs, changes in the availability of and volatility in the prices of power and fuel, generating unit availability, legislative and governmental regulations, potential tax law changes, customer response to price increases and surcharges, streamflows and weather conditions. See “Industry Restructuring,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Power Market Issues” and “Note 1 of Notes to Consolidated Financial Statements” for additional information.

Electric Requirements

The peak electric load requirement for 2003 was 1,936 MW (including retail native load of 1,487 MW, long-term wholesale obligations of 364 MW and short-term wholesale obligations of 85 MW). This peak occurred on July 30, 2003 at which time the maximum resource capacity available from Avista Utilities was 2,365 MW. The maximum resource capacity included 1,574 MW of company-owned electric generation, 72 MW of long-term hydroelectric contracts, 343 MW of other long-term wholesale purchases and 376 MW of short-term wholesale purchases. Variations in energy usage by Avista Utilities’ customers occur from year to year, from season to season and hour to hour as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy for annual, quarterly, monthly, daily and hourly periods in order to meet electric requirements and to prudently manage and optimize available resources.

Electric Resources

General Avista Utilities has a diverse electric resource mix of hydroelectric projects, thermal generating facilities, and power purchases and exchanges. At the end of 2003, Avista Utilities’ facilities had a total net capability of approximately 1,651 MW, of which 58 percent was hydroelectric and 42 percent was thermal. See “Avista Utilities Operating Statistics – Electric Operations” for energy resource statistics.

Hydroelectric Resources Hydroelectric generation is Avista Utilities’ lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on its total power supply costs. Under normal streamflow and operating conditions, Avista Utilities projects that it would be able to meet approximately one-half of its total average electric requirements (both retail and long-term wholesale) with the combination of its own hydroelectric generation and long-term hydroelectric purchase contracts with certain Public Utility Districts (PUDs) in Washington state.

Total hydroelectric resources (including resources purchased under long-term hydroelectric contracts) generate 550 average megawatts (aMW) (or 4.8 million MWhs) annually under normal streamflow conditions. Hydroelectric resources generated 492 aMW, 553 aMW and 369 aMW during 2003, 2002 and 2001, respectively. The streamflows to company-owned hydroelectric projects were 84 percent, 112 percent and 56 percent of normal in 2003, 2002 and 2001, respectively. Hydroelectric generation for Avista Utilities for 2001 was the lowest level in the 73 years in which records have been kept. The combination of low hydroelectric production and other factors resulted in Avista Utilities incurring power supply costs during the second half of 2000 and 2001 significantly in excess of the amount of power supply costs recovered through retail rates in effect at the time. See “Regulatory Issues – Power Cost Deferrals” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities-Regulatory Matters” for more information.

AVISTA CORPORATION

The following table shows Avista Utilities’ hydroelectric generation (in thousands of MWhs) during the years ended December 31:


		2003		2002		2001

Noxon Rapids			1,543		1,816		1,021
Cabinet Gorge			975		1,085		694
Post Falls			80		87		67
Upper Falls			67		75		66
Monroe Street			99		105		89
Nine Mile			122		126		99
Long Lake			465		511		370
Little Falls			189		205		158

	Total company-owned hydroelectric generation		3,540		4,010		2,564
Long-term hydroelectric contracts with PUDs			775		837		631

	Total hydroelectric generation		4,315		4,847		3,195

Thermal Resources Avista Utilities owns a 50 percent interest in Coyote Springs 2 located near Boardman, Oregon. Avista Utilities owns a 15 percent interest in a twin-unit, coal-fired generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana. Additionally, Avista Utilities owns a wood-waste-fired generating facility known as the Kettle Falls Generating Station (Kettle Falls) in northeastern Washington and a two-unit natural gas-fired CT generating facility, located in northeast Spokane (Northeast CT). Avista Utilities also leases and operates a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT). WP Funding LP, an entity that is included in Avista Corp.’s consolidated financial statements and included in the Avista Utilities business segment, owns the Rathdrum CT. In addition, Avista Utilities owns two small generating facilities (Boulder Park and Kettle Falls CT) that were placed into operation in 2002.

Until May 2000, Avista Utilities had a 15 percent interest in a twin-unit, coal-fired generating facility, the Centralia Power Plant (Centralia), in western Washington. In May 2000, the owners of Centralia sold the plant to TransAlta Corporation (TransAlta). Avista Utilities purchased energy from TransAlta to replace the output from Centralia for the period from July 1, 2000 through December 31, 2003, excluding April, May and June of each year. Avista Utilities received approximately 200 megawatts per hour during the term of the contract.

Fuel Supply for Thermal Resources Coyote Springs 2, which is operated by Portland General Electric Corporation, is supplied with natural gas under both long-term contracts and spot market purchases, and transportation agreements with unilateral renewal rights are in place.

Colstrip, which is operated by PPL Montana, LLC, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through December 2019.

Kettle Falls’ primary fuel is wood-waste generated as a by-product from forest industry operations within 100 miles of the plant. Natural gas may be used as an alternate fuel. A combination of long-term contracts plus spot purchases provides Avista Utilities the flexibility to meet expected future fuel requirements for Kettle Falls.

The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT are generating units that are primarily used for peaking electric requirements. Due to the shortage of hydroelectric generation during 2000 and 2001 and the relative operating cost compared to higher wholesale market prices, the Northeast CT and Rathdrum CT units were operated on a more frequent basis. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

The following table shows Avista Utilities’ thermal generation (in thousands of MWhs) during the years ended December 31:


		2003		2002		2001

Coyote Springs 2			397		—		—
Colstrip			1,593		1,397		1,617
Kettle Falls			366		261		361
Northeast CT and Rathdrum CT			20		39		1,023
Boulder Park and Kettle Falls CT			22		17		—

	Total thermal generation		2,398		1,714		3,001

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Purchases, Exchanges and Sales Avista Utilities purchases power under various long-term contracts. Avista Utilities also enters into a significant number of short-term sales and purchases with terms of up to one year.

Under the Public Utility Regulatory Policies Act of 1978 (PURPA), Avista Utilities is required to purchase generation from qualifying facilities, including small hydroelectric and cogeneration projects, at rates approved by the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC). These contracts expire at various times through 2022.

See “Avista Utilities Operating Statistics – Electric Operations - Electric Energy Resources” for more detailed information with respect to purchased power and power from exchanges in 2003, 2002 and 2001.

Future Resource Needs

Avista Utilities has operational strategies to ensure that it has available resources sufficient to meet its energy requirements under a range of operating conditions. The following is a forecast of Avista Utilities’ average energy requirements and resources for the period 2004 through 2006:

Forecasted Electric Energy Requirements and Resources
(aMW)


				2004		2005		2006

Requirements:
	System load				1,036		1,062		1,086
	Contracts for power sales				13		13		12

		Total requirements			1,049		1,075		1,098

Resources:
	Company-owned and contract hydro (1)				525		550		550
	Company-owned thermal generation				373		373		366
	Contracts for power purchases				220		218		218

		Total resources			1,118		1,141		1,134

			Surplus resources		69		66		36
			Additional available energy (2)		207		207		207

			Total surplus resources		276		273		243

(1)		Forecasts and snowpack conditions as of February 2004 indicate that hydroelectric generation will be approximately 525 aMW in 2004, which is 95 percent of normal. This forecast may change based upon additional precipitation, temperatures and other variables. The forecasts for 2005 and 2006 assume normal hydroelectric generation of 550 aMW.

(2)		Forecast assumes no generation from the Northeast CT, Rathdrum CT, Kettle Falls CT and Boulder Park, which are generally only used to meet electric load requirements due to either below normal hydroelectric generation or increased loads or outages at other generating facilities, and/or when operating costs are lower than short-term wholesale market prices. The combined maximum capacity of the Northeast CT, Rathdrum CT, Kettle Falls CT and Boulder Park is 274 MW, with an estimated energy production of 207 aMW.

Significant Customer Contract A power purchase and sales contract with Potlatch Corporation (Potlatch) expired on December 31, 2001. Potlatch’s Lewiston, Idaho facility has electric requirements of about 100 aMW. The facility also typically produces approximately 60 aMW of generation. Since January 2002, Potlatch had been using its generation to supply a portion of its own electric requirements, which resulted in a net electric requirement on Avista Utilities’ system of approximately 40 aMW. During July 2003, Avista Utilities and Potlatch executed a ten-year power purchase and sales contract, under which Avista Utilities will purchase up to 62 aMW of Potlatch’s generation at a price slightly below the IPUC administratively determined avoided cost rate. Avista Utilities may also purchase generation above 62 aMW at a price that is somewhat below market prices, when market conditions are such that it is mutually beneficial to Potlatch and Avista Utilities. Avista Utilities will serve Potlatch’s entire electric requirements of approximately 100 aMW at the retail tariff rates established for large industrial customers, unless a different rate is ordered by the IPUC. Potlatch’s generation and loads are separately measured and billed by Avista Utilities. When Potlatch’s generation experiences an interruption, Avista Utilities serves the full Potlatch facility load from its system. In January 2004, the agreement was approved by the IPUC, including the full recovery of the costs associated with the agreement through the Idaho power cost adjustment (PCA) mechanism or base retail rates. Avista Utilities does not expect the agreement to have a material impact on future net income.

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Hydroelectric Relicensing

Avista Corp. is a licensee under the Federal Power Act as administered by the FERC, which includes regulation of hydroelectric generation resources. Except for the Little Falls Plant, all of the Company’s hydroelectric plants are regulated by the FERC through project licenses issued for 30-50 year periods. Avista Corp.’s licensed projects are subject to the provisions of Part I of the Federal Power Act. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages.

In March 2001, Avista Utilities received a 45-year operating license from the FERC for the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) and the Noxon Rapids Hydroelectric Generating Project (Noxon Rapids). The Clark Fork Settlement Agreement that was entered into during 1999 and incorporated into the FERC license preserved the projects’ economic peaking and load following operations. Also, as part of the Clark Fork Settlement Agreement, Avista Utilities initiated implementation of protection, mitigation and enhancement measures in March 1999. Measures in the agreement, which cost approximately $4.7 million annually, address issues related to fisheries, water quality, wildlife, recreation, land use, cultural resources and erosion. Recovery of previously deferred hydroelectric relicensing costs, as well as estimated levels of ongoing costs associated with implementation of the Clark Fork Settlement Agreement, were addressed by both the WUTC and IPUC and received favorable treatment and recovery through retail rates. Costs of approximately $15 million deferred during the licensing phase were allowed in rate base and are being amortized over the 45-year license term.

Dissolved gas levels exceed Idaho and federal water quality standards downstream of Cabinet Gorge during periods when excess river flows must be diverted over the spillway. Mitigation of the dissolved gas levels continues to be studied as agreed to in the Clark Fork Settlement Agreement. To date, intensive biological studies in the lower Clark Fork River and Lake Pend Oreille have documented no significant biological effects of high dissolved gas levels on free ranging fish. Under the terms of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other signatories to the agreement and submitted the plan in December 2002 for review and approval to the Idaho Department of Environmental Quality and the U.S. Fish and Wildlife Service. In December 2003, the Idaho Department of Environmental Quality provided modifications to the plan that have been reviewed by the Company. The modifications did not result in any significant changes to the Company’s plan. The structural alternative proposed by the Company provides for the modification of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. The costs of modifications to the first tunnel are currently estimated to be $37 million (including AFUDC and inflation) and would be incurred between 2004 and 2009. The second tunnel would be modified only after evaluation of the performance of the first tunnel and such modifications would commence no later than 10 years following the completion of the first tunnel. It is currently estimated that the costs to modify the second tunnel would be $23 million (including AFUDC and inflation). As part of the plan, the Company will also provide $0.5 million annually commencing as early as 2004, as mitigation for aquatic resources that might be adversely affected by high dissolved gas levels. Mitigation funds will continue until the modification of the second tunnel commences or if the second tunnel is not modified to an agreed upon point in time commensurate with the biological effects of high dissolved gas levels. The Company will seek regulatory recovery of the costs for the modification of Cabinet Gorge and the mitigation payments.

The Company operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls) are under one FERC license and referred to herein as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license for the Spokane River Project expires in August 2007; the Company filed a Notice of Intent to Relicense in July 2002. The formal consultation process involving planning and information gathering with stakeholder groups is underway. The Company’s goal is to develop with the stakeholders a comprehensive and cost-effective settlement agreement to be filed as part of the Company’s license application to the FERC in July 2005.

Natural Gas Operations

Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, northeast and southwest Oregon, and the South Lake Tahoe region of California. Natural gas commodity costs in excess of the amount recovered in current rates are deferred and recovered in future periods with applicable regulatory approval through adjustments to rates.

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into the first half of 2003 before declining somewhat during the middle of 2003 and increasing again in the fourth quarter of 2003. Avista Utilities’ average prices per dekatherm were $5.50, $4.95 and $6.33 in 2003, 2002 and 2001, respectively. The continued tight balance between supply and demand for natural gas is a major contributor to the ongoing price volatility in natural gas, and this is expected to continue into 2004. Market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. Avista Utilities believes that natural gas should sustain its market advantage over competing energy sources based on the levels of existing reserves and the potential for natural gas development in the future. Growth has occurred in the natural gas business in recent years due to increased demand for natural gas in new construction, as well as conversions from competing space and water heating energy sources to natural gas.

Challenges facing Avista Utilities’ natural gas operations include, among other things, volatility in the price of natural gas, changes in the availability of natural gas, legislative and governmental regulations, weather conditions and the timing and approval of recovery for increased commodity costs.

Avista Utilities makes sales and provides transportation service directly to large natural gas customers. The majority of Avista Utilities’ large industrial customers purchase their own natural gas requirements through natural gas marketers. For these customers, Avista Utilities provides transportation from natural gas transmission pipeline interconnections to the customers’ premises. Several of Avista Utilities’ largest natural gas customers are provided natural gas transportation service under individual contracts. All individual contracts are subject to regulatory review and approval. The total volume transported on behalf of transportation customers for 2003, 2002 and 2001 was 153.4, 174.9 and 180.9 million therms, which represented approximately 31 percent, 34 percent and 33 percent of Avista Utilities’ total system deliveries, respectively.

Natural Gas Resources

Natural Gas Supply The Company is well connected to multiple supply basins in the western United States and western Canada and believes there will be sufficient supplies of natural gas to meet its customers’ needs. However, natural gas prices in the Pacific Northwest are increasingly affected by supply and demand factors in other regions of the United States and Canada. Avista Utilities has capacity delivery rights on seven pipelines and owns natural gas storage facilities. A diverse portfolio of natural gas resources allows Avista Utilities to capture market opportunities that benefit its natural gas customers.

The Company’s energy marketing, trading and resource management subsidiary, Avista Energy, is currently responsible for the daily management and optimization of these resources for the requirements of customers in the states of Washington, Idaho and Oregon under an Agency Agreement with Avista Utilities. Under this relationship, Avista Utilities retains ownership of its transportation, storage and long-term contracts and Avista Energy acts as an agent to optimize these resources. In February 2004, the WUTC ordered the termination of this relationship in Washington and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. See “Regulatory Issues - Natural Gas Benchmark Mechanism” for additional information.

Approximately 25 percent of Avista Utilities’ natural gas supplies are obtained from domestic sources, with the remaining 75 percent from Canadian sources. Canadian natural gas supplies are not considered to be at greater risk of non-delivery than supplies from the United States.

Natural Gas Storage Avista Utilities owns a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 8.8 million therms, with a total working natural gas inventory of 190.3 million therms. The role of Jackson Prairie in providing flexible natural gas supplies is important to Avista Utilities’ natural gas operations. It enables Avista Utilities to place natural gas into storage when prices are low or to meet minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are high. Avista Energy controls a portion of the capacity at Jackson Prairie for a ten-year period ending in 2009. During 2002, a multi-year project to further increase the capacity at Jackson Prairie commenced. Avista Utilities has contracted to release a total of approximately 37 percent of its Jackson Prairie capacity to two other utilities. One of these contracts requires two-years notice for termination and one contract is renewed on a year-to-year basis.

Regulatory Issues

Avista Corp., as a regulated public utility, is currently subject to regulation by state utility commissions with respect to prices, accounting, the issuance of securities, and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the WUTC, the IPUC, the Oregon Public Utilities Commission (OPUC), the California Public Utilities Commission (CPUC) and the Public Service Commission of the State of Montana (Montana Commission).

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Approval of the issuance of securities is not required from the CPUC and the Montana Commission. The Company is also subject to the jurisdiction of the FERC for its wholesale natural gas rates charged for the release of capacity from Jackson Prairie, and for electric transmission service and wholesale electric sales.

In each regulatory jurisdiction, rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are determined on a “cost of service” basis and are designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable return on “rate base.” “Rate base” is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant. Rates for wholesale electric and natural gas transmission services are based on the “cost of service” principles and are set forth in tariffs on file with the FERC. See “Note 1 of Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes. See “Industry Restructuring” for additional information about deregulation, as well as changes with respect to transmission and wholesale electricity markets.

Power Cost Deferrals Avista Utilities defers the recognition in the income statement of certain power supply costs that are in excess of the level currently recovered from retail customers as authorized by the WUTC and the IPUC. A portion of power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through retail rates.

The WUTC issued an order effective July 1, 2002 providing for restructuring of rate increases previously approved by the WUTC totaling 31.2 percent. The July 2002 rate change increased base retail rates 19.3 percent and provided an 11.9 percent continuing surcharge over previous base retail rates for the recovery of deferred power costs. The WUTC rate order also established an Energy Recovery Mechanism (ERM) effective July 1, 2002. The ERM replaced a series of temporary deferral mechanisms that had been in place in Washington since mid-2000. The ERM allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of annual power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company.

Under the ERM, Avista Utilities agreed to make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The settlement agreement establishing the ERM provided for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. Avista Utilities made its first annual filing with the WUTC in March 2003 related to $18.4 million of deferred power costs incurred for the period July 1, 2002 through December 31, 2002. Previous WUTC orders established the prudence and recoverability of power costs incurred through June 30, 2002. In January 2004, the WUTC approved a settlement agreement among Avista Utilities, the WUTC staff and the Industrial Customers of Northwest Utilities, which provided for Avista Utilities to write off $2.5 million (recorded in 2003) of previously deferred power costs related to the delay of the Coyote Springs 2 project in 2002 and 2003 and allows recovery of all other deferred power costs incurred through December 31, 2002.

Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the authorized level of net power supply expense approved in the last Idaho general rate case. The IPUC originally approved a 19.4 percent surcharge in October 2001, which has been extended through October 2004 for recovery of previously deferred power costs. Based on IPUC staff recommendations and IPUC orders, the prudence of $11.9 million of deferred power costs will be reviewed in the electric general rate case that Avista Utilities filed in February 2004. Avista Utilities believes that such costs for long-term fuel supply contracts were prudently incurred.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities-Regulatory Matters” for additional information.

General Rate Cases Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. In February 2004, Avista Utilities filed electric and natural gas general rate cases in Idaho. The request is designed to increase electric revenues by 11 percent, or $18.9 million in annual revenues, over current rates. This would result from a 24 percent increase in base retail rates (an increase of $35.2 million in annual revenues) offset by a $16.3 million annual revenue decrease from the current PCA surcharge. Avista Utilities also requested a

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natural gas general rate increase of 9.2 percent, or $4.8 million in annual revenues. Avista Utilities’ requests are based on an overall rate of return of 9.82 percent and a return on equity of 11.5 percent. The IPUC generally has up to seven months to review the general rate case filings.

In September 2003, the OPUC approved a general natural gas rate increase of $6.3 million in annual revenues effective October 1, 2003 that authorizes, among other things, an overall rate of return of 8.88 percent and a return on equity of 10.25 percent.

In June 2002, the WUTC issued an order that became effective July 1, 2002 with respect to Avista Utilities’ most recent electric general rate case. The order provides for an overall rate of return of 9.72 percent and a return on equity of 11.16 percent. The order provided for no incremental rate increase to Avista Utilities’ Washington electric customers above the rates in effect at the time; however, rate increases previously approved by the WUTC totaling 31.2 percent were restructured. For further information about this WUTC order, see “Power Cost Deferrals.”

Purchased Gas Adjustment (PGA or Natural Gas Trackers) Under established regulatory practices in each respective state, Avista Utilities is allowed to adjust its natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs already included in retail rates are deferred and charged or credited to expense when regulators approve inclusion of the cost changes in rates. During the second half of 2002, Avista Utilities adjusted its natural gas rates in response to a decrease in current and projected natural gas costs at that time. During the fourth quarter of 2002, natural gas rate decreases of 17.4 percent, 15.5 percent, 7.1 percent and 16.2 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. As discussed above, current and projected natural gas prices increased towards the end of 2002 and into the first half of 2003. During September and October of 2003, natural gas rate increases of 8.7 percent, 2.4 percent, 12.4 percent and 15.0 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. The rate increase in Washington was approved subject to refund, pending further review of the deferred natural gas costs. In February 2004, Avista Utilities filed a request for a 7.3 percent increase in Oregon to be effective April 1, 2004. These natural gas rate increases and decreases are designed to pass through changes in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income.

Natural Gas Benchmark Mechanism The IPUC, WUTC and OPUC approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations in Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets are managed by Avista Energy through an Agency Agreement. Avista Utilities continues to manage natural gas procurement for its California operations, which currently represents approximately four percent of its total natural gas therm sales.

The Natural Gas Benchmark Mechanism provides benefits to retail customers and allows Avista Energy to retain a portion of the benefits associated with asset optimization and the efficiencies gained in purchasing natural gas for Avista Utilities as part of a larger portfolio. In early 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. In January 2003, the WUTC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through January 29, 2004. In April 2003, the Company filed a request with the WUTC to amend certain aspects of the Natural Gas Benchmark Mechanism and related Agency Agreement and requested an extension through March 31, 2007. In July 2003, the WUTC staff and the Public Counsel Section of the Attorney General’s Office filed testimony recommending the termination of the Natural Gas Benchmark Mechanism in Washington. Hearings were held before the WUTC during the fourth quarter of 2003 and the first part of 2004. In February 2004, the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. The transition plan will be filed by March 15, 2004.

Industry Restructuring

Federal Level

Industry restructuring to open the electric wholesale energy market to competition was initially promoted by federal legislation. The Energy Policy Act of 1992 (Energy Act) amended provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act to remove certain barriers to a competitive wholesale market. The Energy Act expanded the authority of the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission

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capacity for the purpose of providing these services. It also created “exempt wholesale generators,” a class of independent power plant owners that are able to sell generation only at the wholesale level. This permits public utilities and other entities to participate through subsidiaries in the development of independent electric generating plants for sales to wholesale customers without being required to register under the PUHCA.

FERC Order No. 888, issued in April 1996, requires public utilities operating under the Federal Power Act to provide access to their transmission systems to third parties pursuant to the terms and conditions of the FERC’s pro-forma open access transmission tariff. FERC Order No. 889, the companion rule to Order No. 888, requires public utilities to establish an Open Access Same-Time Information System (OASIS) to provide transmission customers with information about available transmission capacity and other information by electronic means. It also requires each public utility subject to the rule to functionally separate its transmission and wholesale power merchant functions. The FERC issued its initial order accepting the non-rate terms and conditions of Avista Utilities’ open access transmission tariff in November 1996. Avista Utilities filed its “Procedures for Implementing Standards of Conduct under FERC Order No. 889” with the FERC in December 1996 and adopted these Procedures effective January 1997. FERC Orders No. 888 and No. 889 have not had a material effect on Avista Utilities’ operating results.

In November 2003, the FERC issued a final rule (FERC Order No. 2004) revising the standards of conduct applicable to jurisdictional electric transmission providers and natural gas pipelines (collectively defined by the rule as “transmission providers”) and their “energy affiliates.” FERC Order No. 2004 replaces the previous gas and electricity standards of conduct, adopted in FERC Orders No. 497 and No. 889 respectively, with new unified standards of conduct applicable to both electric and natural gas transmission providers, and dramatically expands the range of affiliated entities covered by the standards. The standards of conduct are designed to ensure that transmission providers do not provide preferential access to service or information to affiliated entities. FERC Order No. 2004 became effective in February 2004 upon each transmission provider completing its filing with the FERC and posting on its OASIS or its Internet Web site its plan for implementing the revised standards of conduct. By June 2004, each transmission provider must comply with the new rule’s requirements and post procedures that will enable customers and the FERC to determine whether the transmission provider is complying with the new standards. Avista Utilities’ compliance with the revised standards will have no substantive impacts on the operation, maintenance and marketing of its transmission system or Avista Utilities’ ability to provide service to its customers.

The North American Electric Reliability Council (NERC) and the WECC have undertaken initiatives to establish a series of security coordinators to oversee the reliable operation of the regional transmission system. Accordingly, Avista Utilities, in cooperation with other utilities in the Pacific Northwest, established the Pacific Northwest Security Coordinator (PNSC), which oversees daily and short-term operations of the Northwest sub-regional transmission grid and has limited authority to direct certain actions of control area operators in the case of a pending transmission system emergency. Avista Utilities executed its service agreement with the PNSC in September 1998.

The utility industry experienced the largest blackout in history on August 14, 2003, when 50 million people lost power in the northeastern United States and eastern Canadian provinces. As a result of this outage the NERC, in conjunction with the FERC, conducted a comprehensive investigation of the outage and issued 14 reliability related recommendations. These recommendations address compliance with existing national and regional standards and initiatives to prevent or mitigate future blackouts. Utilities in the western United States, including Avista Utilities, had already been following the provisions of approximately half of these NERC recommendations in response to blackouts experienced in 1996 and Avista Utilities already complies with many of the remaining NERC recommendations. Avista Utilities plans to perform some additional work in the future to address certain NERC recommendations.

Governmental agencies (including the FERC), legislators and others have suggested enactment of specific requirements, standards, operating procedures and accountabilities for electric transmission system operators and owners. The additional requirements that could be enacted, if any, are not known at this time. Avista Utilities expects that the costs associated with any new requirements would be recoverable in rates.

Avista Utilities has implemented appropriate other operating practices and processes. The majority of these procedures were implemented prior to the August 2003 blackout in the northeastern United States. Examples of the practices and processes already in place include: (1) Critical outages are coordinated through the 45-day regional coordinated outage schedule process. (2) Participation in the Northwest Operations and Planning Study Group (NOPSG). NOPSG reviews and approves seasonal study limits for critical Northwest paths. (3) System studies are performed prior to all construction and maintenance outages. These study results are used to set new generation and transmission limits based on construction and maintenance outages. (4) Avista Utilities’ Supervisory Control And Data Acquisition (SCADA) Engineering and Operations group reports to the same management as the System Operations department. System operators are in continuous discussions with SCADA support personnel. (5) As noted above, Avista Utilities has signed an empowerment agreement with the PNSC that gives the PNSC authority to direct Avista

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Utilities to take certain action with respect to regional reliability issues. (6) Development of operating procedures, updated periodically, to assist system operators during normal, emergency and unusual operating conditions. (7) Review of existing emergency practices and backup plans. These include control center backup plan, loss of communications, loss of SCADA system, operation during system island conditions, operation during high/low frequency conditions, operation during high/low voltage conditions and manual load shedding. (8) Sharing of critical system status and information with Western Utilities. (9) A construction plan to significantly increase the capacity of the Avista Utilities’ transmission system over the next 5 years.

Regional Transmission Organizations

FERC Order No. 2000 requires all utilities subject to FERC regulation to file a proposal to form a Regional Transmission Organization (RTO), or a description of efforts to participate in an RTO, and any existing obstacles to RTO participation. FERC Order No. 2000 is a follow up to FERC Orders No. 888 and No. 889 issued in 1996, which required transmission owners to provide non-discriminatory transmission service to third parties.

Avista Corp. is in continuing discussions with utilities and others in the Pacific Northwest region to define how such an RTO might work. For example, the Company has negotiated with nine other utilities in the western United States on the possible formation of an RTO, RTO West, a non-profit organization. The Company and two other western utilities have also taken steps toward the formation of a for-profit Independent Transmission Company, TransConnect, which could be a member of a future RTO.

The final proposal for any RTO or TransConnect must be approved by the FERC, the boards of directors of the filing companies and regulators in various states. The Company’s decision to move forward with the formation of TransConnect or any RTO serving the Pacific Northwest region, as well as the legal, financial and operating implications of such decisions, will ultimately depend on the terms and conditions related to the formation of the entities and conditions established in the regulatory approval processes. The Company cannot predict these implications.

In September 2003, a new organization called Western Interconnection L.L.C. (WI) filed an application with the FERC for certification as an RTO to provide transmission service in the western United States. As part of its application, WI requested that FERC order each jurisdictional utility in the western United States (including Avista Corp.) to provide escrow funding to WI in the amount of $4.0 million per year. Several parties (including Avista Corp.) have filed motions with the FERC requesting that WI’s application be denied.

Wholesale Power Market Design

In April 2003, the FERC issued a White Paper presenting a revised version of proposed wholesale power market rules. The White Paper emphasizes a focus on the formation of RTOs and on ensuring that all independent transmission organizations have sound market rules. The White Paper further indicates that the implementation schedule will vary depending on regional needs and will also allow for regional differences. This White Paper was developed based on input from numerous state regulatory agencies, utility companies, industry and consumer groups, as well as the public. The White Paper reflects significant concerns raised with respect to the FERC’s initial proposal of a Standard Market Design in July 2002. The FERC’s stated goals with respect to wholesale power markets include: reliable and reasonably priced electric service for all customers; sufficient electric infrastructure; transparent markets with fair rules for all market participants; stability and regulatory certainty for customers, the electric power industry, and investors; technological innovation; and efficient use of the nation’s resources. The White Paper proposes a significant role being played by regional authorities in setting up regional power markets. At this time, the Company cannot predict the ultimate impact the changes may have on its operations as well as how the changes may impact the RTO West, TransConnect and WI proposals.

State Level

Competition among utilities for retail customers is not generally allowed in Avista Utilities’ service territory. While the Energy Act precludes the FERC from mandating retail wheeling, state regulators and legislators could open service territories to full competition at the retail level. Legislative action at the state level would be required for full retail wheeling and customer choice to occur in Washington and Idaho. For the past several years, the legislatures and public utility commissions in Washington and Idaho have conducted a series of hearings and several studies regarding electric industry restructuring. Issues such as unbundling, deregulation, reliability and consumer protection were examined. Impacts on customer service quality and system reliability (generation, transmission and distribution) were considered on a “macro” basis under various restructuring scenarios. Public policy makers in Washington and Idaho continue to examine other states’ experiences with restructuring, while cognizant that the Pacific Northwest generally benefits from

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electric rates that are among the lowest in the country. Currently, there is generally no movement toward deregulation in Washington or Idaho.

Automated Meter Reading

Over a four-year period beginning in 2005, Avista Utilities plans to upgrade electric and natural gas meters for automated meter reading (AMR) in Idaho. Avista Utilities believes a combination of decreases in capital and installation costs of AMR together with expected continuing increases in meter reading expenses now supports the installation of this technology. This should allow Avista Utilities to manage meter reading labor costs, provide improvements on meter data accuracy, lower customer service costs, and reduce estimated meter reads.

Environmental Issues

The Company is subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which Avista Utilities has an ownership interest were designed to comply with all applicable environmental laws. Furthermore, the Company conducts periodic reviews of all its facilities and operations to respond to or to anticipate emerging environmental issues. The Company’s Board of Directors has an environmental committee to deal specifically with these issues.

Since December 1991, a number of species of fish in the Northwest, including the Snake River sockeye salmon and fall chinook salmon, the Kootenai River white sturgeon, the upper Columbia River steelhead, the upper Columbia River spring chinook salmon and the bull trout, have been listed as threatened or endangered under the Federal Endangered Species Act. Thus far, measures that were adopted and implemented to save the Snake River sockeye salmon and fall chinook salmon have not directly impacted generation levels at any of Avista Utilities’ hydroelectric dams. Avista Utilities does, however, purchase power from four projects on the Columbia River that are directly impacted by ongoing mitigation measures for salmon and steelhead. The reduction in generation at these projects is relatively minor, resulting in minimal economic impact on Avista Utilities at this time. It is currently not possible to accurately predict the likely economic costs to the Company resulting from all future actions.

The Company received a new FERC operating license for Cabinet Gorge and Noxon Rapids in March 2001 that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, in particular bull trout, is a principal focus of the agreement. The result is a collaborative bull trout recovery program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. See “Hydroelectric Relicensing” for further information.

Air Quality The most significant impact on the Company related to the Clean Air Act (CAA) and the 1990 Clear Air Act Amendments (CAAA) pertains to Colstrip, which is a “Phase II” coal-fired plant under the CAAA. Avista Utilities does not expect Colstrip to be required to implement any additional sulfur dioxide (SO2) mitigation in the foreseeable future in order to continue operations. Avista Utilities’ other thermal projects are subject to various CAAA standards. Every five years each of the other thermal projects requires an updated operating permit (known as a Title V permit), which addresses, among other things, the compliance of the plant with the CAAA. The operating permit for the Rathdrum CT was renewed in 2001 (expires 2006) and the operating permit for Kettle Falls was renewed in 2002 (expires 2007). The Northeast CT was issued a Title V permit in February 2004 (expires 2009). Boulder Park does not require a Title V permit based on its limited output and instead has a synthetic minor permit that does not expire. Coyote Springs 2 has a Title V permit that was issued in 2003 (expires in 2008).

In 1999, the Environmental Protection Agency (EPA) initiated enforcement actions against several utilities, asserting that older, coal-fired power plants operated by those utilities have, over the years, been modified in ways that subject them to more stringent requirements under the CAA. The EPA has since issued notices of violation and commenced enforcement activities against other utilities. The future direction of the EPA’s enforcement initiative is presently unclear. Therefore, at this time, Avista Utilities is unable to predict whether such EPA enforcement actions will be brought with respect to Colstrip. However, the EPA regional office that regulates plants in Montana has indicated an intention to issue information requests to all utilities in their jurisdiction and issued such a request to Colstrip in 2003. The owners of Colstrip are in the process of responding to this information request. Avista Utilities cannot presently predict what, if any, action the EPA might take in this regard.

In December 2003, PPL Montana, LLC, as operator of Colstrip, received an Administrative Compliance Order (ACO) from the EPA pursuant to the CAA. The ACO alleges that Colstrip has been in violation of its CAA permit at Colstrip since 1980. The permit required Colstrip to submit for review and approval by the EPA an analysis and proposal for reducing emissions of nitrogen oxides to address visibility concerns if and when EPA promulgates Best Available Retrofit Technology requirements for nitrogen oxides. The EPA is asserting that regulations it promulgated in 1980

AVISTA CORPORATION

triggered this requirement. Avista Utilities and PPL Montana, LLC believe that the ACO is unfounded and PPL Montana, LLC is discussing the matter with the EPA. The ACO does not expressly seek penalties, and it is unclear at this time what, if any, additional control technology the EPA may consider to be required. Accordingly, the costs to install any additional controls for nitrogen oxides, if required, cannot be estimated at this time.

Water Quality Dissolved gas levels exceed Idaho and federal water quality standards downstream of Cabinet Gorge during periods when excess river flows must be diverted over the spillway. Mitigation of the dissolved gas levels continues to be studied as agreed to in the Clark Fork Settlement Agreement. See “Hydroelectric Relicensing” for further information.

In June 2001, Avista Development received official notice that it had been designated as a potentially liable party (PLP) with respect to contaminated sites on the Spokane River. The State of Washington’s Department of Ecology (DOE) discovered PCBs in fish and sediments in the Spokane River in the 1970s and 1980s. In the 1990s, the DOE performed subsequent sampling of the river and identified potential sources of the PCBs, including the Spokane Industrial Park (SIP) and a number of other entities in the area. The SIP, renamed Pentzer Development Corporation (Pentzer Development) in 1990, operated a wastewater treatment plant at the site until it was closed in December 1993. The SIP’s treatment plant discharged to the Spokane River under the terms of a National Pollutant Discharge Elimination System permit issued by the DOE. Pentzer Development sold the property in 1996 and merged with Avista Development in 1998. Avista Development filed a response to this notice in August 2001. In December 2001, the DOE confirmed Avista Development’s status as a PLP and named at least two other PLPs in this matter. During the fourth quarter of 2002, Avista Development and one other PLP finalized the Consent Decree and Scope of Work for the remedial investigation and feasibility study of the site, which was formally entered into Spokane County Superior Court in January 2003. One other PLP has not been participating in the process. As directed by Avista Development and the other PLP, the field work for the remedial investigation began in April 2003 and was completed by the end of 2003 with a draft remedial investigation report and feasibility study technical memorandum due March 29, 2004. The other PLP that has been participating with Avista Development has filed for bankruptcy and is expected to file its reorganization plan in mid-2004. The other PLP has initiated negotiations with the DOE and Avista Development to settle its future financial liabilities associated with the site.

In April 2003, the DOE released its study of wastewater and sludge handling from facilities owned by a fourth PLP. The DOE study indicated that the fourth PLP continued to discharge PCBs into the Spokane River. The DOE issued the fourth PLP a final notice of participation as a PLP on April 30, 2003.

The DOE has indicated that the actual cleanup of PCB sediments in the Spokane River will be coordinated to the extent possible with the EPA’s separate plan to remove heavy metals from the Spokane River. The Company believes that the heavy metals contamination resulted from decades of mining upstream at locations in Idaho and is not related to the activities of Avista Development or Avista Corp.

See “Note 25 of the Notes to Consolidated Financial Statements” for additional information with respect to environmental issues.

AVISTA CORPORATION

AVISTA UTILITIES OPERATING STATISTICS


					Years Ended December 31,

					2003			2002			2001

ELECTRIC OPERATIONS
	ELECTRIC OPERATING REVENUES (Dollars in Thousands):
		Residential			$	204,783		$	196,156		$	158,847
		Commercial				201,339			194,732			155,371
		Industrial				78,276			68,096			80,433
		Public street and highway lighting				4,770			4,683			3,790

			Total retail revenues			489,168			463,667			398,441
		Wholesale revenues				73,463			64,082			480,903
		Revenues from sales of fuel				71,456			40,937			18,948
		Other revenues				16,835			15,455			23,913

			Total electric operating revenues		$	650,922		$	584,141		$	922,205

	ELECTRIC ENERGY SALES (Thousands of MWhs):
		Residential				3,298			3,203			3,219
		Commercial				2,919			2,837			2,882
		Industrial				1,785			1,519			1,892
		Public street and highway lighting				25			25			25

			Total retail energy sales			8,027			7,584			8,018
		Wholesale energy sales				2,075			2,216			6,262

			Total electric energy sales			10,102			9,800			14,280

	ELECTRIC ENERGY RESOURCES (Thousands of MWhs):
		Hydro generation (from Company facilities)				3,540			4,010			2,564
		Thermal generation (from Company facilities)				2,398			1,714			3,001
		Purchased power - long-term hydroelectric contracts with PUDs				775			837			631
		Purchased power - wholesale				3,909			3,828			8,624
		Power exchanges				36			17			(104	)

			Total power resources			10,658			10,406			14,716
		Energy losses and Company use				(556	)		(606	)		(436	)

			Total energy resources (net of losses)			10,102			9,800			14,280

	NUMBER OF ELECTRIC CUSTOMERS (Average for Period):
		Residential				283,497			279,735			276,845
		Commercial				36,279			35,910			35,454
		Industrial				1,414			1,420			1,434
		Public street and highway lighting				422			413			402

			Total electric retail customers			321,612			317,478			314,135
		Wholesale				47			46			44

			Total electric customers			321,659			317,524			314,179

	ELECTRIC RESIDENTIAL SERVICE AVERAGES:
		Annual use per customer (KWh)				11,633			11,450			11,629
		Revenue per KWh (in cents)				6.21			6.12			4.93
		Annual revenue per customer			$	722.35		$	701.22		$	573.77
	ELECTRIC AVERAGE HOURLY LOAD (aMW)					984			935			975

	RESOURCE AVAILABILITY at time of system peak (MW):
		Total requirements (winter):
			Retail native load			1,509			1,346			1,500
			Wholesale obligations			417			297			1,734

				Total requirements (winter)		1,926			1,643			3,234
		Total resource availability (winter)				2,557			2,213			3,553
		Total requirements (summer):
			Retail native load			1,487			1,389			1,379
			Wholesale obligations			449			466			1,332

				Total requirements (summer)		1,936			1,855			2,711
		Total resource availability (summer)				2,365			2,287			2,927

AVISTA CORPORATION

AVISTA UTILITIES OPERATING STATISTICS


				Years Ended December 31,

				2003			2002			2001

NATURAL GAS OPERATIONS
	NATURAL GAS OPERATING REVENUES (Dollars in Thousands):
		Residential		$	166,925		$	183,964		$	179,584
		Commercial			90,523			104,974			104,012
		Industrial			7,475			7,127			11,130

			Total retail natural gas revenues		264,923			296,065			294,726
		Wholesale revenues			280			695			1,762
		Transportation revenues			8,485			9,664			8,576
		Other revenues			3,601			3,399			3,578

			Total natural gas operating revenues	$	277,289		$	309,823		$	308,642

	THERMS DELIVERED (Thousands of Therms):
		Residential			198,471			199,686			198,413
		Commercial			122,115			126,220			126,869
		Industrial			12,737			11,243			15,523

			Total retail		333,323			337,149			340,805
		Wholesale			675			2,306			4,831
		Transportation			153,352			174,891			180,918
		Interdepartmental and Company use			3,124			2,145			15,430

			Total therms delivered		490,474			516,491			541,984

	SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):
		Purchases			334,609			344,793			348,620
		Storage — injections			(74	)		(53	)		(62	)
		Storage — withdrawals			76			60			54
		Natural gas for transportation			153,352			174,891			180,918
		Interdepartmental transportation			2,607			1,513			14,662
		Distribution system losses			(96	)		(4,713	)		(2,208	)

			Total natural gas supply		490,474			516,491			541,984

	NUMBER OF NATURAL GAS CUSTOMERS (Average for Period):
		Residential			261,063			254,700			249,650
		Commercial			31,312			30,823			30,355
		Industrial			310			315			328

			Total retail customers		292,685			285,838			280,333
		Wholesale customers			1			1			2
		Transportation customers			84			88			86

			Total natural gas customers		292,770			285,927			280,421

	NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
		Washington and Idaho
			Annual use per customer (therms)		813			841			852
			Revenue per therm (in cents)		83.68			93.05			89.24
			Annual revenue per customer	$	679.96		$	782.16		$	760.02
		Oregon and California
			Annual use per customer (therms)		663			679			688
			Revenue per therm (in cents)		85.07			90.00			93.44
			Annual revenue per customer	$	564.31		$	610.68		$	643.31
	NET SYSTEM MAXIMUM CAPABILITY (Thousands of Therms):
		Net system maximum demand (winter)			2,270			2,253			2,236
		Net system maximum firm contractual capacity (winter)			4,340			4,340			4,320
	HEATING DEGREE DAYS: (1)
		Spokane, WA
			Actual		6,351			6,818			6,800
			30 year average		6,820			6,842			6,842
			% of average		93	%		100	%		99	%
		Medford, OR
			Actual		4,046			4,230			4,143
			30 year average		4,592			4,611			4,611
			% of average		88	%		92	%		90	%

(1)

Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

AVISTA CORPORATION

Energy Marketing and Resource Management

The Energy Marketing and Resource Management business segment includes Avista Energy and Avista Power, both subsidiaries of Avista Capital.

Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily within the WECC. Avista Energy’s headquarters are in Spokane, Washington, and it also has an office in Vancouver, British Columbia, Canada. Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric and natural gas transmission and transportation arrangements. Avista Energy Canada, Ltd. is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 400 industrial customers in British Columbia, Canada. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. Avista Energy’s earnings are primarily derived from the following activities:

•		Marketing and managing the output and availability of combustion turbines and hydroelectric assets owned by other entities.

•		Capturing price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process.

•		Purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks.

•		Transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations within the WECC.

•		Taking speculative positions on future price movements within established risk management policies.

Volatility and liquidity conditions in the wholesale energy markets affect Avista Energy’s earnings. Volatility in wholesale energy markets refers to the size and frequency of price movements. Liquidity represents the volume of activity in the wholesale energy markets during a given period of time and may affect the ability to conduct transactions in the wholesale market. Increases in the volatility in wholesale energy markets generally increase Avista Energy’s potential earnings or losses while decreases in the volatility generally decrease Avista Energy’s potential earnings or losses. Decreases in liquidity in the wholesale energy markets tend to decrease Avista Energy’s earnings.

Derivative commodity instruments in the energy trading portfolio are marked to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Market prices and valuation models are utilized in determining the value of electric, natural gas and related derivative commodity instruments.

Avista Energy trades electricity and natural gas, along with derivative commodity instruments including futures, options, swaps and other contractual arrangements. Most transactions are conducted on an “over-the-counter” basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges). Avista Energy’s trading operations are affected by, among other things, volatility of prices within the electric energy and natural gas markets, the demand for and availability of energy, changing regulation of the electric and natural gas industries, the creditworthiness of counterparties and variations in liquidity in energy markets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Risk” for further information.

The following table provides operating statistics for Avista Energy for the years ended December 31:


		2003		2002		2001

Gross Realized Sales Volume:
	Electricity (thousands of MWhs)		41,579		40,426		47,927
	Natural gas (thousands of dekatherms)		228,397		225,983		248,193

In 1997, Avista Energy entered into a scheduling and marketing services agreement with Chelan County Public Utility District (PUD), located in Washington State. The agreement allows Avista Energy to market, on a “real-

AVISTA CORPORATION

time” basis, a portion of the output from Chelan County PUD’s hydroelectric resources and to jointly market energy products and services to other utilities in the region.

In September 1999, Avista Energy began managing Avista Utilities’ natural gas storage assets, transportation contracts and natural gas purchasing operations. Under an Agency Agreement, Avista Energy serves as agent for Avista Utilities, managing its pipeline transportation rights and natural gas storage assets, as well as purchasing natural gas for Avista Utilities’ retail customers. The assets continue to be owned by Avista Utilities; however, they are fully integrated operationally into Avista Energy’s portfolio. The Natural Gas Benchmark Mechanism allows Avista Energy the opportunity to retain a portion of the benefits associated with asset optimization and the efficiencies gained in purchasing natural gas for Avista Utilities. The Natural Gas Benchmark Mechanism and related Agency Agreement expires in March 2005 in Idaho and Oregon. In February 2004, the WUTC ordered the termination of the Natural Gas Benchmark Mechanism and related Agency Agreement in Washington and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. The transition plan will be filed by March 15, 2004.

Avista Energy is subject to the various risks inherent in commodity trading including, particularly, market risk, liquidity risk, commodity risk and credit risk, as well as risks resulting from the imposition of market controls by federal and state regulatory agencies. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Power Market Issues, Business Risks and Risk Management,” and “Notes 1, 2, 7 and 8 of Notes to Consolidated Financial Statements” for additional information regarding the market and credit risks inherent in the energy trading business, Avista Energy’s risk management policies and procedures, accounting practices, and positions held by Avista Energy as of December 31, 2003.

Avista Power

Avista Power is a 49 percent owner of the Lancaster Project, which commenced commercial operation in September 2001. The Goldman Sachs Group, Inc. acquired Cogentrix Energy, Inc., which owns 51 percent of the Lancaster Project, in December 2003. All of the output from the Lancaster Project is contracted to Avista Energy through 2026.

Avista Power and its co-owner, Mirant Oregon LLC (Mirant Oregon), which is an affiliate of Mirant Americas Development, Inc., substantially completed the construction of Coyote Springs 2 during 2002. In January 2003, Avista Power’s 50 percent ownership interest in Coyote Springs 2 was transferred to Avista Corp. for inclusion in Avista Utilities’ power generation resource portfolio.

Avista Advantage

Avista Advantage is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. Avista Advantage’s solutions are designed to provide multi-site companies with critical and easy-to-access information that enables them to proactively manage and reduce their facility-related expenses.

Avista Advantage analyzes and presents consolidated bills on-line, and pays utility and other facility-related expenses for multi-site customers. Information gathered from invoices, providers and other customer-specific data allows Avista Advantage to provide its customers with in-depth analytical support, real-time reporting and consulting services with regard to facility-related energy, waste, repair and maintenance, and telecom expenses.

Avista Advantage has secured five patents on its two critical business systems, the Facility IQ system, which provides operational information drawn from facility bills, and the AviTrack database, which processes and reports on information gathered from service providers to ensure customers are receiving the most effective services at the proper price. Avista Advantage is not aware of any claimed or threatened infringement on any of its patents issued to date and will continue to expand and protect its existing patents, as well as file additional patent applications for new products, services and process enhancements.

As of December 31, 2003, Avista Advantage serviced 292 customers, having 109,583 billed sites throughout North America. This is an increase from 247 customers and 98,251 billed sites as of December 31, 2002. As of December 31, 2001, Avista Advantage serviced 203 customers and 79,749 billed sites. During 2003, Avista Advantage processed $6.4 billion of bills, an increase from $4.9 billion in 2002 and $4.3 billion in 2001.

AVISTA CORPORATION

Other

The Other business segment includes Avista Ventures, Pentzer, Avista Development and certain other operations of Avista Capital. Included in this business segment is Advanced Manufacturing and Development (AM&D) doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal manufacturing of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also has a wood products division that provides complete fabrication and turnkey assembly for arcade games, kiosks, store fixtures, and displays. The Company continues to limit its future investment in the Other business segment. Over time as opportunities arise, the Company plans to dispose of assets and phase out of operations in the Other business segment.

Discontinued Operations

Avista Labs

In July and September 2003, Avista Corp. announced total investments of $12.2 million by private equity investors in a new entity, AVLB, Inc., which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. As of December 31, 2003, Avista Corp. had an ownership interest of approximately 17.5 percent in AVLB, Inc., with the opportunity but no further obligation to fund or invest in this business. Avista Corp.’s investment in AVLB, Inc. is accounted for under the cost method. Avista Labs patented and developed a modular air-cooled, self-hydrating Proton Exchange Membrane (PEM) fuel cell that delivers reliable and clean distributed power solutions. In addition to developing its modular fuel cell products, Avista Labs contracted with selected market channels to deliver system solutions to industrial, commercial and residential markets.

Avista Communications

Avista Communications provided local dial tone, data transport, internet services, voice messaging and other telecommunications services to several communities in the western United States. In September 2001, Avista Corp. decided that it would dispose of substantially all of the assets of Avista Communications. The divestiture of operating assets was complete by the end of 2002.

AVISTA CORPORATION

Item 2. Properties

Avista Utilities

Avista Utilities’ electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:

Generation Properties (1)


						Nameplate		Present
				No. of		Rating		Capability
				Units		(MW) (2)		(MW) (3)

Hydroelectric Generating Stations (River)
	Washington:
		Long Lake (Spokane)			4		70.0		88.0
		Little Falls (Spokane)			4		32.0		36.0
		Nine Mile (Spokane)			4		26.4		24.5
		Upper Falls (Spokane)			1		10.0		10.2
		Monroe Street (Spokane)			1		14.8		15.0
	Idaho:
		Cabinet Gorge (Clark Fork)			4		245.1		246.0
		Post Falls (Spokane)			6		14.8		18.0
	Montana:
		Noxon Rapids (Clark Fork)			5		466.2		527.0

			Total Hydroelectric				879.3		964.7
Thermal Generating Stations
	Washington:
		Kettle Falls			1		50.7		50.0
		Kettle Falls CT			1		6.9		6.9
		Northeast (Spokane) CT			2		61.8		66.8
		Boulder Park			6		24.6		24.6
	Idaho:
		Rathdrum CT (1)			2		166.5		176.0
	Montana:
		Colstrip (Units 3 and 4) (4)			2		233.4		222.0
	Oregon:
		Coyote Springs 2 (5)			1		140.0		140.0

			Total Thermal				683.9		686.3
	Total Generation Properties						1,563.2		1,651.0

	(1)		All generation properties are owned by Avista Utilities with the exception of the Rathdrum CT, which is leased from WP Funding LP, an entity that is included in Avista Corp.’s consolidated financial statements.

	(2)		Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.

	(3)		Present capability is the maximum capacity of the plant without exceeding approved limits of temperature, stress and environmental conditions.

	(4)		Jointly owned; data refers to Avista Utilities’ 15 percent interest.

	(5)		Jointly owned; data refers to Avista Utilities’ 50 percent interest.

Electric Distribution and Transmission Plant

Avista Utilities operates approximately 16,900 miles of primary and secondary electric distribution lines. Avista Utilities completed a field inventory of its primary and secondary electric distribution lines and has been able to determine a more accurate measure of the miles of distribution lines than in prior years. The significant increase (12,200 miles reported in 2002) in the miles of distribution lines primarily reflects a more accurate measurement process and not growth in Avista Utilities’ distribution system. Avista Utilities has an electric transmission system of approximately 615 miles of 230 kV line and 1,535 miles of 115 kV line. Avista Utilities also owns an 11 percent interest (representing 465 MW capacity) in 495 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. The transmission and distribution system also includes numerous substations with transformers, switches, monitoring and metering devices, and other equipment related to its operation.

AVISTA CORPORATION

The 230 kV lines are used to transmit power from Noxon Rapids and Cabinet Gorge to major load centers in Avista Utilities’ service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect with the Bonneville Power Administration (BPA) at five locations and at one location each with PacifiCorp, NorthWestern Energy and Idaho Power Company. The BPA interconnections serve as points of delivery for power from the Colstrip generating station, as well as for the interchange of power with entities within and outside the Pacific Northwest. The interconnection with PacifiCorp is used to integrate Mid-Columbia hydroelectric generating facilities to Avista Utilities’ loads, as well as for the interchange of power with entities within and outside the Pacific Northwest.

The 115 kV lines provide for transmission of energy and the integration of the Spokane River hydroelectric and Kettle Falls wood-waste generating stations with service-area load centers. These lines interconnect with BPA at nine locations, Grant County PUD, Seattle City Light and Tacoma City Light at two locations each and one interconnection each with Chelan County PUD, PacifiCorp and NorthWestern Energy.

Avista Utilities is currently in the process of expanding and enhancing its 230 kV transmission system, which Avista Utilities expects to be completed by the end of 2006.

Natural Gas Plant

Avista Utilities has natural gas distribution mains of approximately 2,609 miles in Washington, 1,502 miles in Idaho, 1,742 miles in Oregon and 233 miles in California. The natural gas distribution system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment related to its operation.

Avista Utilities owns a one-third interest in Jackson Prairie, which has a total peak day deliverability of 8.8 million therms, with a total working natural gas inventory of 190.3 million therms. Avista Utilities has contracted to release a total of approximately 37 percent of its Jackson Prairie capacity to two other utilities. One of these contracts requires two-years notice for termination and one contract is renewed on a year-to-year basis.

Item 3. Legal Proceedings

See “Note 25 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.

Item 4. Submission of Matters to a Vote of Security Holders

None.

AVISTA CORPORATION

PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

Outstanding shares of common stock are listed on the New York and Pacific Stock Exchanges. As of March 1, 2004, there were approximately 16,142 registered shareholders of the Company’s no par value common stock.

The Board of Directors considers the level of dividends on the Company’s common stock on a regular basis, taking into account numerous factors including, without limitation, the Company’s results of operations, cash flows and financial condition, as well as the success of the Company’s strategies and general economic and competitive conditions. The Company’s net income available for dividends is derived primarily from the operations of Avista Utilities and Avista Energy.

Avista Energy holds a significant portion of the cash and cash equivalents reflected on the Consolidated Balance Sheet. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. These covenants allow for the payment of dividends from Avista Energy to Avista Capital up to current earnings levels. During 2003, Avista Energy paid $12.1 million in dividends to Avista Capital.

For additional information, refer to “Notes 1, 22, 23 and 24 of Notes to Consolidated Financial Statements.” For high and low stock price information, refer to “Note 26 of Notes to Consolidated Financial Statements.”

For information with respect to securities authorized for issuance under equity compensation plans see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

AVISTA CORPORATION

Item 6. Selected Financial Data

(in thousands, except per share data and ratios)


		Years Ended December 31,

		2003			2002			2001			2000			1999
Operating Revenues:
	Avista Utilities	$	928,211		$	893,964		$	1,230,847		$	1,512,101		$	1,115,647
	Energy Marketing and Resource Management		307,141			222,634			403,743			546,893			18,330
	Avista Advantage		19,839			16,911			13,151			4,971			1,518
	Other		13,581			14,645			16,385			32,937			122,303
	Intersegment Eliminations		(145,387	)		(85,238	)		(152,375	)		(161,423	)		(28,705	)

	Total	$	1,123,385		$	1,062,916		$	1,511,751		$	1,935,479		$	1,229,093

Income (Loss) from Operations (pre-tax):
	Avista Utilities	$	146,777		$	149,180		$	114,927		$	3,177		$	142,567
	Energy Marketing and Resource Management		30,078			29,211			94,669			250,196			(97,785	)
	Avista Advantage		(1,331	)		(6,363	)		(15,098	)		(14,482	)		(5,042	)
	Other		(3,821	)		(14,886	)		(10,432	)		(9,861	)		(423	)

	Total	$	171,703		$	157,142		$	184,066		$	229,030		$	39,317

Income (Loss) from Continuing Operations:
	Avista Utilities	$	36,241		$	36,382		$	24,164		$	(38,781	)	$	59,573
	Energy Marketing and Resource Management		20,672			22,425			63,246			161,753			(60,739	)
	Avista Advantage		(1,334	)		(4,253	)		(10,748	)		(11,022	)		(3,428	)
	Other		(4,936	)		(12,380	)		(8,421	)		(2,885	)		35,817

	Total		50,643			42,174			68,241			109,065			31,223
Loss from discontinued operations			(4,949	)		(6,719	)		(56,085	)		(17,386	)		(5,192	)

Net Income before cumulative effect of accounting change			45,694			35,455			12,156			91,679			26,031
Cumulative effect of accounting change			(1,190	)		(4,148	)		—			—			—

Net income			44,504			31,307			12,156			91,679			26,031
Deduct - preferred stock dividend requirements (1)			1,125			2,402			2,432			23,735			21,392

Income available for common stock		$	43,379		$	28,905		$	9,724		$	67,944		$	4,639

Average common shares outstanding, basic			48,232			47,823			47,417			45,690			38,213
Average common shares outstanding, diluted			48,630			47,874			47,435			46,103			38,325
Common shares outstanding at year-end			48,344			48,044			47,633			47,209			35,648
Earnings per Common Share:
	Avista Utilities	$	0.72		$	0.71		$	0.46		$	(1.37	)	$	1.00
	Energy Marketing and Resource Management		0.43			0.47			1.33			3.51			(1.59	)
	Avista Advantage		(0.03	)		(0.09	)		(0.23	)		(0.23	)		(0.09	)
	Other		(0.10	)		(0.26	)		(0.18	)		(0.06	)		0.94

	Earnings per common share from continuing operations, diluted		1.02			0.83			1.38			1.85			0.26
	Loss per common share from discontinued operations, diluted		(0.10	)		(0.14	)		(1.18	)		(0.38	)		(0.14	)

	Earnings per common share before cumulative effect of accounting change, diluted		0.92			0.69			0.20			1.47			0.12
	Cumulative effect of accounting change, diluted		(0.03	)		(0.09	)		—			—			—

	Total earnings per common share, diluted	$	0.89		$	0.60		$	0.20		$	1.47		$	0.12

	Total earnings per common share, basic	$	0.90		$	0.60		$	0.21		$	1.49		$	0.12
	Dividends paid per common share		0.49			0.48			0.48			0.48			0.48
	Book value per common share at year-end	$	15.54		$	14.84		$	15.12		$	15.34		$	11.04
Total Assets at Year-End:
	Avista Utilities	$	2,563,572		$	2,369,418		$	2,569,798		$	2,306,221		$	2,138,606
	Energy Marketing and Resource Management		1,013,213			1,349,626			1,506,185			10,271,834			1,595,470
	Avista Advantage		36,405			31,733			20,288			11,063			3,925
	Other		48,305			42,866			86,514			96,362			114,929
	Discontinued Operations		—			5,900			27,919			54,031			22,454

	Total	$	3,661,495		$	3,799,543		$	4,210,704		$	12,739,511		$	3,875,384

Long-Term Debt (not including current portion)		$	925,012		$	902,635		$	1,175,715		$	679,806		$	714,904
Long-Term Debt to Affiliated Trusts (2)			113,403			—			—			—			—
Company-Obligated Mandatorily Redeemable Preferred Trust Securities (2)			—			100,000			100,000			100,000			110,000
Preferred Stock Subject to Mandatory Redemption (1)			29,750			33,250			35,000			35,000			35,000
Convertible Preferred Stock			—			—			—			—			263,309
Common Equity		$	751,252		$	712,791		$	720,063		$	724,224		$	393,499
Ratio of Earnings to Fixed Charges			1.88			1.69			1.98			3.62			1.71
Ratio of Earnings to Fixed Charges and Preferred Dividend Requirements			1.85			1.63			1.91			2.31			1.15

(1)		Preferred Stock Subject to Mandatory Redemption was reclassified from equity to liabilities in 2003 with the adoption of SFAS No. 150. Accordingly, preferred stock dividend requirements were reclassified to interest expense effective July 1, 2003. See Note 2 of the Consolidated Financial Statements. Balance as of December 31, 2003 does not include current portion.

(2)		Company-Obligated Mandatorily Redeemable Preferred Trust Securities was reclassified to Long-Term Debt to Affiliated Trusts in 2003 with the adoption of FASB Interpretation No. 46. See Note 2 of the Consolidated Financial Statements.

AVISTA CORPORATION

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Safe Harbor for Forward-Looking Statements

This Report on Form 10-K contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Avista Corporation (Avista Corp. or the Company) is including the following cautionary statement to make applicable, and to take advantage of, the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, projections of future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions). Forward-looking statements are all statements other than statements of historical fact including, without limitation, those that are identified by the use of words such as, but not limited to, “will,” “anticipates,” “seeks to,” “estimates,” “expects,” “intends,” “plans,” “predicts,” and similar expressions. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements.

Such statements are inherently subject to a variety of risks and uncertainties that could cause actual results to differ materially from those expressed. Certain of these risks and uncertainties are beyond the Company’s control. Such risks and uncertainties include, among others:

•		changes in the utility regulatory environment in the individual states and provinces in which the Company operates and the United States and Canada in general. This can impact allowed rates of return, financings, or industry and rate structures;

•		the impact of regulatory and legislative decisions including Federal Energy Regulatory Commission (FERC) price controls, and including possible retroactive price caps and resulting refunds;

•		The potential effects of any legislation or administrative rulemaking passed into law;

•		the impact from the potential formation of a Regional Transmission Organization and/or an Independent Transmission Company;

•		the impact from the implementation of the FERC’s proposed wholesale power market rules;

•		volatility and illiquidity in wholesale energy markets, including the availability and prices of purchased energy and demand for energy sales;

•		wholesale and retail competition (including, but not limited to, electric retail wheeling and transmission costs);

•		future streamflow conditions that affect the availability of hydroelectric resources;

•		outages at any company-owned generating facilities from any cause including equipment failure;

•		unanticipated delays or changes in construction costs with respect to present or prospective facilities;

•		changes in weather conditions that can affect customer demand, result in natural disasters and/or disrupt energy delivery;

•		changes in industrial, commercial and residential growth and demographic patterns in the Company’s service territory;

•		the loss of significant customers and/or suppliers;

•		failure to deliver on the part of any parties from which the Company purchases and/or sells capacity or energy;

•		changes in the creditworthiness of customers and energy trading counterparties;

•		the Company’s ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including the Company’s credit ratings, interest rate fluctuations and other capital market conditions;

•		changes in future economic conditions in the Company’s service territory and the United States in general, including inflation or deflation and monetary policy;

•		the potential for future terrorist attacks, particularly with respect to utility plant assets;

•		changes in tax rates and/or policies;

•		changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs;

•		the outcome of legal and regulatory proceedings concerning the Company or affecting directly or indirectly its operations, including the potential disallowance of previously deferred costs;

•		employee issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, as well as the ability to recruit and retain employees;

•		changes in actuarial assumptions and the return on assets with respect to the Company’s pension plan, which can impact future funding obligations, costs and pension plan liabilities;

AVISTA CORPORATION

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

•		increasing costs of insurance, changes in coverage terms and the ability to obtain insurance.

The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. However, there can be no assurance that the Company’s expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. The Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company’s business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

The following discussion and analysis is provided for the consolidated financial condition and results of operations of Avista Corp., including its subsidiaries. This discussion focuses on significant factors concerning the Company’s financial condition and results of operations and should be read along with the consolidated financial statements.

Avista Corp. Business Segments

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. The Company has four business segments - Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. As of December 31, 2003, the Company had common equity investments of $494.0 million and $257.2 million in Avista Utilities and Avista Capital, respectively.

The Energy Marketing and Resource Management business segment is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily in the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states and the provinces of British Columbia and Alberta, Canada. Avista Power is an investor in certain generation assets, primarily its 49 percent interest in a 270-megawatt (MW) natural gas-fired combustion turbine plant in northern Idaho (Lancaster Project).

Avista Advantage, Inc. (Avista Advantage) is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling services.

The Other business segment includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development and certain other operations of Avista Capital. Included in this business segment is Advanced Manufacturing and Development (AM&D) doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal manufacturing of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also has a wood products division that provides complete fabrication and turnkey assembly for arcade games, kiosks, store fixtures, and displays.

Executive Level Summary

Avista Corp.’s net income and operating cash flows are derived primarily from its energy-related business: Avista Utilities and Avista Energy (included in the Energy Marketing and Resource Management segment). Avista Corp. intends to focus on improving earnings and operating cash flows, controlling costs and reducing debt while working to restore an investment grade credit rating.

Avista Utilities will seek to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. The utility business is expected to grow modestly, consistent with historical trends. Expansion is expected to result primarily from economic and population growth in its service territory. It is Avista Utilities’ strategy to own or to have contracts that provide a sufficient amount of resources to meet its retail and wholesale energy requirements under a range of operating conditions. Available resources and the costs of those resources are significantly affected by Avista Utilities’ hydroelectric production, which was 89 percent

AVISTA CORPORATION

of normal in 2003. Based on forecasts and snowpack conditions as of February 2004, Avista Utilities expects hydroelectric production will be approximately 95 percent of normal in 2004. This forecast may change based upon additional precipitation, temperatures and other variables. Customer loads and resulting revenues are significantly affected by weather. During 2003, the weather in Avista Utilities’ service territory was warmer than normal during the heating season (particularly the first quarter). Avista Utilities expects a return to more normal weather in 2004. As is the case with most regulated entities, Avista Utilities generally has ongoing regulatory proceedings. Avista Utilities continues to make progress with respect to resolving its regulatory matters; however, significant issues remain unresolved (see “Avista Utilities - Regulatory Matters” and “Power Market Issues”). Avista Utilities will continue to file for rate adjustments to achieve recovery of its costs, to more closely align earned returns with those allowed by regulatory agencies in each jurisdiction. The Company expects Avista Utilities’ net income will increase in 2004 as compared to 2003 assuming more normal hydroelectric production and weather, a decrease in interest expenses and the implementation of general rate increases.

Avista Utilities faces issues with respect to an aging workforce at all levels of its operations. It is expected that approximately 30 percent of the workforce will retire in the next 5 to 15 years. Management succession plans have been implemented to work towards ensuring that executive officer positions are appropriately filled. Avista Utilities has taken similar steps in key technical and craft areas to work towards ensuring that these positions will be appropriately filled when retirements occur.

Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric and natural gas transmission and transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 400 industrial customers in British Columbia, Canada. In addition to earnings and resulting cash flows from settled or realized transactions, Avista Energy records unrealized or mark-to-market adjustments for the change in the value of derivative commodity instruments. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. Avista Energy is also subject to certain regulatory proceedings that remain unresolved (see “Power Market Issues”); however, Avista Energy believes that it has adequate reserves established for any refunds that may be ordered. The wholesale power markets in which Avista Energy operates continue to change with respect to market participants involved, level of activity, volatility in market prices, liquidity, FERC-imposed price caps and counterparty credit issues. The Company expects that net income from Avista Energy will decrease in 2004 as compared to 2003. This is primarily due to the positive effects in 2003 of accounting for energy trading activities under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” and the settlement of positions with certain Enron Corporation (Enron) affiliates.

Avista Advantage remains focused on increasing revenues, improving margins, and continuously enhancing client satisfaction. The Company expects Avista Advantage will be break-even or generate slightly positive net income for 2004 based on improving revenues and stabilized operating expenses from processing efficiencies.

Over time as opportunities arise, the Company plans to dispose of assets and phase out operations in the Other business segment. The Company expects the net loss in the Other business segment to be less in 2004 as compared to 2003 due to the resolution of prior legal matters as well as decreased losses from current investments and the operations of AM&D.

During 2004, the Company expects that cash flows from operations and Avista Corp.’s committed line of credit will provide adequate resources to fund capital expenditures, maturing long-term debt and other contractual commitments. However, if market conditions warrant during 2004, the Company may issue long-term debt to fund these obligations, refinance existing debt and repurchase long-term debt scheduled to mature in future years to reduce its overall debt service costs, as well as to reduce the impact of significant debt maturities scheduled for 2007 and 2008.

Avista Utilities - Resource Optimization

Avista Utilities owns and operates eight hydroelectric projects, a wood-waste fueled generating station, a two-unit natural gas-fired combustion turbine (CT) generating facility and two small generating facilities. It also owns a 15 percent share in a two-unit coal-fired generating facility and leases and operates a two-unit natural gas-fired CT generating facility. WP Funding LP, an entity that is included in Avista Corp.’s consolidated financial statements and included in the Avista Utilities business segment, owns the two-unit natural gas-fired CT generating facility that

AVISTA CORPORATION

is leased by Avista Utilities. In July 2003, the combined cycle natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) was placed into operation. Avista Utilities has a 50 percent ownership interest (140 MW) in Coyote Springs 2. See “Avista Utilities-Developments with Coyote Springs 2” for information with respect to a transformer failure at Coyote Springs 2. Avista Utilities’ facilities have a total net capability of approximately 1,651 MW, of which 58 percent is hydroelectric and 42 percent is thermal. In addition to company owned resources, Avista Utilities has a number of long-term power purchase and exchange contracts that increase its available resources.

Avista Utilities - Regulatory Matters

General Rate Cases

Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. In February 2004, Avista Utilities filed electric and natural gas general rate cases in Idaho. The request is designed to increase electric revenues by 11 percent, or $18.9 million in annual revenues, over current rates. This would result from a 24 percent increase in base retail rates (an increase of $35.2 million in annual revenues) offset by a $16.3 million annual revenue decrease from the current Power Cost Adjustment (PCA) surcharge. Avista Utilities also requested a natural gas general rate increase of 9.2 percent, or $4.8 million in annual revenues. Avista Utilities’ requests are based on an overall rate of return of 9.82 percent and a return on equity of 11.5 percent. The Idaho Public Utilities Commission (IPUC) generally has up to seven months to review the general rate case filings.

In September 2003, the Oregon Public Utilities Commission (OPUC) approved a general natural gas rate increase of $6.3 million in annual revenues effective October 1, 2003 that authorizes, among other things, an overall rate of return of 8.88 percent and a return on equity of 10.25 percent.

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs that are in excess of the level currently recovered from retail customers as authorized by the WUTC and the IPUC. A portion of power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through retail rates.

The Washington Utilities and Transportation Commission (WUTC) issued an order effective July 1, 2002 providing for restructuring of rate increases previously approved by the WUTC totaling 31.2 percent. The July 2002 rate change increased base retail rates 19.3 percent and provided an 11.9 percent continuing surcharge over previous base retail rates for the recovery of deferred power costs. The WUTC rate order also established an Energy Recovery Mechanism (ERM) effective July 1, 2002. The ERM replaced a series of temporary deferral mechanisms that had been in place in Washington since mid-2000. The ERM allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of the power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company. The Company expensed the initial $9.0 million of power supply costs above the amount included in base retail rates during the first quarter of 2003 and expects to expense the initial $9.0 million during 2004. This is primarily due to costs related to fuel contracts entered into during 2001 that expire in the second half of 2004 for the Company’s thermal generating units.

AVISTA CORPORATION

The following table shows activity in deferred power costs for Washington and Idaho during 2002 and 2003 (dollars in thousands):


		Washington			Idaho			Total

Deferred power costs as of December 31, 2001		$	140,238		$	73,087		$	213,325
Activity from January 1 - December 31, 2002:
	Power costs deferred		22,423			13,471			35,894
	Unrealized gain on fuel contracts (1)		(7,068	)		(3,485	)		(10,553	)
	Interest and other net additions		6,726			888			7,614
	Amortization of deferred credit		-			(27,711	)		(27,711	)
	Recovery of deferred power costs through retail rates		(38,570	)		(24,732	)		(63,302	)

Deferred power costs as of December 31, 2002			123,749			31,518			155,267
Activity from January 1 - December 31, 2003:
	Power costs deferred		22,217			23,341			45,558
	Unrealized loss on fuel contracts (1)		1,975			1,004			2,979
	Interest and other net additions		6,002			1,037			7,039
	Write-off deferred power costs		(2,461	)		-			(2,461	)
	Recovery of deferred power costs through retail rates		(25,777	)		(26,615	)		(52,392	)

Deferred power costs as of December 31, 2003		$	125,705		$	30,285		$	155,990

(1)

Unrealized gains and losses on fuel contracts are not included in the ERM and PCA mechanism until the contracts are settled or realized.

It is expected that the recovery of deferred power costs will take several years.

Purchased Gas Adjustments

Natural gas commodity prices increased towards the end of 2002 and into the first half of 2003 before declining somewhat in the middle of 2003 and increasing at the end of 2003. The continued tight balance between supply and demand for natural gas is a major contributor to the ongoing price volatility in natural gas, and this is expected to continue into 2004. Avista Utilities’ average prices per dekatherm were $5.50, $4.95 and $6.33 in 2003, 2002 and 2001, respectively. The Company is well connected to multiple supply basins in the western United States and western Canada and believes there will be sufficient supplies of natural gas to meet its customers’ needs. However, natural gas prices in the Pacific Northwest are increasingly affected by supply and demand factors in other regions of the United States and Canada. Natural gas commodity costs in excess of the amount recovered in current rates are deferred and recovered in future periods with applicable regulatory approval through adjustments to rates. Market

AVISTA CORPORATION

prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. Avista Utilities believes that natural gas should sustain its market advantage over competing energy sources based on the levels of existing reserves and potential natural gas development in the future.

During the second half of 2002, Avista Utilities adjusted its natural gas rates in response to a decrease in current and projected natural gas costs at that time. During the fourth quarter of 2002, natural gas rate decreases of 17.4 percent, 15.5 percent, 7.1 percent and 16.2 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. As discussed above, current and projected natural gas prices increased towards the end of 2002 and into the first half of 2003. During September and October of 2003, natural gas rate increases of 8.7 percent, 2.4 percent, 12.4 percent and 15.0 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. The rate increase in Washington was approved subject to refund, pending further review of the deferred natural gas costs. In February 2004, Avista Utilities filed a request for a 7.3 percent increase in Oregon to be effective April 1, 2004. These natural gas rate increases and decreases are designed to pass through changes in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income. Total deferred natural gas costs were $15.4 million and $11.5 million as of December 31, 2003 and 2002, respectively.

Natural Gas Benchmark Mechanism

The IPUC, WUTC and OPUC approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations in Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets are managed by Avista Energy through an Agency Agreement. The Natural Gas Benchmark Mechanism provides benefits to retail customers and allows Avista Energy to retain a portion of the benefits associated with asset optimization and the efficiencies gained in purchasing natural gas for Avista Utilities as part of Avista Energy’s larger portfolio of natural gas assets. In early 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. In January 2003, the WUTC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through January 29, 2004. In April 2003, the Company filed a request with the WUTC to amend certain aspects of the Natural Gas Benchmark Mechanism and related Agency Agreement and requested an extension through March 31, 2007. In July 2003, the WUTC staff and the Public Counsel Section of the Attorney General’s Office filed testimony recommending the termination of the Natural Gas Benchmark Mechanism in Washington. Hearings were held before the WUTC during the fourth quarter of 2003 and the first part of 2004. In February 2004, the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. The transition plan will be filed by March 15, 2004. It is estimated that the termination of the Natural Gas Benchmark Mechanism and related Agency Agreement will result in a reduction of approximately $1.0 million in Avista Energy’s pre-tax earnings and an increase in costs of approximately $1.0 million for Avista Utilities. Avista Utilities would seek recovery of any additional costs in a future general rate case proceeding. This transition of Avista Utilities’ natural gas procurement operations will also impact the level of counterparty credit requirements at both Avista Utilities and Avista Energy.

Significant Customer Contract

A power purchase and sales contract with Potlatch Corporation (Potlatch) expired on December 31, 2001. Potlatch’s Lewiston, Idaho facility has electric requirements of about 100 average megawatts (aMW). The facility also typically produces approximately 60 aMW of generation. Since January 2002, Potlatch had been using its generation to supply a portion of its own electric requirements, which resulted in a net electric requirement on Avista Utilities’ system of approximately 40 aMW. In July 2003, Avista Utilities and Potlatch executed a ten-year power purchase and sales contract, under which Avista Utilities will purchase up to 62 aMW of Potlatch’s generation at a price slightly below the IPUC administratively determined avoided cost rate. Avista Utilities may also purchase generation above 62 aMW at a price that is somewhat below market prices, when market conditions are such that it is mutually beneficial to Potlatch and Avista Utilities. Avista Utilities will serve Potlatch’s entire electric requirements of approximately 100 aMW at the retail tariff rates established for large industrial customers, unless a different rate is ordered by the IPUC. Potlatch’s generation and loads are separately measured and billed by Avista Utilities. When Potlatch’s generation experiences an interruption, Avista Utilities serves the full Potlatch facility load from its system. In January 2004, the agreement was approved by the IPUC, including the full recovery of the costs associated with the agreement through the Idaho PCA mechanism or base retail rates. Avista Utilities does not expect the agreement to have a material impact on future net income.

AVISTA CORPORATION

Power Market Issues

Counterparty Defaults

In early 2001, California’s two largest utilities defaulted on payment obligations owed to various energy sellers, including Avista Energy, resulting in defaults by the California Power Exchange (CalPX) and the California Independent System Operator (CalISO). Pacific Gas & Electric Company (PG&E) and the CalPX filed for bankruptcy in 2001. The settlement of defaulted obligations will depend on PG&E paying its debt upon emerging from bankruptcy and a determination of the California refund claims (see further information under “California Refund Proceeding”). As of December 31, 2003, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and refunds. Avista Energy is pursuing recovery of the defaulted obligations.

California Refund Proceeding

In July 2001, the FERC initiated a proceeding to determine if refunds should be owed and, if so, the amounts of such refunds for sales during the period from October 2, 2000 to June 20, 2001 in the California power market. The order provides that any refunds owed could be offset against unpaid energy debts due to the same party. Interested parties have contested pricing determinants and other matters since the proceeding started. The CalISO and the CalPX prepared revised values for the affected power transactions and they are preparing additional iterations of revised prices and terms as directed by the FERC. The results of these calculations are likely to be appealed to the FERC and federal courts. In March 2003, the FERC issued an order that addressed issues related to the California refund proceedings, setting forth proposed retroactive pricing standards. In June 2003, the FERC issued an order to review bids above $250 per MW made by participants in the short-term energy markets operated by the CalISO and the CalPX from May 1, 2000 to October 2, 2000. Market participants with bids above $250 per MW during the period described above will be required to demonstrate why their bidding behavior and practices did not violate applicable market rules. If violations were found to exist, the FERC would require the refund of any unjust profits and could also enforce other non-monetary penalties, such as the revocation of market-based rate authority. Avista Energy is subject to this review. Avista Energy maintains that it has engaged in sound business practices in accordance with established market rules. Based on current information, the Company believes that it has sufficient reserves in place for potential California refunds.

Pacific Northwest Refund Proceeding

In July 2001, the FERC initiated a proceeding to determine if refunds should be owed and, if so, the amounts of such refunds for sales during the period from December 25, 2000 to June 20, 2001 in the Pacific Northwest power market. Various parties including aggrieved parties, FERC staff, and alleged beneficiaries of excess prices filed pleadings, analyses, and motions related to the requested refunds in the two years following the initiation of this proceeding. In June 2003, the FERC denied the request for retroactive refunds for spot market sales in the Pacific Northwest power market. In July 2003, a group, which includes Avista Utilities and Avista Energy, filed a request for rehearing supporting the FERC’s decision to deny retroactive refund claims in the Pacific Northwest spot market but raising argument on certain procedural issues only in the event that the FERC entertains additional arguments in the case. Also in July 2003, several other parties filed requests for rehearing on the FERC’s June 2003 order. The requests for rehearing were denied by the FERC in November 2003. A petition for review of the FERC’s decision was filed by the City of Tacoma on December 24, 2003, with the United States Court of Appeals for the Ninth Circuit. Final closure of the Pacific Northwest refund proceeding will await appellate court review and the Company cannot predict its ultimate conclusion.

Market Conduct Investigations

As a result of certain revelations about alleged improper practices engaged in by Enron and certain of its affiliates, the FERC initiated investigations in February 2002 of Avista Utilities, Avista Energy and other unrelated parties. Avista Utilities and Avista Energy cooperated with the FERC investigation by providing requested documents and other information. Several parties filed documents with the FERC in March 2003 alleging improper market conduct by various parties, including Avista Utilities and Avista Energy, and requesting refunds and other relief. Based upon review of the filings, there were no new allegations or information not known to and addressed by the FERC trial staff in its investigations of Avista Corp. and Avista Energy. Avista Corp. and Avista Energy filed replies in response to the allegations of the parties.

In March 2003, the FERC policy staff issued its final report on their investigation of western energy markets. In the report, the FERC policy staff recommended the issuance of “show cause” orders to dozens of companies to respond to allegations of possible misconduct in the western energy markets during 2000 and 2001. Of the companies named in the March 2003 FERC policy staff report, Avista Corp. and Avista Energy were among the few that had already been subjects of a FERC investigation. As explained at “Federal Energy Regulatory Commission Inquiry” in “Note

AVISTA CORPORATION

25 of the Notes to Consolidated Financial Statements” regarding the investigation of Avista Corp. and Avista Energy, the FERC trial staff stated that its investigation found no evidence that: (1) any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy; (2) Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) Avista Utilities or Avista Energy withheld relevant information from the FERC’s inquiry into the western energy markets for 2000 and 2001. In July 2003, the FERC’s administrative law judge certified the agreement in resolution with respect to the FERC’s investigation of Avista Corp. and Avista Energy and forwarded it to the FERC commissioners for final approval. Final approval of the agreement in resolution has remained pending before the FERC since July 2003.

See further information under “Federal Energy Regulatory Commission Inquiry,” “U.S. Commodity Futures Trading Commission (CFTC) Subpoena,” “California Energy Markets,” “Port of Seattle Complaint,” and “State of Montana Proceedings” in “Note 25 of the Notes to Consolidated Financial Statements.”

Regional Transmission Organizations

Wholesale Power Market Design

AVISTA CORPORATION

Results of Operations

Diluted Earnings (Loss) per Common Share by Business Segments

The following table presents diluted earnings (loss) per common share by business segments for the years ended December 31:


		2003			2002			2001

Avista Utilities		$	0.72		$	0.71		$	0.46
Energy Marketing and Resource Management			0.43			0.47			1.33
Avista Advantage			(0.03	)		(0.09	)		(0.23	)
Other			(0.10	)		(0.26	)		(0.18	)

	Earnings per common share from continuing operations		1.02			0.83			1.38
Loss per common share from discontinued operations			(0.10	)		(0.14	)		(1.18	)

	Earnings per common share before cumulative effect of accounting change		0.92			0.69			0.20
Loss per common share from cumulative effect of accounting change			(0.03	)		(0.09	)		—

	Total earnings per common share, diluted	$	0.89		$	0.60		$	0.20

Overall Operations

2003 compared to 2002

Income from continuing operations was $50.6 million for 2003 compared to $42.2 million for 2002. The increase was primarily due to a decrease in the net losses for Avista Advantage and the Other business segment, partially offset by decreased net income for Energy Marketing and Resource Management.

Net income for Energy Marketing and Resource Management was $20.7 million (excluding the cumulative effect of accounting change) for 2003 compared to $22.4 million for 2002. This decrease was primarily due to a $3.2 million (net of tax) impairment charge recorded by Avista Power, partially offset by an increase in gross margin for Avista Energy. During 2003, Avista Energy’s earnings were positively impacted by the effects of accounting for energy contracts under SFAS No. 133 and a settlement with certain Enron affiliates. Avista Energy’s transition to SFAS No. 133 resulted in contracts, which are not considered derivatives, no longer being accounted for at market value. The transition to SFAS No. 133 increased the volatility of reported earnings due to the fact that certain contracts, which are not considered derivatives, are economically hedged by contracts that are accounted for as derivative instruments at market value under SFAS No. 133. During September 2003, Avista Energy implemented hedge accounting for certain transactions. This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis.

Net income for Avista Utilities was $36.2 million for 2003, compared to $36.4 million for 2002. The decrease for Avista Utilities was primarily due to an increase in other operating expenses (operations and maintenance, administrative and general, and depreciation and amortization), partially offset by an increase in gross margin and a decrease in interest expense.

Avista Advantage incurred a net loss of $1.3 million for 2003 compared to $4.3 million for 2002. The decrease in the net loss was primarily due to an increase in operating revenues and a decrease in operating expenses.

The Other business segment incurred a net loss of $4.9 million for 2003 compared to $12.4 million (excluding the cumulative effect of accounting change) for 2002. The decrease in the net loss was primarily due to a reduction in litigation costs and settlements.

Total revenues increased $60.5 million for 2003 compared to 2002. Avista Utilities’ revenues increased $34.2 million, or 4 percent, primarily due to increased electric revenues, partially offset by decreased natural gas revenues. The decrease in natural gas revenues was primarily due to natural gas rate decreases implemented during the fourth quarter of 2002 and partially due to decreased therms sold as a result of warmer weather during the first quarter of 2003 as compared to the first quarter of 2002. Natural gas rate increases have been implemented in September and October 2003 in response to increased natural gas costs, which should increase retail natural gas revenues for 2004. The increase in electric revenues reflects an increase in retail revenues, wholesale revenues and sales of fuel. Revenues from Energy Marketing and Resource Management increased $84.5 million, or 38 percent, primarily due to increased revenues on contracts that are not considered derivatives under SFAS No. 133 (primarily the Agency

AVISTA CORPORATION

Agreement with Avista Utilities), non-trading derivative contracts and revenues from Avista Energy Canada. Avista Energy’s settlement of various positions with Enron affiliates and the resulting release by Avista Energy of amounts, which had been reserved against such positions, also had a positive impact of $8.4 million on operating revenues for 2003. Revenues from Avista Advantage increased 17 percent to $19.8 million primarily as a result of customer growth. Revenues from the Other business segment decreased $1.1 million primarily due to decreased revenues from AM&D.

Total resource costs increased $39.8 million for 2003 compared to 2002. Resource costs for Avista Utilities increased $21.4 million primarily due to an increase in the expense for power purchased, natural gas purchased, fuel for generation and other fuel costs, partially offset by a decrease in the net amortization of deferred power and natural gas costs. The increase in power purchased expense and natural gas purchased was primarily due to an increase in prices. Resource costs for Energy Marketing and Resource Management increased $78.5 million due to an increase in costs from contracts that are not accounted for as derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities), non-trading derivative contracts and resource costs of Avista Energy Canada, partially offset by a change in natural gas inventory valuations.

Intersegment eliminations, which decreases both operating revenues and resource costs, increased to $145.4 million for 2003 from $85.2 million for 2002, representing increased purchases of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Operations and maintenance expenses increased $12.1 million for 2003 compared to 2002 primarily due to increased expenses for Avista Utilities and the $4.9 million impairment of a turbine at Avista Power (Energy Marketing and Resource Management segment), partially offset by decreased expenses for Avista Advantage and the Other business segment. The increase in operations and maintenance expenses for Avista Utilities was partially due to increased pension costs, and expenses for Coyote Springs 2, which commenced operations in mid-2003. The increase for Avista Utilities was also due to initiatives implemented during the third quarter of 2001 designed to temporarily reduce certain operating expenses to improve liquidity and operating cash flows. These initiatives resulted in significantly reduced expenses for 2001 and the first half of 2002.

Administrative and general expenses decreased $8.2 million for 2003 compared to 2002 primarily due to decreased expenses for the Other business segment, partially offset by increased expenses for Avista Utilities and Energy Marketing and Resource Management. Administrative and general expenses for the Other business segment decreased due to reduced litigation costs and settlements. The increase for Energy Marketing and Resource Management was primarily a result of increased compensation expenses. The increase for Avista Utilities was consistent with the increase in operations and maintenance expenses. Increased insurance costs also contributed to the increase in administrative and general expenses for Avista Utilities.

Depreciation and amortization increased $5.9 million for 2003 compared to 2002 primarily due to utility plant additions at Avista Utilities and the resulting increase in depreciation expense. Coyote Springs 2 was placed into service in mid-2003 and increased depreciation expense by $2.2 million.

Taxes other than income taxes decreased $3.8 million for 2003 compared to 2002 primarily due to decreased retail natural gas revenues and related taxes for Avista Utilities.

Interest expense decreased $11.9 million for 2003 compared to 2002 primarily due to a decrease in the average balance of debt outstanding. This decrease was partially offset by the inclusion of $1.1 million of preferred stock dividends as interest expense for the second half of 2003 in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (see Note 2 of the Notes to Consolidated Financial Statements). During 2003 and 2002, the Company repurchased $52.5 million and $203.6 million of long-term debt, respectively. The Company expects interest expense to continue to decline in 2004 due to the effect of debt repurchases. In September 2003, the Company issued $45.0 million of 6.125 percent First Mortgage Bonds due in 2013. The proceeds were used to repay a portion of the borrowings under the $245.0 million line of credit that were used on an interim basis to fund $46.0 million of maturing 9.125 percent Unsecured Medium-Term Notes and should result in an overall reduction in the Company’s interest expense.

Capitalized interest decreased $6.4 million for 2003 compared to 2002. This was primarily due to the fact that the Company did not capitalize any interest related to Coyote Springs 2 subsequent to September 30, 2002 because the project was substantially completed.

Other income-net decreased $11.1 million for 2003 compared to 2002 primarily due to reduced interest income

AVISTA CORPORATION

(including accrued interest on power and natural gas deferrals) as well as losses in 2003 on certain investments in the Other business segment. The decrease in interest income primarily reflects the repayment of a note receivable in the Other business segment in the fourth quarter of 2002 and decreased earnings on short-term investments.

Income taxes increased $0.5 million for 2003 compared to 2002. The effective tax rate was 41.1 percent for 2003 compared to 45.2 percent for 2002.

During 2003, Avista Energy recorded as a cumulative effect of accounting change a charge of $1.2 million (net of tax) related to Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which effectively required the transition of accounting for energy trading activities from EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” to SFAS No. 133. EITF Issue No. 02-3 rescinded EITF Issue No. 98-10 and related interpretative guidance. Under EITF Issue No. 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS No. 133. The rescission of EITF Issue No. 98-10 also eliminated the recognition of physical inventories at fair value other than provided by other accounting standards.

In April 2002, the Company completed its transitional test of goodwill related to the adoption of SFAS No. 142 “Goodwill and Other Intangible Assets.” Accordingly, the Company determined that $4.1 million (net of tax) of goodwill related to AM&D was impaired and recorded this as a cumulative effect of accounting change for 2002.

2002 compared to 2001

Income from continuing operations was $42.2 million for 2002 compared to $68.2 million for 2001. The decrease was primarily due to reduced net income for the Energy Marketing and Resource Management business segment and an increased net loss in the Other business segment, partially offset by increased net income for Avista Utilities and decreased net loss for Avista Advantage.

Net income for Energy Marketing and Resource Management was $22.4 million for 2002 compared to $63.2 million for 2001. The primary reason for the decrease in net income was a reduction in Avista Energy’s gross margin (operating revenues less resource costs). During the second half of 2001 and 2002, prices, trading volumes and volatility in wholesale energy markets in the western United States decreased relative to the first half of 2001, which reduced Avista Energy’s earnings potential.

Net income for Avista Utilities was $36.4 million for 2002, compared to $24.2 million for 2001. The increase for Avista Utilities was primarily due to an increase in gross margin (operating revenues less resource costs) primarily due to an electric rate increase in Washington, partially offset by an increase in other operating expenses (administrative and general, depreciation and amortization, and taxes other than income taxes).

Avista Advantage incurred a net loss of $4.3 million for 2002 compared to $10.7 million for 2001. The decrease in the net loss was primarily due to an increase in operating revenues and a decrease in operating expenses.

The Other business segment incurred a net loss of $12.4 million (excluding the cumulative effect of accounting change) for 2002 compared to $8.4 million for 2001. The increase in the net loss was primarily due to litigation costs and settlements.

Total revenues decreased $448.8 million for 2002 compared to 2001. Avista Utilities’ revenues decreased $336.9 million, or 27 percent, primarily due to decreased wholesale electric revenues, partially offset by increased retail electric revenues. Wholesale sales volumes decreased primarily due to the expiration of several wholesale electric sales contracts. The decrease in wholesale revenues also reflected a decrease in wholesale prices. The increase in retail electric revenues was primarily a result of higher rates approved by state regulatory commissions to recover deferred power costs as well as the general electric rate case order approved by the WUTC in June 2002. Revenues from Energy Marketing and Resource Management decreased $181.1 million primarily due to decreased revenues on contracts that are not considered derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities), non-trading derivative contracts and revenues from Avista Energy Canada, as well as a decrease in net trading margin. The decrease in net trading margin was primarily due to decreased energy commodity prices and trading volumes, as well as reduced market volatility. Revenues from Avista Advantage increased 29 percent to $16.9 million primarily as a result of customer growth. Revenues from the Other business segment decreased $1.7 million reflecting decreased activity in this business segment.

AVISTA CORPORATION

Total resource costs decreased $430.4 million for 2002 compared to 2001. Resource costs for Avista Utilities decreased $396.5 million for 2002 compared to 2001 primarily due to reduced power purchase expenses, decreased cost of natural gas purchased to serve retail customers and decreased fuel for generation expenses. Power purchase expenses, natural gas purchased and fuel for generation decreased due to lower wholesale market prices, increased hydroelectric generation, reduced wholesale sales obligations and decreased thermal generation. The net amortization of deferred power and natural gas costs was $68.5 million for 2002, compared to net deferrals of $210.5 million for 2001. Resource costs for Energy Marketing and Resource Management decreased $101.1 million due to a decrease in costs from contracts that are not accounted for as derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities), non-trading derivative contracts and resource costs of Avista Energy Canada, as well as a change in natural gas inventory valuations, partially offset by increased tolling charges.

Intersegment eliminations, which decreases both operating revenues and resource costs, decreased to $85.2 million for 2002 from $152.4 million for 2001 primarily from decreased prices for the sale of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Operations and maintenance expenses decreased $3.4 million for 2002 compared to 2001 primarily due to reduced expenses for Avista Advantage. During 2002, Avista Advantage focused on reducing operating expenses by improving efficiencies and reducing the workforce.

Administrative and general expenses increased $2.3 million for 2002 compared to 2001; however, there were significant fluctuations within each business segment. The net increase was due to increased expenses for Avista Utilities and Other, partially offset by reduced expenses for Energy Marketing and Resource Management as well as Avista Advantage. The decrease for Energy Marketing and Resource Management was primarily a result of reduced incentive compensation expenses resulting from decreased earnings as well as reduced professional fees. The decrease for Avista Advantage was consistent with the decrease in operations and maintenance expenses. The increase for Avista Utilities was primarily due to initiatives implemented during the third quarter of 2001 designed to temporarily reduce certain operating expenses to improve liquidity and operating cash flows. These initiatives resulted in significantly reduced expenses for 2001. Cost reduction measures were not as restrictive during 2002 as the second half of 2001. The increase in administrative and general expenses for Avista Utilities was also due to increased pension, health care, legal and general insurance costs. Administrative and general expenses for the Other business segment increased due to litigation costs and settlements.

Depreciation and amortization increased $1.4 million for 2002 compared to 2001 due to an increase for Avista Utilities partially offset by decreases for each of the other business segments. The decreases for the other business segments were primarily due to the requirement of SFAS No. 142 that goodwill no longer be amortized effective January 1, 2002.

Taxes other than income taxes increased $8.2 million for 2002 compared to 2001 primarily due to increased retail electric revenues and related taxes for Avista Utilities. The increase for Avista Utilities was partially offset by a decrease for Energy Marketing and Resource Management due to a decrease in the net margin on energy trading activities.

Interest expense decreased $1.0 million for 2002 compared to 2001. The average balance of debt outstanding was relatively consistent for 2001 and 2002 with increasing balances outstanding during 2001 and decreasing balances outstanding during 2002. The amount of debt outstanding increased substantially during 2001 with the issuance of $400.0 million of Unsecured Senior Notes in April 2001 and $150.0 million of First Mortgage Bonds in December 2001. During 2002, the Company repurchased $203.6 million of long-term debt.

Capitalized interest decreased $3.0 million for 2002 compared to 2001 primarily due to the fact that the Company did not capitalize any interest related to Coyote Springs 2 subsequent to September 30, 2002 because the project was substantially completed. A decrease in capital expenditures for Avista Utilities also contributed to the decrease in capitalized interest.

Other income-net decreased $2.8 million for 2002 compared to 2001 primarily due to reduced interest income partially offset by impairment charges recorded during 2001.

Income taxes decreased $5.7 million for 2002 compared to 2001, primarily due to decreased earnings before income taxes, partially offset by an increase in state income taxes. The effective tax rate was 45.2 percent for 2002 compared to 37.3 percent for 2001. The increase in the effective tax rate was due to increased state income tax expense as well as decreased earnings and the increased effect of permanent tax differences.

AVISTA CORPORATION

In April 2002, the Company completed its transitional test of goodwill related to the adoption of SFAS No. 142. Accordingly, the Company determined that $4.1 million (net of tax) of goodwill related to AM&D was impaired and recorded this as a cumulative effect of accounting change for 2002.

Avista Utilities

2003 compared to 2002

Net income for Avista Utilities was $36.2 million for 2003 compared to $36.4 million for 2002. Avista Utilities’ income from operations was $146.8 million for 2003 compared to $149.2 million for 2002. This decrease was primarily due to an increase in operations and maintenance, administrative and general, and depreciation and amortization expenses, partially offset by an increase in gross margin and a decrease in taxes other than income taxes.

The increase in operations and maintenance as well as administrative and general expenses reflects increased pension and insurance costs. The increase was also due to initiatives implemented during the third quarter of 2001 designed to temporarily reduce certain operating expenses to improve liquidity and operating cash flows. These initiatives resulted in significantly reduced expenses for 2001 and the first half of 2002.

The following table presents Avista Utilities’ gross margin for the years ended December 31 (dollars in thousands):


	Electric				Natural Gas				Total
	2003		2002		2003		2002		2003		2002

Operating revenues	$	650,922	$	584,141	$	277,289	$	309,823	$	928,211	$	893,964
Resource costs		294,031		240,380		180,896		213,145		474,927		453,525

Gross margin	$	356,891	$	343,761	$	96,393	$	96,678	$	453,284	$	440,439

Avista Utilities’ operating revenues increased $34.2 million and resource costs increased $21.4 million, which resulted in an increase of $12.8 million in gross margin for 2003 as compared to 2002. The gross margin on natural gas sales decreased $0.3 million and the gross margin on electric sales increased $13.1 million. The slight decrease in the gross margin on natural gas sales was primarily due to a slight decrease in retail customer usage. Primarily due to warmer weather during the first three months of 2003, total retail therm sales decreased by 1 percent. The increase in electric gross margin was primarily due to the general electric rate increase of 19.3 percent in Washington base retail rates effective July 1, 2002. This increase was partially offset by the expense of the initial $9.0 million of power supply costs in Washington exceeding the amount included in base retail rates during 2003 as compared to $4.5 million expensed during 2002.

The following table presents Avista Utilities’ electric operating revenues and megawatt-hour (MWh) sales for the years ended December 31 (dollars and MWhs in thousands):


		Electric Operating				Electric Energy
		Revenues				MWh sales
		2003		2002		2003		2002

Residential		$	204,783	$	196,156		3,298		3,203
Commercial			201,339		194,732		2,919		2,837
Industrial			78,276		68,096		1,785		1,519
Public street and highway lighting			4,770		4,683		25		25

	Total retail		489,168		463,667		8,027		7,584
Wholesale			73,463		64,082		2,075		2,216
Sales of fuel			71,456		40,937		—		—
Other			16,835		15,455		—		—

	Total	$	650,922	$	584,141		10,102		9,800

Retail electric revenues increased $25.5 million for 2003 from 2002. This increase was primarily due to an increase in total MWhs sold (increased revenues $27.0 million), partially offset by a decrease in revenue per MWh (decreased revenues $1.5 million). The weather was generally warmer than 2002 during the first quarter of 2003 which reduced MWh sales during the first part of the year. However, this was offset by warmer weather during the second and third quarters of 2003, which increased residential and commercial air conditioning usage during the period. The weather was colder during the fourth quarter of 2003 as compared to the fourth quarter of 2002, which increased usage during the period. The slight decrease in revenue per MWh was due to a slight change in revenue mix with a greater

AVISTA CORPORATION

percentage of revenues from industrial sales. The increase in industrial revenues was primarily due to the new Potlatch contract.

Wholesale electric revenues increased $9.4 million reflecting average sales prices that were 22 percent higher than the prior period (increased revenues $14.4 million), partially offset by a 6 percent decrease in wholesale sales volumes (decreased revenues $5.0 million). Average wholesale prices increased to $35.40 per MWh for 2003 from $28.92 per MWh for 2002. The increase in average wholesale sales prices appears to primarily reflect decreased hydroelectric resources as compared to the prior year throughout the western United States and an increase in the cost of natural gas used for generation.

Sales of fuel increased $30.5 million. This natural gas was not used for generation because electric wholesale market prices were generally below the cost of operating the gas-fired thermal generating units.

The following table presents Avista Utilities’ natural gas operating revenues and therm sales for the years ended December 31 (dollars and therms in thousands):


	Natural Gas				Natural Gas
	Operating Revenues				Therm Sales

	2003		2002		2003		2002

Residential	$	166,925	$	183,964		198,471		199,686
Commercial		90,523		104,974		122,115		126,220
Industrial		7,475		7,127		12,737		11,243

Total retail		264,923		296,065		333,323		337,149
Wholesale		280		695		675		2,306
Transportation		8,485		9,664		153,352		174,891
Other		3,601		3,399		3,124		2,145

Total	$	277,289	$	309,823		490,474		516,491

Natural gas revenues decreased $32.5 million for 2003 from 2002 primarily due to a decrease in retail natural gas revenues. The $31.1 million decrease in retail natural gas revenues was primarily due to a decrease in retail rates (decreased revenues $28.1 million) and partially due to a decrease in volumes (decreased revenues $3.0 million). During the fourth quarter of 2002, retail rates for natural gas were reduced in response to a decrease in current and projected natural gas costs. During the fourth quarter of 2003, retail rates for natural gas were increased in response to an increase in current and projected natural gas costs. The decrease in total therms sold was a result of warmer weather during the first quarter of 2003, which was partially offset by a colder fourth quarter of 2003 as compared to 2002.

The following table presents Avista Utilities’ average number of electric and natural gas customers as well as heating degree days for the years ended December 31:


			Electric				Natural Gas
			Customers				Customers

			2003		2002		2003		2002

Residential				283,497		279,735		261,063		254,700
Commercial				36,279		35,910		31,312		30,823
Industrial				1,414		1,420		310		315
Public street and highway lighting				422		413		—		—

	Total retail			321,612		317,478		292,685		285,838
Wholesale				47		46		1		1
Transportation				—		—		84		88

	Total customers			321,659		317,524		292,770		285,927

Heating degree days (1):
	Spokane, Washington
		Actual						6,351		6,818
		30 year average						6,820		6,842
	Medford, Oregon
		Actual						4,046		4,230
		30 year average						4,592		4,611

(1)

Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

AVISTA CORPORATION

The following table presents Avista Utilities’ resource costs for the years ended December 31 (dollars in thousands):


			2003			2002

Electric resource costs:
	Power purchased		$	147,743		$	115,282
	Power cost amortizations, net			7,165			26,253
	Fuel for generation			35,581			18,531
	Other fuel costs			96,765			77,885
	Other regulatory amortizations, net			(9,538	)		(15,411	)
	Other electric resource costs			16,315			17,840

		Total electric resource costs		294,031			240,380

Natural gas resource costs:
	Natural gas purchased			184,014			170,662
	Natural gas cost amortizations (deferrals), net			(3,336	)		42,229
	Other regulatory amortizations, net			218			254

		Total natural gas resource costs		180,896			213,145

Total resource costs			$	474,927		$	453,525

Power purchased for 2003 increased $32.5 million, or 28 percent, compared to 2002 primarily due to an increase in the price of power purchases (increased costs $31.3 million) and partially due to an increase in the volume of power purchases (increased costs $1.2 million). Average purchased power prices for 2003 were $31.30 per MWh or 27 percent higher than $24.64 per MWh for 2002 and volumes purchased increased 1 percent compared to 2002. The increase in the price of power purchases reflects increases in the price of power in the western United States and the Pacific Northwest. This appears to be partially due to lower than normal precipitation and snowpack conditions during the fourth quarter of 2002 and the first two months of 2003 and the anticipated effects on hydroelectric generation in the region. Warm and dry conditions in the Pacific Northwest during the summer of 2003 as well as the increased cost of natural gas used to generate electricity appear to have increased the price of electricity during 2003 as compared to 2002. Reduced hydroelectric availability and increased demand due to weather also appear to have affected wholesale electric prices in the western United States and the Pacific Northwest during the second half of 2003 as compared to 2002.

Net amortization of deferred power costs was $7.2 million for 2003 compared to $26.3 million for 2002. During 2003, Avista Utilities recovered (collected as revenue) $25.8 million of previously deferred power costs in Washington and $26.6 million in Idaho. During 2003, Avista Utilities deferred $22.2 million of power costs in Washington and $23.3 million in Idaho. The decrease in net amortization primarily reflects the decreased recovery of deferred power costs in Washington and an increase in the deferral of power costs in Idaho.

Fuel for generation for 2003 increased $17.1 million compared to 2002. This was primarily due to expenses associated with natural gas used as fuel for Coyote Springs 2, which was placed into operation on July 1, 2003.

Other fuel costs for 2003 increased $18.9 million compared to 2002. This was due to an increase in natural gas purchased as fuel for electric generation that was not used. This natural gas was sold with the associated revenues reflected as sales of fuel. Other fuel costs exceeded the revenues from selling the natural gas. This cost is accounted for under the ERM in Washington and the PCA in Idaho.

The expense for natural gas purchased for 2003 increased $13.4 million compared to 2002 primarily due to an increase in the cost of natural gas (increased costs $19.0 million), partially offset by a decrease in total therms purchased (decreased costs $5.6 million) consistent with a decrease in natural gas sales. During 2003, Avista Utilities had $3.3 million of net deferrals of natural gas costs compared to $42.2 million of net amortization for 2002.

2002 compared to 2001

Net income for Avista Utilities was $36.4 million for 2002 compared to $24.2 million for 2001. Avista Utilities’ income from operations was $149.2 million for 2002 compared to $114.9 million for 2001. This increase was primarily due to an increase in gross margin (operating revenues less resource costs). The increase in gross margin was partially offset by an increase in administrative and general expenses, depreciation and amortization and taxes other than income taxes.

AVISTA CORPORATION

The following table presents Avista Utilities’ gross margin for the years ended December 31 (dollars in thousands):


	Electric				Natural Gas				Total
	2002		2001		2002		2001		2002		2001

Operating revenues	$	584,141	$	922,205	$	309,823	$	308,642	$	893,964	$	1,230,847
Resource costs		240,380		636,821		213,145		213,175		453,525		849,996

Gross margin	$	343,761	$	285,384	$	96,678	$	95,467	$	440,439	$	380,851

Avista Utilities’ operating revenues decreased $336.9 million and resource costs decreased $396.5 million resulting in an increase of $59.6 million in gross margin for 2002 as compared to 2001. The general electric rate increase of 19.3 percent in Washington base retail rates effective July 1, 2002 contributed to the increase in gross margin.

The following table presents Avista Utilities’ electric operating revenues and MWh sales for the years ended December 31 (dollars and MWhs in thousands):


		Electric Operating				Electric Energy
		Revenues				MWh sales
		2002		2001		2002		2001

Residential		$	196,156	$	158,847		3,203		3,219
Commercial			194,732		155,371		2,837		2,882
Industrial			68,096		80,433		1,519		1,892
Public street and highway lighting			4,683		3,790		25		25

	Total retail		463,667		398,441		7,584		8,018
Wholesale			64,082		480,903		2,216		6,262
Sales of fuel			40,937		18,948		—		—
Other			15,455		23,913		—		—

	Total	$	584,141	$	922,205		9,800		14,280

Retail electric revenues increased $65.2 million for 2002 from 2001. This increase was primarily due to the electric surcharges implemented to recover deferred power costs and the June 2002 Washington electric rate increase (increased revenues $91.7 million), partially offset by decreased use per customer and total MWhs sold (decreased revenues $26.5 million). The increase in retail electric revenues was also due to refunds to customers in January 2001 of the gain on the sale of Avista Utilities’ interest in the Centralia Power Plant (Centralia) that reduced revenues for 2001. During 2001 and 2002, Avista Utilities experienced decreased loads and decreased use per customer with respect to electric retail sales. The decrease in use per customer appears to be primarily due to a response to the increase in electric rates and the resulting conservation efforts of individual customers. The decrease in use per customer also appears to reflect milder weather in 2002 and 2001 as compared to 2000. The decrease in total MWhs sold primarily related to industrial customers and appears to have reflected a general downturn in the economy of eastern Washington and northern Idaho.

Wholesale electric revenues decreased $416.8 million, or 87 percent, reflecting wholesale sales volumes that decreased 65 percent from 2001 (decreased revenues $117.0 million) and average sales prices that were 62 percent lower than in 2001 (decreased revenues $299.8 million). Average wholesale prices decreased to $28.92 per MWh for 2002 from $76.80 per MWh for 2001 reflecting decreased electric prices in the western United States. Wholesale sales volumes decreased primarily due to the expiration of several wholesale electric sales contracts, including two 100 MW index-based sales contracts that expired in July 2001.

Sales of fuel increased $22.0 million. This natural gas was not used for generation because electric wholesale market prices were generally below the cost of operating the gas-fired thermal generating units.

AVISTA CORPORATION

The following table presents Avista Utilities’ natural gas operating revenues and therm sales for the years ended December 31 (dollars and therms in thousands):


	Natural Gas				Natural Gas
	Operating Revenues				Therm Sales
	2002		2001		2002		2001

Residential	$	183,964	$	179,584		199,686		198,413
Commercial		104,974		104,012		126,220		126,869
Industrial		7,127		11,130		11,243		15,523

Total retail		296,065		294,726		337,149		340,805
Wholesale		695		1,762		2,306		4,831
Transportation		9,664		8,576		174,891		180,918
Other		3,399		3,578		2,145		15,430

Total	$	309,823	$	308,642		516,491		541,984

Natural gas revenues increased $1.2 million for 2002 from 2001 due to a slight increase in retail and transportation revenues, partially offset by a decrease in wholesale natural gas revenues. The $1.3 million increase in retail natural gas revenues was due to an increase in average rates (increased revenues $4.5 million), partially offset by a decrease in volumes (decreased revenues $3.2 million). Retail rates were increased during 2001 to recover deferred natural gas costs. During the fourth quarter of 2002, retail rates for natural gas were reduced in response to a decrease in current and projected natural gas costs. During 2001 and 2002, Avista Utilities experienced decreased loads and decreased use per customer with respect to natural gas retail sales. The decrease in use per customer appears to be primarily due to a response to the increase in natural gas rates during 2001 and the resulting conservation efforts of individual customers. The decrease in use per customer also appears to reflect milder weather in 2002 and 2001 as compared to 2000. The decrease in total therms sold primarily related to industrial customers and appears to have reflected a general downturn in the economy of Avista Utilities’ service territory.

The following table presents Avista Utilities’ average number of electric and natural gas customers as well as heating degree days for the years ended December 31:


			Electric				Natural Gas
			Customers				Customers
			2002		2001		2002		2001

Residential				279,735		276,845		254,700		249,650
Commercial				35,910		35,454		30,823		30,355
Industrial				1,420		1,434		315		328
Public street and highway lighting				413		402		—		—

	Total retail			317,478		314,135		285,838		280,333
Wholesale				46		44		1		2
Transportation				—		—		88		86

	Total customers			317,524		314,179		285,927		280,421

Heating degree days (1):
	Spokane, Washington
		Actual						6,818		6,800
		30 year average						6,842		6,842
	Medford, Oregon
		Actual						4,230		4,143
		30 year average						4,611		4,611

(1)

AVISTA CORPORATION

The following table presents Avista Utilities’ resource costs for the years ended December 31 (dollars in thousands):


			2002			2001

Electric resource costs:
	Power purchased		$	115,282		$	708,321
	Power cost amortizations (deferrals), net			26,253			(202,794	)
	Fuel for generation			18,531			81,949
	Other fuel costs			77,885			43,269
	Other regulatory amortizations, net			(15,411	)		(19,494	)
	Other electric resource costs			17,840			25,570

		Total electric resource costs		240,380			636,821

Natural gas resource costs:
	Natural gas purchased			170,662			220,692
	Natural gas cost amortizations (deferrals), net			42,229			(7,745	)
	Other regulatory amortizations, net			254			228

		Total natural gas resource costs		213,145			213,175

Total resource costs			$	453,525		$	849,996

Power purchased for 2002 decreased $593.0 million, or 84 percent, compared to 2001 due to the decreased volume (decreased costs $110.0 million) and price (decreased costs $483.0 million) of power purchases. Average purchased power prices for 2002 were $24.64 per MWh or 68 percent lower than $77.40 per MWh for 2001 and volumes purchased decreased 49 percent compared to 2001. The decrease in the volume of purchased power was primarily the result of decreases in the volume of wholesale electric sales and increased hydroelectric resource availability to meet retail demand.

Net amortization of deferred power costs was $26.3 million in 2002 compared to net deferrals of $202.8 million in 2001. During 2002, Avista Utilities recovered (collected as revenue) $38.6 million of previously deferred power costs in Washington and $24.7 million in Idaho. During 2002, Avista Utilities deferred $22.4 million of power costs in Washington and $13.5 million in Idaho. During 2002, $27.7 million of a deferred credit was offset against the Idaho share of deferred power costs. The deferred credit related to funds received in December 1998 in which the Company assigned and transferred certain rights under a long-term power sales contract with Portland General Electric Corporation (PGE) to a funding trust.

The cost of fuel for generation for 2002 decreased $63.4 million from 2001 primarily due to a decrease in thermal generation as well as a decrease in the average cost of natural gas used for generation. Thermal generation decreased 43 percent primarily due to increased hydroelectric generation and wholesale market prices that were generally below the cost of operating the thermal generating units.

Other fuel costs for 2002 increased $34.6 million compared to 2001. This was due to an increase in natural gas purchased as fuel for electric generation that was not used. This excess natural gas was sold with the associated revenues reflected as sales of fuel. Other fuel costs exceeded the revenues from selling the excess natural gas. This excess cost is accounted for under the ERM in Washington and the PCA in Idaho.

The expense for natural gas purchased for 2002 decreased $50.0 million compared to 2001 primarily due to the decreased average cost of natural gas (decreased costs $48.1 million) and partially due to a decrease in total therms purchased (decreased costs $1.9 million). During 2002, Avista Utilities had $42.2 million of net amortization of deferred natural gas costs compared to net deferrals of $7.7 million in 2001.

Developments with Coyote Springs 2

In January 2004, Avista Utilities determined there was a problem with the transformer at Coyote Springs 2. The plant was taken off-line and the transformer has been returned to the manufacturer for repairs covered by warranty. Avista Utilities expects that the transformer will be returned to Coyote Springs 2 by June 30, 2004. Based on current forward power price curves and assuming that the transformer is returned when expected, Avista Utilities does not expect that the absence of Coyote Springs 2 will have a material effect on its results of operations for 2004. If Coyote Springs is not placed back into operation by August 2004, it could have an effect on the Company’s results of operations for 2004 depending on the level of wholesale market prices. Changes in power supply costs, including thermal generation and wholesale power purchases, are addressed through the ERM and PCA mechanism. The Company has ordered a backup transformer for Coyote Springs 2 that is scheduled for delivery in November 2004.

AVISTA CORPORATION

Energy Marketing and Resource Management

Energy Marketing and Resource Management includes the results of Avista Energy and Avista Power.

Avista Energy’s earnings are primarily derived from the following activities:

•		Marketing and managing the output and availability of combustion turbines and hydroelectric assets owned by other entities.

•		Capturing price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process.

•		Purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks.

•		Transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations within the WECC.

•		Taking speculative positions on future price movements within established risk management policies.

Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts, which are not accounted for as derivatives under SFAS No. 133 and derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Costs from contracts, which are not accounted for as derivatives under SFAS No. 133 and derivative commodity instruments not held for trading, are reported on a gross basis in resource costs.

The following table presents Avista Energy’s realized gains and unrealized losses for the years ended December 31 (dollars in thousands):


		2003			2002			2001

Realized gains		$	82,317		$	141,610		$	164,504
Unrealized losses			(22,128	)		(87,403	)		(30,238	)

	Total gross margin (operating revenues less resource costs)	$	60,189		$	54,207		$	134,266

2003 compared to 2002

Energy Marketing and Resource Management’s net income before cumulative effect of accounting change was $20.7 million for 2003, compared to net income of $22.4 million for 2002. This decrease was primarily due to a $3.2 million (net of tax) impairment charge recorded by Avista Power, partially offset by an increase in gross margin for Avista Energy. Operating revenues increased $84.5 million and resource costs increased $78.5 million for 2003 as compared to 2002 resulting in an increase in gross margin of $6.0 million.

Avista Energy’s gross margin (operating revenues less resource costs) was $60.2 million for 2003 compared to $54.2 million for 2002. The increase in gross margin was partially due to the transition to SFAS No. 133, which resulted in certain contracts with net estimated unrecognized losses of $7.3 million for 2003 not being accounted for at market value. These losses are recognized as the contracts are settled or realized. These contracts that are not accounted for at market value are economically hedged by certain other contracts with unrealized gains for 2003 that are considered derivatives under SFAS No. 133, and as such are recorded at market value with a positive impact on gross margin. The positive effects of the transition to SFAS No. 133 will be reversed in future periods as market

AVISTA CORPORATION

values change or the contracts are settled and realized. During September 2003, Avista Energy implemented hedge accounting for certain transactions. This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis. Avista Energy’s settlement of various positions with Enron affiliates and the resulting release by Avista Energy of amounts, which had been reserved against such positions, also had a positive effect of $8.4 million on gross margin for 2003.

Realized gains decreased to $82.3 million for 2003 from $141.6 million for 2002. Realized gains represent the net gain on contracts that have settled. The decrease in realized gains was primarily due to a decrease in the gains on physical electric and natural gas transactions partially offset by the settlement with Enron affiliates, increased gains on settled financial transactions and gains on the change in natural gas inventory valuations. Realized gains for 2002 also reflect gains from the settlement of transactions that were initiated during the period of high wholesale market prices and volatility during 2000 and 2001. The total mark-to-market adjustment for Energy Marketing and Resource Management was an unrealized loss of $22.1 million for 2003 compared to an unrealized loss of $87.4 million for 2002. The change in the unrealized loss was primarily due to the settlement of contracts with significant realized gains during 2002 and the transition to SFAS No. 133 described above. During 2003, the change in the total unrealized gain attributable to market prices and other market changes was $63.2 million, an increase from $49.7 million in 2002.

Energy Marketing and Resource Management’s total assets decreased $336.4 million from December 31, 2002 to December 31, 2003 primarily due to a decrease in energy commodity assets and the transfer of Coyote Springs 2 from Avista Power to Avista Corp. in January 2003. The decrease in energy commodity assets primarily reflects the settlement of contracts during the period.

2002 compared to 2001

Energy Marketing and Resource Management’s net income was $22.4 million for 2002, compared to $63.2 million for 2001. The primary reason for the decrease in net income was a decrease in gross margin to $54.2 million for 2002 compared to $134.3 million for 2001.

Realized gains decreased to $141.6 million for 2002 from $164.5 million for 2001. The decrease was primarily due to a decrease in the underlying commodity values that settled and a decrease in the volume of transactions. The decrease in the volume of transactions was primarily due to reduced liquidity in wholesale markets, fewer creditworthy counterparties participating in the wholesale markets and a decrease in the volatility of prices in the wholesale markets. The total mark-to-market adjustment for Energy Marketing and Resource Management was an unrealized loss of $87.4 million for 2002 compared to an unrealized loss of $30.2 million for 2001. The increase in the unrealized loss was primarily due to the settlement of contracts, the realization of previously unrealized gains and decreased volatility in the wholesale energy markets. During 2002, the change in the total unrealized gain attributable to market prices and other market changes was $49.7 million, a decrease from $120.6 million in 2001.

Administrative and general expenses decreased $11.7 million, or 35 percent, from 2001 primarily due to reduced incentive compensation expense based on lower earnings in 2002. Reduced professional fees also contributed to the decrease in administrative and general expenses. Professional fees were high during 2001 due to expenses associated with the California energy crisis and a CFTC investigation that was resolved in 2001 related to certain trades in 1998.

Energy Marketing and Resource Management’s total assets decreased $156.6 million from December 31, 2001 to December 31, 2002 primarily due to a decrease in total current and non-current energy commodity assets. This decrease in commodity assets reflects the settlement of contracts and a decrease in commodity prices during 2002.

AVISTA CORPORATION

Energy trading activities and positions

The following table summarizes information with respect to Avista Energy’s trading activities during 2003 (dollars in thousands):


	Electric			Natural Gas			Total
	Assets net of			Assets net of			Unrealized
	Liabilities			Liabilities			Gain (Loss)

Fair value of contracts as of December 31, 2002	$	60,081		$	34,720		$	94,801
Less contracts settled during 2003 (1)		(57,478	)		(24,839	)		(82,317	)
Cumulative effect of accounting change (2)		(357	)		(1,473	)		(1,830	)
Fair value of new contracts when entered into during 2003 (3)		—			—			—
Change in fair value due to changes in valuation techniques (4)		(388	)		176			(212	)
Change in fair value attributable to market prices and other market changes		61,715			1,505			63,220

Fair value of contracts as of December 31, 2003	$	63,573		$	10,089		$	73,662

(1)		Contracts settled during 2003 include those contracts that were open in 2002 but settled during 2003 as well as new contracts entered into and settled during 2003. Amount represents realized gains associated with these settled transactions.

(2)		Represents the adjustment for the transition to SFAS No. 133 for contracts not meeting the definition of a derivative. Effective January 1, 2003, contracts that were entered into on or prior to October 25, 2002 and not meeting the definition of a derivative are accounted for on an accrual basis. Contracts not meeting the definition of a derivative include Avista Energy’s Agency Agreement with Avista Utilities, natural gas storage contracts, tolling agreements and natural gas transportation agreements.

(3)		Avista Energy has not entered into any origination transactions during 2003 in which dealer profit or mark-to-market gain or loss was recorded at inception.

(4)		During 2003, Avista Energy revised the methodology for a liquidity valuation adjustment.

The following table discloses summarized information with respect to valuation techniques and contractual maturities of Avista Energy’s energy commodity contracts outstanding as of December 31, 2003 (dollars in thousands):


					Greater			Greater
					than one			than three		Greater
		Less than			and less than			and less than		than
		one year			three years			five years		five years			Total

Electric assets (liabilities), net
	Prices from other external sources (1)	$	24,100		$	23,926		$	—	$	—		$	48,026
	Fair value based on valuation models (2)		(1,750	)		12,249			11,899		(6,851	)		15,547

	Total electric assets (liabilities), net	$	22,350		$	36,175		$	11,899	$	(6,851	)	$	63,573

Natural gas assets (liabilities), net
	Prices from other external sources (1)	$	1,163		$	6,663		$	—	$	—		$	7,826
	Fair value based on valuation models (3)		521			(101	)		1,329		514			2,263

	Total natural gas assets (liabilities), net	$	1,684		$	6,562		$	1,329	$	514		$	10,089

(1)		Fair value is determined based upon actively traded, “over-the-counter” market quotes received from third party brokers. For electric assets and liabilities, these market quotes are generally available through two years. For natural gas assets and liabilities, these market quotes are generally available through three years.

(2)		Represents contracts for delivery at basis locations not actively traded in the “over-the-counter” markets. In addition, this includes all contracts with a delivery period greater than two years, for which active quotes are not available. These internally developed market curves are determined using a production cost model with inputs for assumptions related to power prices (including, without limitation, natural gas prices, generation on- line, transmission constraints, future demand and weather). Avista Energy performs frequent stress tests on the valuation of the portfolio. While consistent valuation methodologies and updates to the assumptions are used to capture current market information, changes in these methodologies or underlying assumptions could result in significantly different fair values and income recognition. These same pricing techniques and stress tests are used to evaluate a contract prior to taking a position.

(3)		Represents contracts for delivery at basis locations not actively traded in the “over-the-counter” markets. In addition, this includes all contracts with a delivery period greater than three years, for which active quotes are not available. These internally developed market curves are based upon published New York Mercantile Exchange prices through seven years, as well as basis spreads using historical and broker estimates. After

AVISTA CORPORATION

seven years, an escalation is used to estimate the valuation.

Avista Power

In 2003, the Company recorded an impairment charge related to a turbine owned by Avista Power. This resulted in a charge of $4.9 million for 2003 included in operations and maintenance expense.

Avista Advantage

2003 compared to 2002

Avista Advantage’s net loss was $1.3 million for 2003 compared to $4.3 million for 2002. Operating revenues for Avista Advantage increased $2.9 million and operating expenses decreased $2.1 million, as compared to 2002. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage had a 12 percent increase in the number of billed sites as of December 31, 2003 as compared to December 31, 2002. The decrease in operating expenses reflects improved efficiencies, a reduction in the number of employees and a focus on reducing operating expenses. Total costs per account were reduced by 26 percent for 2003 as compared to 2002.

2002 compared to 2001

Avista Advantage’s net loss was $4.3 million for 2002 compared to $10.7 million for 2001. Operating revenues for Avista Advantage increased $3.8 million and operating expenses decreased $5.0 million, for 2002 as compared to 2001. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage had a 23 percent increase in the number of billed sites as of December 31, 2002 as compared to December 31, 2001. The decrease in operating expenses reflects improved efficiencies, a reduction in the number of employees and a focus on reducing operating expenses. Certain non-recurring items in both periods also contributed to the decrease in operating expenses.

Other

The Other business segment includes Avista Ventures (including AM&D), Pentzer, Avista Development and certain other operations of Avista Capital.

2003 compared to 2002

The net loss from this business segment was $4.9 million for 2003, compared to a net loss before the cumulative effect of accounting change of $12.4 million for 2002. The decrease in the net loss was primarily due to an increase in income from operations. Operating revenues from this business segment decreased $1.1 million and operating expenses decreased $12.1 million, respectively, for 2003 as compared to 2002. The increase in income from operations was primarily due to a decrease in litigation costs and settlements. The loss from AM&D decreased to $2.3 million for 2003 from $5.1 million for 2002. The improvement in income from operations was partially offset by an increase in losses on certain other investments of Avista Ventures not related to AM&D.

2002 compared to 2001

The net loss before the cumulative effect of accounting change from this business segment was $12.4 million for 2002, compared to a net loss of $8.4 million for 2001. The increase in the net loss was primarily due to a decrease in income from operations and partially due to an increase in interest expense as well as a reduction in gains on the disposition of assets. Operating revenues from this business segment decreased $1.7 million and operating expenses

AVISTA CORPORATION

increased $2.7 million, respectively, for 2002 as compared to 2001. The decrease in income from operations was primarily due to an increase in litigation costs and settlements as well as an increase in the loss from AM&D, from $4.5 million in 2001 to $5.1 million in 2002.

Discontinued Operations

In September 2001, Avista Corp. decided that it would dispose of substantially all of the assets of Avista Communications, Inc. (Avista Communications). The divestiture of operating assets was complete by the end of 2002. The operations of Avista Communications are included as part of discontinued operations during 2001 and 2002.

The decrease in the loss from discontinued operations from $6.7 million in 2002 to $4.9 million in 2003 was primarily due to the fact that only six months of operations for Avista Labs are included in 2003 and partially due to $1.1 million of net income for Avista Communications in 2002. The significant loss for 2001 was due to asset impairment charges of $58.4 million recorded during the third quarter of 2001 for Avista Communications.

Transactions with Mirant Corporation

In July 2003, Mirant Corporation and substantially all its subsidiaries in the United States filed for bankruptcy protection under chapter 11 of the bankruptcy code for protection from creditors. The Company does not expect the bankruptcy filing by Mirant Corporation, which did not include Mirant Oregon, the owner of 50 percent of Coyote Springs 2, to have any material effect on the joint ownership and operation of the plant. Avista Corp. and Mirant Oregon are both current with respect to their obligations to share equally in the costs of the plant. Avista Corp. and Mirant Oregon are sharing equally in the costs of operation and rights to the output from Coyote Springs 2. Each owner is separately responsible for arranging for the purchase and delivery of natural gas in order to fuel its respective interest in the plant. Each owner is also separately responsible for the sale and delivery of electric energy generated with respect to its interest in the plant. While physical limitations prevent the operation of the plant at less than approximately seventy percent of its base load capacity, the joint operating agreement provides mechanisms to allow a single owner to dispatch and direct the operation of more than its interest in the plant in order to achieve operation at or above the plant’s minimum dispatch level in the event that the other owner is unable or unwilling to dispatch its portion of the plant. Additionally, provisions in the joint operating agreement provide that if either party fails to fund its portion of the operating costs or otherwise meet its obligations under the joint operating agreement, that the non-defaulting owner may elect a variety of remedies. Such remedies include the right, after notice and a cure period, (i) to convert a payment default into an adjustment of the ownership interests in the plant, resulting in a reduction of the defaulting owner’s interest and a corresponding increase in the non-defaulting owner’s interest, (ii) to declare a default and pursue recovery of unpaid amounts or other equitable remedies against the defaulting party, (iii) to exercise a purchase option to acquire the defaulting owner’s interest in the plant, or (iv) to trigger a retirement of the plant. The Company will continue to assess the ability of Mirant Oregon to perform its obligations under the joint operating agreement and the need to exercise remedies in the event the impact of the Mirant Corporation bankruptcy prevents Mirant Oregon from performing its obligations with respect to Coyote Springs 2.

Both Avista Corp. and Avista Energy had energy contracts with a subsidiary of Mirant Corporation that was included in the bankruptcy filing, Mirant Americas Energy Marketing (MAEM). The bankruptcy filing did not represent an event of default or trigger the termination of Avista Corp.’s natural gas swap contract with MAEM. As of the bankruptcy filing date, Avista Corp. was in a liability position with respect to this contract and does not expect the filing to have any material adverse effect on its financial condition or results of operations. The bankruptcy filing constituted an event of default under contracts between Avista Energy and MAEM. As a result, Avista Energy terminated all of its contracts and suspended trading activities with MAEM. Avista Energy’s contracts with MAEM provide that, upon termination, the net settlement of accounts receivable and accounts payable will be netted and offset against the net mark-to-market value of the terminated forward contracts. A settlement on the terminated positions was reached and approved by the U.S. Bankruptcy Court in December 2003. While the settlement amount is protected under confidentiality, it did not have a material effect on Avista Energy’s results of operations or financial condition.

AVISTA CORPORATION

New Accounting Standards

See “Note 2 of the Notes to Consolidated Financial Statements.”

Critical Accounting Policies and Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that the Company’s management believes are particularly important to the consolidated financial statements that require the use of estimates and assumptions:

Avista Utilities Operating Revenues

Operating revenues for Avista Utilities related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. The estimate of unbilled revenue is based on the number of customers, current rates, meter reading dates, weather (degree days), as well as actual throughput for natural gas. Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading and customer billing is made.

Regulatory Accounting

The Company prepares its consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its financial statements. SFAS No. 71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) are reflected as deferred charges on the balance sheet. These costs and/or obligations are not reflected in the statement of income until the period during which matching revenues are recognized. The Company has mechanisms in place in each regulatory jurisdiction, which provide for the recovery of its regulatory assets through future rates. However, these regulatory assets are subject to review for prudence and recoverability and as such certain deferred costs may be disallowed by the respective regulatory agencies. If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to all or a portion of the Company’s regulated operations, the Company could be required to write off its regulatory assets. The Company could also be precluded from the future deferral of costs not recovered through rates at the time such costs were incurred, even if the Company expects to recover such costs in the future.

Avista Utilities Energy Commodity Derivative Assets and Liabilities

Avista Utilities enters into forward contracts to purchase or sell energy. Under these forward contracts, Avista Utilities commits to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. Certain of these forward contracts are considered derivative instruments. Avista Utilities also records derivative commodity assets and liabilities for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered into as part of Avista Utilities’ management of its loads and resources. In conjunction with the issuance of SFAS No. 133, the WUTC and the IPUC issued accounting orders authorizing Avista Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The order provides for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement subject to current or future recovery in retail rates. Realized gains and losses are reflected as adjustments through purchased gas cost adjustments, the ERM and the PCA mechanism. Quoted market prices and forward price curves are used to estimate the fair value of Avista Utilities derivative commodity instruments.

Avista Energy Revenues and Trading Activities

Avista Energy’s derivative commodity instruments accounted for under SFAS No. 133 are marked to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as unrealized gains or losses in the period of change. Market prices are utilized in determining the value of electric, natural gas

AVISTA CORPORATION

and related derivative commodity instruments. For electric commodity instruments, these market prices are generally available through two years. For natural gas commodity instruments, these market prices are generally available through three years. For longer-term positions and certain short-term positions for which market prices are not available, models are used to estimate market values. These models incorporate a variety of estimates and assumptions, the ultimate outcomes of which are beyond Avista Energy’s control including, among others, estimates and assumptions as to demand growth, fuel price escalation, availability of existing generation and costs of new generation. Actual experience can vary significantly from these estimates and assumptions.

Avista Energy implemented hedge accounting in accordance with SFAS No. 133 during the third quarter of 2003. Specific natural gas and electric trading derivative contracts have been designated as hedging instruments in cash flow hedging relationships. The hedge strategies represent cash flow hedges of the variable price risk associated with expected purchases of natural gas and sales of electricity. These designated hedging instruments represent hedges of variable price exposures generated from certain contracts, which do not qualify as derivatives under SFAS No. 133. For all derivatives designated as cash flow hedges, Avista Energy documents the relationship between the hedging instrument and the hedged item (forecasted purchases and sales of power and natural gas), as well as the risk management objective and strategy for using the hedging instrument. Avista Energy assesses whether a change in the value of the designated derivative is highly effective in achieving offsetting cash flows attributable to the hedged item, both at the inception of the hedge and on an ongoing basis. Any changes in the fair value of the designated derivative that are effective are recorded in accumulated other comprehensive income or loss, while changes in fair value that are not effective are recognized currently in earnings as operating revenues. Amounts recorded in accumulated other comprehensive income or loss are recognized in earnings during the period that the hedged items are recognized in earnings.

Pension Plans and Other Postretirement Benefit Plans

The Company has a defined benefit pension plan covering substantially all of its regular full-time employees. Employees of Avista Energy also participate in this plan. Individual benefits under this plan are based upon years of service and the employee’s average compensation as specified in the plan. The Company’s funding policy is to contribute amounts that are not less than the minimum amounts required to be funded under the Employee Retirement Income Security Act, nor more than the maximum amounts that are currently deductible for income tax purposes. The Company made $12 million in cash contributions to the pension plan in each of 2003 and 2002. The Company expects to contribute approximately $15 million to the pension plan in 2004. Pension fund assets are invested primarily in marketable debt and equity securities. As of December 31, 2003, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. In 2003, the pension plan funding deficit was reduced as compared to the end of 2002 and as such the Company reduced the additional minimum liability for the unfunded accumulated benefit obligation by $15.5 million and the intangible asset by $0.6 million (representing the amount of unrecognized prior service cost) related to the pension plan. This resulted in an increase to other comprehensive income of $9.7 million, net of taxes, for 2003. In 2002, the Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $33.4 million and an intangible asset of $6.4 million (representing the amount of unrecognized prior service cost) related to the pension plan. This resulted in a charge to other comprehensive income of $17.6 million, net of taxes, for 2002.

The Company’s pension costs (including the Supplemental Executive Retirement Plan (SERP)) were $16.1 million, $10.3 million and $4.8 million for 2003, 2002 and 2001, respectively. Of these pension costs, approximately 70 percent are expensed and approximately 30 percent are capitalized. The Company’s costs for the pension plan are determined in part by actuarial formulas and are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are affected by actual employee demographics (including age, compensation and the length of service by employees), the amount of cash contributions the Company makes to the pension plan and the return on pension plan assets. Changes made to the provisions of the pension plan may also impact current and future pension costs. Pension plan costs may also be significantly affected by changes in key actuarial assumptions, including the expected return on pension plan assets, the discount rate used in determining the projected benefit obligation and pension costs as well as the assumed rate of increase in employee compensation. The change in pension plan obligations associated with these factors may not be immediately recognized as pension costs in the Consolidated Statement of Income, but generally are recognized in future years over the remaining average service period of pension plan participants. As such, costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.

The Company has not made any changes to pension plan provisions in 2003, 2002 and 2001 that have had any significant effect on recorded pension plan amounts. The Company has revised the key assumption of the discount rate in 2003 as compared to 2002 and 2001. Such change had an effect on reported pension costs in 2003 and may

AVISTA CORPORATION

have an impact on future years given the cost recognition approach described above. However, in determining pension obligation and costs amounts, assumptions can change from period to period, and such changes could result in material changes to future pension costs and funding requirements.

The following chart reflects the sensitivities associated with a change in certain actuarial assumptions by the indicated percentage (dollars in thousands):


Actuarial	Change in			Impact on Projected			Impact on			Impact on
Assumption	Assumption			Benefit Obligation			Pension Liability			Pension Cost
Expected long-term return on plan assets		-0.5	%	$	—		$	-	*	$	679
Expected long-term return on plan assets		+0.5	%		—			-	*		(679	)
Discount rate		-0.5	%		19,645			11,996			1,806
Discount rate		+0.5	%		(17,573	)		(12,735	)		(1,640	)

* As the Company has already recorded an additional minimum liability for the unfunded accumulated benefit obligation, changes in the expected return on plan assets would not have an impact on the total pension liability.

In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits. The Company reduced the discount rate in 2003 from 6.75 percent to 6.25 percent.

In selecting an assumed long-term rate of return on plan assets, the Company considered past performance and economic forecasts for the types of investments held by the plan. The assumed long-term rate of return was 8 percent in both 2003 and 2002. For 2003, the actual return on plan assets was a gain of $33.1 million. The actual return on plan assets was a loss of $16.7 million and $9.3 million in 2002 and 2001, respectively.

The Company also has a SERP that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $0.3 million, $0.7 million and $1.1 million related to the SERP in 2003, 2002 and 2001, respectively. This resulted in a charge to other comprehensive income of $0.2 million, $0.5 million and $0.7 million, net of taxes, for 2003, 2002 and 2001, respectively.

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2003 by $3.0 million and the service and interest cost by $0.2 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2003 by $2.6 million and the service and interest cost by $0.2 million.

Contingencies

The Company has multiple unresolved regulatory, legal and tax issues for which there is inherent uncertainty with respect to the ultimate outcome of the respective matter. The Company accounts for contingencies in accordance with SFAS No. 5, “Accounting for Contingencies” as well as other accounting guidance specific to a particular issue. In accordance with SFAS No. 5, a loss contingency is accrued if the likelihood of loss or asset impairment is probable and the amount of the loss or impairment can be reasonably estimated. The Company also discloses losses that do not meet these conditions, if it there is a reasonable possibility that a loss may be incurred.

For all material contingencies, the Company has made a judgment with respect to the likelihood of the loss occurring and an estimate of the amount of loss, and, if the loss recognition criteria have been met, liabilities have been accrued or assets have been written down. However, the ultimate outcome of each contingent matter could vary significantly from the amount estimated and no assurance can be given with respect to the ultimate outcome of any particular contingency.

AVISTA CORPORATION

Liquidity and Capital Resources

Review of Cash Flow Statement

Continuing Operating Activities Net cash provided by continuing operating activities was $122.6 million for 2003 compared to $326.9 million for 2002. The primary reason for the decrease in net cash provided by continuing operating activities was a decrease in cash provided by working capital components, a change in power and natural gas cost amortizations and deferrals and a change in energy commodity assets and liabilities. Power and natural gas cost amortizations, net of deferrals, were $3.8 million for 2003 compared to $68.5 million for 2002. This was primarily due to reduced amortization (and a corresponding decrease in cash revenues received from customers) of deferred natural gas costs, increased deferral of power and natural gas costs due to increasing prices and reduced hydroelectric generation in 2003 and the reduced amortization (as a greater percentage of electric rate increases have been allocated to a general rate increase) of deferred power costs in Washington. The amortization of deferred power and natural gas costs is substantially matched by an increase in cash revenues collected from customers. The deferral of power and natural gas costs is substantially matched by an increase in cash resource costs paid for power and natural gas costs. Net cash used in working capital components was $43.0 million for 2003, compared to net cash provided of $99.1 million for 2002. The net cash used in 2003 primarily reflects a net decrease in accounts payable. The net cash provided for 2002 primarily reflects an increase in deposits from counterparties. Significant changes in non-cash items also included a $65.3 million change in energy commodity assets and liabilities, representing the change from an unrealized loss of $87.4 million on energy trading activities for Avista Energy for 2002 to an unrealized loss of $22.1 million for 2003. This decrease reflects a decrease in realized gains and cash receipts on settled trading transactions at Avista Energy. The $68.7 million change in the provision for deferred income taxes was partially due to changes in deferred power and natural gas cost amortizations and the unrealized loss on energy trading activities described above. The purchases of securities held for trading of $18.9 million represents the investment of cash held at Avista Energy in short-term instruments.

Continuing Investing Activities Net cash used in continuing investing activities was $109.8 million for 2003, an increase compared to $47.8 million for 2002. The increase was primarily due to an increase in utility property construction expenditures and a decrease in payments received on notes receivable, partially offset by a decrease in other capital expenditures (non-utility capital expenditures). Other capital expenditures for 2002 primarily related to Coyote Springs 2, which was included in the Energy Marketing and Resource Management segment. Utility property construction expenditures were unusually low during 2002 due to liquidity constraints.

Continuing Financing Activities Net cash used in continuing financing activities was $54.5 million for 2003 compared to $284.7 million for 2002. During 2003, short-term borrowings increased $50.5 million, the Company repurchased $52.5 million of long-term debt scheduled to mature in future years, and $72.4 million of long-term debt matured. In September 2003, the Company issued $45.0 million (net proceeds of $44.8 million) of 6.125 percent First Mortgage Bonds due in 2013. The increase in short-term borrowings primarily reflects an increase in the amount of debt outstanding under Avista Corp.’s line of credit. The increase in the amount of short-term borrowings reflects decreased cash flows from operations and increased funding needed for capital expenditures, maturing long-term debt and discretionary repurchases of long-term debt scheduled to mature in future years.

During 2002, the Company repurchased $203.6 million of long-term debt and short-term borrowings decreased $45.1 million. The decrease in short-term borrowings in 2002 reflected a decrease in the amount outstanding under Avista Corp.’s line of credit as well as the repayment of a short-term note at Avista Capital. The overall decrease in borrowings during 2002 reflected increased cash flows from operations primarily related to the recovery of deferred power and natural gas costs as well as a general rate increase for Washington electric customers that was partially used to repurchase long-term debt. Cash dividends from Avista Energy were also a significant source of funds used by Avista Corp. to repurchase long-term debt during 2002.

Overall Liquidity

The Company’s consolidated operating cash flows are primarily derived from the operations of Avista Utilities and Avista Energy. The primary source of operating cash flows for Avista Utilities is revenues (including the recovery of previously deferred power and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, taxes and interest. The primary source and use of operating cash flows for Avista Energy is revenues and costs from realized energy commodity transactions. Significant operating cash outflows for Avista Energy also include other operating expenses and taxes.

AVISTA CORPORATION

Over time, operating cash flows do not always fully support the capital expenditure needs of Avista Utilities. As such, from time to time, the Company may need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

During 2002 and 2003, the Company’s overall liquidity improved compared to 2001. The general electric rate case order issued by the WUTC in June 2002 is allowing the Company to continue to improve its liquidity. The general electric rate case order provided for the restructuring and continuation of previously approved rate increases totaling 31.2 percent. In 2003, the Company received a general rate increase of $6.3 million in Oregon. Additionally, the Company has a PCA surcharge of 19.4 percent in place in Idaho and has filed for general rate increases for both electric and natural gas customers in Idaho. See further details in the section “Avista Utilities — Regulatory Matters.”

The Company designs operating budgets to control operating costs and capital expenditures. In addition to operating expenses, the Company has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities. In 2001, the Company incurred substantial levels of indebtedness, both short and long-term, to finance these requirements and to otherwise maintain adequate levels of working capital. As a result of improved operating cash flow, during 2002 and 2003, the Company repurchased $256.1 million of long-term debt.

If Avista Utilities’ power and natural gas costs were to significantly exceed the levels currently recovered from retail customers, its cash flows would be negatively affected. Factors that could cause purchased power costs to exceed the levels currently recovered from customers include, but are not limited to, higher prices in wholesale markets combined with an increased need to purchase power in the wholesale markets. Current FERC imposed price caps limit wholesale market prices to $250 per MWh. Factors beyond the Company’s control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to, increases in demand (either due to weather or customer growth), low availability of hydroelectric resources, outages at generating facilities and failure of third parties to deliver on energy or capacity contracts.

Capital Resources

The Company’s consolidated capital structure, including the current portion of long-term debt and short-term borrowings consisted of the following as of December 31 (dollars in thousands):


	2003					2002
			Percent					Percent
	Amount		of total			Amount		of total
Current portion of long-term debt	$	29,711		1.5	%	$	71,896		3.9	%
Short-term borrowings		80,525		4.2			30,000		1.6
Long-term debt to affiliated trusts		113,403		5.9			—		—
Long-term debt		925,012		47.9			902,635		48.8

Total debt		1,148,651		59.5			1,004,531		54.3
Preferred stock-cumulative (including current portion)		31,500		1.6			—		—

Total liabilities		1,180,151		61.1			1,004,531		54.3
Preferred trust securities		—		—			100,000		5.4
Preferred stock-cumulative		—		—			33,250		1.8
Common equity		751,252		38.9			712,791		38.5

Total	$	1,931,403		100.0	%	$	1,850,572		100.0	%

The Company’s total debt increased from December 31, 2002 to December 31, 2003 due to the adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46 (see Note 2 of the Notes to Consolidated Financial Statements), the issuance of long-term debt in September 2003 and an increase in short-term borrowings, partially offset by the repurchase and maturity of long-term debt. The decrease in total debt (excluding $168 million of debt resulting from the adoption of FASB Interpretation No. 46) was made possible by positive operating cash flows from both Avista Utilities and Avista Energy. The Company needs to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund working capital, purchased power and natural gas costs, capital expenditures, dividends and other corporate requirements. The Company’s consolidated common equity

AVISTA CORPORATION

increased $38.5 million during 2003 primarily due to net income, other comprehensive income and the issuance of common stock through the Dividend Reinvestment Plan and employee benefit plans, partially offset by dividends.

The Company generally funds capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by utility operating activities and cash generated by Avista Energy are expected to be the Company’s primary sources of funds for operating needs, dividends and capital expenditures for 2004.

On May 13, 2003, the Company amended its committed line of credit with various banks to increase the amount to $245.0 million from $225.0 million and extend the expiration date to May 11, 2004. The Company can request the issuance of up to $75.0 million in letters of credit under the amended committed line of credit. As of December 31, 2003 and 2002, the Company had $80.0 million and $30.0 million, respectively, of borrowings outstanding under this committed line of credit. As of December 31, 2003 and 2002, there were $10.7 million and $14.3 million in letters of credit outstanding, respectively. The committed line of credit is secured by $245.0 million of non-transferable first mortgage bonds of the Company issued to the agent bank. Such first mortgage bonds would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit. The Company is currently in discussions with its banks and believes that the committed line of credit will be renewed for an additional year by the May 11, 2004 expiration date.

The committed line of credit agreement contains customary covenants and default provisions, including covenants not to permit the ratio of “consolidated total debt” (not including preferred stock, long-term debt to affiliated trusts or WP Funding LP debt) to “consolidated total capitalization” of Avista Corp. to be, at the end of any fiscal quarter, greater than 65 percent. As of December 31, 2003, the Company was in compliance with this covenant with a ratio of 52.6 percent. The committed line of credit also has a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the twelve-month period ending December 31, 2003 to be greater than 1.6 to 1. As of December 31, 2003, the Company was in compliance with this covenant with a ratio of 2.3 to 1.

Any default on its committed line of credit or other financing arrangements could result in cross-defaults to other agreements and could induce vendors and other counterparties to demand collateral. In the event of default, it would be difficult for the Company to obtain financing on any reasonable terms to pay creditors or fund operations, and the Company would likely be prohibited from paying dividends on its common stock. As of December 31, 2003, Avista Corp. was in compliance with the covenants of all of its financing agreements.

The Company is restricted under various agreements and its Restated Articles of Incorporation as to the additional preferred stock it can issue. As of December 31, 2003, approximately $395.4 million of additional preferred stock could be issued at an assumed dividend rate of 6.95 percent with a maturity date later than June 1, 2008.

The Mortgage and Deed of Trust securing the Company’s First Mortgage Bonds contains limitations on the amount of First Mortgage Bonds that may be issued based on, among other things, a 70 percent debt-to-collateral ratio, and/or retired First Mortgage Bonds, and a 2.00 to 1 net earnings to First Mortgage Bond interest ratio. Under various financing agreements, the Company is also restricted as to the amount of additional First Mortgage Bonds that it can issue. As of December 31, 2003, the Company could issue $93.1 million of additional First Mortgage Bonds under the most restrictive of these financing agreements.

In June 2003, the Company filed a registration statement on Form S-3 with the Securities and Exchange Commission for the purpose of issuing up to $150.0 million of secured or unsecured debt securities. In September 2003, the Company issued $45.0 million of 6.125 percent First Mortgage Bonds due in 2013. The proceeds were used to repay a portion of the borrowings under the $245.0 million line of credit that were used on an interim basis to fund $46.0 million of maturing 9.125 percent Unsecured Medium-Term Notes and is expected to result in an overall reduction in the Company’s interest expense. As of December 31, 2003, the Company had $105.0 million of either secured or unsecured debt remaining under this registration statement.

In July 2001, the Company filed a registration statement on Form S-3 with the Securities and Exchange Commission for the purpose of issuing up to 3.7 million shares of common stock. No common stock has been issued and the Company currently does not have any plans to issue common stock under this registration statement.

AVISTA CORPORATION

Inter-Company Debt; Subordination

As part of its on-going cash management practices and operations, Avista Corp. from time to time makes unsecured short-term loans to, and borrowings from, Avista Capital. In turn, Avista Capital from time to time makes unsecured short-term loans to, and borrowings from, its subsidiaries. As of December 31, 2003, Avista Corp. held short-term notes receivable from Avista Capital in the principal amount of $40.0 million.

In addition, Avista Capital from time to time guarantees the indebtedness and other obligations of its subsidiaries. See “Energy Marketing and Resource Management Operations” for further information.

The credit arrangements of Avista Capital’s subsidiaries generally provide that any indebtedness owed by such entity to its corporate parent will be subordinated to the indebtedness outstanding under such credit arrangements.

The right of Avista Corp., as a shareholder, to receive assets of any of its direct or indirect subsidiaries upon the subsidiary’s liquidation or reorganization (and the consequent right of the holders of debt securities and other creditors of Avista Corp. to participate in those assets) is junior to the claims against such assets of that subsidiary’s creditors. As a result, the obligations of Avista Corp. to its debt securityholders and other unrelated creditors are effectively subordinated in right of payment to all indebtedness and other liabilities and commitments (including trade payables and lease obligations) of Avista Corp.’s direct and indirect subsidiaries. Similarly, the obligations of Avista Capital to its creditors are effectively subordinated in right of payment to all indebtedness and other liabilities and commitments of its direct and indirect subsidiaries.

Pension Plan

As of December 31, 2003, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. The Company does not expect the current pension plan funding deficit to have a material adverse impact on its financial condition, results of operations or cash flows. The Company made $12 million in cash contributions to the pension plan in each of 2003 and 2002 and expects to make $15 million in cash contributions during 2004. The Company’s goal is to have the pension plan’s current obligations fully funded by the end of 2006.

Off-Balance Sheet Arrangements

Avista Receivables Corp. (ARC) is a wholly owned, bankruptcy-remote subsidiary of the Company formed in 1997 for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On May 29, 2002, ARC, the Company and a third-party financial institution entered into a three-year agreement whereby ARC can sell without recourse, on a revolving basis, up to $100.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. As of December 31, 2003, $72.0 million in receivables were sold pursuant to the revolving agreement. This agreement provides the Company with cost-effective funds for working capital requirements, capital expenditures and other general corporate needs.

Spokane Energy, LLC

In December 1998, the Company received cash proceeds of $143.4 million from a transaction in which the Company assigned and transferred certain rights under a long-term power sales contract with PGE to a funding trust. The proceeds were recorded as deferred revenue and were being amortized into revenues over the 16-year period of the long-term sales contract. Pursuant to the WUTC order in September 2001, the Company was directed to offset the Washington share of the deferred revenue against deferred power costs. The IPUC order in October 2001 directed the Company to amortize the remaining Idaho share of the deferred revenue against deferred power costs over the 15-month period between October 2001 and December 2002.

Under this power exchange arrangement, Peaker, LLC (Peaker) purchases capacity from Avista Corp. and sells capacity to Spokane Energy LLC (Spokane Energy), a subsidiary of Avista Corp., formed in 1998 solely for the purpose of facilitating a long-term capacity contract between PGE and Avista Corp. Spokane Energy sells the related capacity to PGE. Peaker acts as an intermediary to fulfill certain regulatory requirements between Spokane Energy and Avista Corp. from dealing directly with each other. The transaction is structured such that Spokane Energy bears full recourse risk for a loan (balance of $120.0 million as of December 31, 2003) that matures in January 2015 with no recourse to Avista Corp. related to the loan. Peaker is obligated to pay approximately $150,000 per month to Avista Corp. for its capacity purchase. Peaker was formed solely for the purpose of assuming all rights and obligations from

AVISTA CORPORATION

Enron Power Marketing, Inc. (EPMI), which assigned the transactions to Peaker in November 2003 as part of its bankruptcy proceedings. Peaker is not affiliated with EPMI.

Credit Ratings

The Company’s credit ratings were downgraded during the fourth quarter of 2001 resulting in an overall corporate credit rating that is below investment grade. The downgrade was due to liquidity concerns primarily related to the significant amount of purchased power and natural gas costs incurred and the resulting increase in debt levels and debt service costs.

The following table summarizes the Company’s credit ratings as of March 1, 2004:

Standard & Poor’s

Moody’s

Fitch, Inc.

Avista Corporation

Corporate/Issuer rating

BB+

Ba1

BB+

Senior secured debt

BBB-

Baa3

BBB-

Senior unsecured debt

BB+

Ba1

BB+

Preferred stock

BB-

Ba3

Avista Capital I*

Preferred Trust Securities

BB-

Ba2

BB+

Avista Capital II*

Preferred Trust Securities

BB-

Ba2

Rating outlook

Stable

Negative

Stable

* Only assets are subordinated debentures of Avista Corporation

These security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other rating.

Avista Utilities Operations

Capital expenditures for Avista Utilities were $286.4 million for the years 2001 through 2003. This excludes Coyote Springs 2, which was included in Energy Marketing and Resource Management for 2001 and 2002. During the years 2004 through 2006, utility capital expenditures are expected to be in the range of $100 million to $120 million per year and long-term debt maturities, mandatory redemptions of preferred stock and sinking fund requirements total $165 million. During this period, internally generated funds and short-term borrowing arrangements are expected to be sufficient to fund these requirements. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. Avista Utilities’ planned capital expenditures include an expansion and enhancement of its 230 kV transmission system at an estimated total cost of approximately $100 million that Avista Utilities expects will be completed by the end of 2006.

Avista Utilities held cash deposits from other parties in the amount of $19.0 million as of December 31, 2003, which is included in cash and cash equivalents with a corresponding amount in deposits from counterparties on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

The transition of the natural gas procurement operations from Avista Energy to Avista Utilities will impact the level of counterparty credit requirements with respect to natural gas purchase contracts.

As of December 31, 2003, Avista Utilities had $19.6 million in cash and temporary investments, including the $19.0 million of cash deposits from other parties.

See “Notes 5, 14, 15, 16, 19, 20, 21 and 22 of Notes to Consolidated Financial Statements” for additional details related to financing activities.

AVISTA CORPORATION

Energy Marketing and Resource Management Operations

On July 25, 2003, Avista Energy and its subsidiary, Avista Energy Canada, Ltd., as co-borrowers, entered into a committed credit agreement with a group of banks in the aggregate amount of $110.0 million expiring July 23, 2004, replacing a previous uncommitted credit agreement that had an extended expiration date of July 31, 2003. This new committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties. This facility is guaranteed by Avista Capital and secured by Avista Energy’s assets. The maximum amount of credit extended by the banks for the issuance of letters of credit is the subscribed amount of the facility less the amount of outstanding cash advances, if any. The maximum amount of credit extended by the banks for cash advances is $30.0 million. No cash advances were outstanding under the credit agreement as of December 31, 2003. Letters of credit in the aggregate amount of $15.0 million and $17.4 million were outstanding as of December 31, 2003 and 2002, respectively. The cash deposits of Avista Energy at the respective banks collateralize these letters of credit and is reflected as restricted cash on the Consolidated Balance Sheet.

The Avista Energy credit agreement contains customary covenants and default provisions, including covenants to maintain “minimum net working capital” and “minimum net worth,” as well as a covenant limiting the amount of indebtedness that the co-borrowers may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. Also, a reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement. Avista Energy was in compliance with the covenants of its credit agreement as of December 31, 2003.

Avista Energy believes that it will have access to credit facilities beyond the July 23, 2004 expiration date of its current committed credit agreement.

Avista Capital provides guarantees for Avista Energy’s credit agreement (see discussion above) and, in the course of business, may provide performance guarantees to other parties with whom Avista Energy may be doing business. At any point in time, Avista Capital is only liable for the outstanding portion of the performance guarantee, which was $35.0 million as of December 31, 2003. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $411.7 million as of December 31, 2003.

As part of its on-going cash management practices and operations, Avista Energy from time to time makes unsecured short-term loans to its parent, Avista Capital. Avista Capital’s Board of Directors has limited the total outstanding indebtedness to no more than $45.0 million. Further, as required under Avista Energy’s credit facility, such loans cannot be outstanding longer than 90 days without being repaid. During 2003, Avista Energy’s maximum total outstanding short-term loan to Avista Capital was $42.4 million including accrued interest. As of December 31, 2003, all outstanding loans including accrued interest had been repaid.

Avista Energy manages collateral requirements with counterparties by providing letters of credit, providing guarantees from Avista Capital, depositing cash with counterparties and offsetting transactions with counterparties. Cash deposited with counterparties totaled $36.8 million as of December 31, 2003, which is included in prepayments and other current assets on the Consolidated Balance Sheet. Avista Energy held cash deposits from other parties in the amount of $78.8 million as of December 31, 2003, which is included in cash and cash equivalents with a corresponding amount in deposits from counterparties on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

As of December 31, 2003, Avista Energy had $122.9 million in cash, including $16.5 million of restricted cash and $78.8 million of cash deposits from other parties. In addition, Avista Energy had $18.9 million of short-term investments held for trading as of December 31, 2003. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. These covenants allow for the payment of dividends from Avista Energy to Avista Capital up to current earnings levels. During 2003, Avista Energy paid $12.1 million in dividends to Avista Capital.

Capital expenditures for the Energy Marketing and Resource Management companies were $176.6 million for years 2001 through 2003, primarily due to Avista Power’s investment in Coyote Springs 2 as well as the purchase of turbines during 2001. Capital expenditures are expected to be less than $1.0 million per year in this business segment during the years 2004 through 2006.

AVISTA CORPORATION

Avista Advantage Operations

Capital expenditures for Avista Advantage were $4.2 million for the years 2001 through 2003. Capital expenditures for the years 2004 through 2006 are expected to be between $1.5 million and $2.5 million per year.

As of December 31, 2003, Avista Advantage had $0.1 million of cash and cash equivalents and $2.2 million in debt was outstanding. Avista Advantage’s outstanding debt is related to capital leases.

Other Operations

Capital expenditures for these companies were $1.8 million for the years 2001 through 2003. Capital expenditures for the years 2004 through 2006 are expected to be less than $1.0 million per year. As of December 31, 2003, this business segment had $2.1 million of cash and cash equivalents and $0.7 million in debt was outstanding. The outstanding debt includes short-term borrowings and capital leases.

Contractual Obligations

The following table provides a summary of the Company’s future contractual obligations as of December 31, 2003 (dollars in millions):


	2004		2005		2006		2007		2008		Thereafter
Avista Utilities:
Long-term debt maturities (1)	$	29	$	84	$	38	$	176	$	363	$	261
Long-term debt to affiliated trusts (1)		—		—		—		—		—		113
Sinking fund requirements (1)		3		3		3		3		1		14
Interest on long-term debt (2)		79		78		76		80		64		—
Short-term borrowings (3)		80		—		—		—		—		—
Accounts receivable sales (4)		72		—		—		—		—		—
Preferred stock redemptions (1)		2		2		2		25		—		—
Energy purchase contracts (5)		340		167		139		142		135		795
Public Utility District contracts (5)		3		4		3		3		3		23
Operating lease obligations (6)		6		2		2		2		2		7
Capital lease obligations (6)		1		1		1		1		1		—
Other obligations (7)		12		12		12		12		12		174
Pension plan funding (9)		15		15		20		22		—		—
Avista Capital (consolidated):
Short-term borrowings		1		—		—		—		—		—
Energy purchase contracts (8)		863		273		238		175		187		667
Operating lease obligations (6)		1		1		—		—		—		—
Capital lease obligations (6)		1		1		1		—		—		—

Total cash requirements	$	1,508	$	643	$	535	$	641	$	768	$	2,054

(1)		For 2004, the Company expects that cash flows from operations and short-term debt will provide sufficient funds for maturing long-term debt, sinking fund requirements and preferred stock redemptions. However, if market conditions warrant during 2004, the Company may issue long-term debt to fund these obligations and potentially repurchase long-term debt scheduled to mature in future years to reduce its overall debt service costs. In years subsequent to 2006, the Company will most likely need to issue additional long-term debt to fund these obligations.

(2)		Represents the Company’s estimate of interest payments on long-term debt, including long-term debt to affiliated trusts and preferred stock dividends. The Company will make interest payments beyond 2008; however, the Company has not made an estimate of such payments at this time.

(3)		Represents $80 million outstanding under a $245 million line of credit.

(4)		Represents $72 million outstanding under a revolving $100 million accounts receivable sales financing facility.

(5)		All of the energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail natural gas and electric customers’ energy requirements. As a result, these costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.

(6)		Includes the interest component of the lease obligation.

*AVISTA CORPORATION*

(7)		Represents operational agreements, settlements and other contractual obligations with respect to generation, transmission and distribution facilities. These costs are generally recovered through base retail rates.

(8)		Represents Avista Energy’s commitments under energy contracts in future periods. Avista Energy also has sales commitments related to energy commodities in future periods.

(9)		Represents the Company’s estimated cash contributions to the pension plan through 2007. The Company cannot reasonably estimate pension plan contributions beyond 2007 at this time.

As of December 31, 2003, Avista Corp. did not have any commitments outstanding with equity triggers. When the Company’s corporate credit rating was reduced to below investment grade in October 2001, additional collateral requirements due to rating triggers were met and further requirements are not currently anticipated. Avista Corp. does not expect any material impact from rating triggers; remaining triggers for Avista Corp. primarily relate to changes in pricing under certain financing agreements. A reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement.

Competition

Avista Utilities competes to provide service to new retail electric customers with various rural electric cooperatives and public utility districts in and adjacent to its service territories. Alternate providers of power may also compete for sales to existing customers, including new market entrants as a result of deregulation. Competition for available electric resources can be critical to utilities as surplus power resources are absorbed by load growth. Avista Utilities’ natural gas distribution operations compete with other energy sources; however, natural gas continues to maintain a price advantage compared to heating oil, propane and other fuels, provided that the natural gas distribution system is proximate to prospective customers.

The Energy Policy Act of 1992 (Energy Act) amended provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act to remove certain barriers to a competitive wholesale market. The Energy Act expanded the authority of the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity for the purpose of providing these services. It also created “exempt wholesale generators,” a class of independent power plant owners that are able to sell generation only at the wholesale level. This permits public utilities and other entities to participate through subsidiaries in the development of independent electric generating plants for sales to wholesale customers without being required to register under the PUHCA.

Participants in the wholesale market include other utilities, federal marketing agencies and energy trading and marketing companies. The wholesale market has changed significantly over the last few years with respect to market participants involved, level of activity, variability in market prices, liquidity, FERC-imposed price caps and counterparty credit issues. During 2000 and the first half of 2001, the electric wholesale market in the WECC region was more turbulent than previously experienced and marked by significant volatility, service disruptions and defaults by certain participants. During the second half of 2001 and 2002, wholesale market prices decreased to levels similar to those experienced before 2000. Wholesale market prices increased in 2003 compared to 2002; however, prices have not increased to levels experienced during 2000 and the first half of 2001. Currently, many energy companies are facing liquidity issues, and counterparty credit exposure is of concern to market participants. During 2002 and 2003 as compared to 2000 and the first half of 2001, electric and natural gas trading volumes have decreased, the energy markets are less volatile and fewer creditworthy counterparties participated in the energy markets. Avista Corp. is actively monitoring energy industry developments with a focus on liquidity, volatility of energy trading markets and counterparty credit exposure.

The Avista Capital subsidiaries, particularly Avista Advantage, are subject to competition as they develop products and services and enter new markets. Competition from other companies in these emerging industries may mean challenges for a company to be the first to market a new product or service to gain the advantage in market share. In order for these new businesses to grow as planned, one significant challenge will be the availability of funding and resources to meet the capital needs. Other challenges will be rapidly advancing technologies, possibly making some of the current technology quickly obsolete, and requiring continual research and development for product advancement. In order for some of these subsidiaries to succeed, they will need to reduce costs of these emerging technologies to make them affordable to future customers.

Business Risk

AVISTA CORPORATION

investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. See further reference to risks and uncertainties under “Safe Harbor for Forward-Looking Statements.”

Avista Utilities has mechanisms in each regulatory jurisdiction, which provide for the recovery of the majority of the changes in its power and natural gas costs. The majority of power and natural gas costs that exceed the amount currently recovered through retail rates are deferred on the balance sheet for the opportunity for recovery through future retail rates. These deferred power and natural gas costs are subject to review for prudence and recoverability and as such certain deferred costs may be disallowed by the respective regulatory agencies.

Hydroelectric conditions in 2001 were significantly below normal, leading to a greater than normal reliance on purchased power. Hydroelectric generation was slightly above normal in 2002 and 89 percent of normal in 2003. Forecasts as of February 2004 indicate that hydroelectric generation will be approximately 95 percent of normal in 2004. This forecast may change based upon additional precipitation, temperatures and other variables. The earnings impact of these factors is mitigated by regulatory mechanisms that are intended to defer increased power supply costs for recovery in future periods. Avista Utilities is not able to predict how the combination of energy resources, energy loads, prices, rate recovery and other factors will ultimately drive deferred power costs and the timing of recovery of these costs in future periods. See further information at “Avista Utilities - Regulatory Matters.”

Natural gas commodity prices increased dramatically during 2000 and remained at relatively high levels during the first half of 2001 before declining in the second half of the year. Natural gas commodity prices during 2002 were generally lower than during 2000 and the first half of 2001. Natural gas commodity prices increased towards the end of 2002 and into the first half of 2003 before declining somewhat the middle of 2003 and increasing at the end of 2003. Avista Utilities’ average prices per dekatherm were $5.50, $4.95 and $6.33 in 2003, 2002 and 2001, respectively. Market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. Avista Utilities believes that natural gas should sustain its market advantage over competing energy sources based on the levels of existing reserves and the potential for natural gas development in the future. Growth has occurred in the natural gas business in recent years due to increased demand for natural gas in new construction, as well as conversions from competing space and water heating energy sources to natural gas. Challenges facing Avista Utilities’ natural gas operations include, among other things, volatility in the price of natural gas, changes in the availability of natural gas, legislative and governmental regulations, weather conditions and the timing and approval of recovery for increased commodity costs. Avista Utilities’ natural gas business also faces the potential for certain natural gas customers to by-pass its natural gas system. To reduce the potential for such by-pass, Avista Utilities prices its natural gas services, including transportation contracts, competitively and has varying degrees of flexibility to price its transportation and delivery rates by means of individual contracts, subject to state regulatory review and approval. Avista Utilities has long-term transportation contracts with several of its largest industrial customers, which reduces the risk of these customers by-passing the system in the foreseeable future.

In addition to its asset management activities, Avista Energy trades electricity and natural gas, along with derivative commodity instruments, including futures, options, swaps and other contractual arrangements. As a result of these trading activities, Avista Energy is subject to various risks including commodity price risk and credit risk, as well as possible risks resulting from the imposition of market controls by federal and state agencies. The FERC is conducting proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds. As a result, certain parties have asserted claims for significant refunds from Avista Energy and lesser refunds from Avista Utilities, which could result in liabilities for refunding revenues recognized in prior periods. Avista Energy and Avista Utilities have joined other parties in opposing these proposals. The refund proceedings provide that any refunds owed could be offset against unpaid energy debts due to the same party. As of December 31, 2003, Avista Energy’s accounts receivable outstanding related to defaulting parties in California are fully offset by reserves for uncollected amounts and refunds. Avista Energy is pursuing recovery of the defaulted obligations. The FERC denied the request of certain parties for retroactive refunds for spot market sales in the Pacific Northwest during the period from December 25, 2000 to June 20, 2001. See “Power Market Issues” for further information with respect to the refund proceedings.

AVISTA CORPORATION

In connection with matching loads to available resources and optimizing the use of its assets, Avista Utilities engages in wholesale sales and purchases of electric capacity and energy and, accordingly, is also subject to commodity price risk, credit risk and other risks associated with these activities.

Commodity Price Risk. Both Avista Utilities and Avista Energy are subject to energy commodity price risk. The price of power in wholesale markets is affected primarily by fundamental factors related to production costs and by other factors including generating unit physical parameters, streamflows, the availability of hydroelectric and thermal generation and transmission capacity, weather and the resulting retail loads, and the price of coal, natural gas and oil to operate thermal generating units. Any combination of these factors that results in a shortage of energy generally causes the market price of power to move upward. In addition to production cost factors, wholesale power markets are subject to regulatory constraints including price controls. The FERC imposed a price mitigation plan in the western United States in June 2001 and has subsequently modified various price and market control regulations.

Price risk is, in general, the risk of fluctuation in the market price of the commodity needed, held or traded. In the case of electricity, prices can be affected by the adequacy of generating reserve margins, scheduled and unscheduled outages of generating facilities, availability of streamflows for hydroelectric generation, the price of thermal generating plant fuel, and disruptions or constraints to transmission facilities. Demand changes (caused by variations in the weather and other factors) can also affect market prices. Price risk also includes the risk of fluctuation in the market price of associated derivative commodity instruments (such as options and forward contracts). Price risk may also be influenced to the extent that the performance or non-performance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity. Wholesale market prices for power and natural gas in the western United States and western Canada were significantly higher in 2000 and the first half of 2001 than at any time in history, with unprecedented levels of volatility. Prices and volatility decreased considerably during the second half of 2001, 2002 and 2003 relative to 2000 and the first half of 2001.

Credit Risk. Credit risk relates to the risk of loss that Avista Utilities and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy and make financial settlements. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it and the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Avista Utilities and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by actively monitoring current credit exposures. These policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees, and the use of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty. However, despite mitigation efforts, defaults by counterparties periodically occur. Avista Energy experienced payment receipt defaults from certain parties impacted by the California energy crisis. Both Avista Corp. and Avista Energy engaged in considerable business and had short-term and long-term contracts with entities that have filed for bankruptcy protection. These bankruptcies and other changes, uncertainties and regulatory proceedings have resulted in reduced liquidity in the energy markets.

A trend of declining credit quality was evident during 2002 and continued into 2003, particularly throughout the energy industry. Rating agencies have downgraded the credit ratings of several of the counterparties of Avista Energy and Avista Utilities. Avista Energy and Avista Utilities regularly evaluate counterparties’ credit exposure for future settlements and delivery obligations. Avista Energy and Avista Utilities have taken a conservative position by reducing or eliminating open (unsecured) credit limits and implemented other credit risk reduction measures for parties perceived to have increased default risk. Counterparty collateral is used to offset the Company’s credit risk where unsettled net positions and future obligations by counterparties to pay Avista Utilities and/or Avista Energy or deliver to Avista Utilities and/or Avista Energy warrant.

Avista Energy has concentrations of suppliers and customers in the electric and natural gas industries including electric utilities, natural gas distribution companies, and other energy marketing and trading companies. In addition, Avista Energy has concentrations of credit risk related to geographic location. These concentrations of counterparties and concentrations of geographic location in the western United States and western Canada may impact Avista Energy’s overall exposure to credit risk, either positively or negatively, because the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

AVISTA CORPORATION

significantly, with the result that sudden and significant demands may be made against the Company’s capital resource reserves (credit facilities and cash). Avista Utilities and Avista Energy actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

In conjunction with the valuation of their commodity derivative instruments and accounts receivable, Avista Utilities and Avista Energy maintain credit reserves that are based on management’s evaluation of the credit risk of the overall portfolio. Based on these policies, exposures and credit reserves, the Company does not anticipate a materially adverse effect on its financial condition or results of operations as a result of counterparty nonperformance.

Other Operating Risks. In addition to commodity price risk, Avista Utilities’ commodity positions are subject to operational and event risks including, among others, increases in load demand, transmission or transport disruptions, fuel quality specifications, changes in regulatory requirements, forced outages at generating plants and disruptions to information systems and other administrative tools required for normal operations. Avista Utilities also has exposure to weather conditions and natural disasters that can cause physical damage to property, requiring repairs to restore utility service. The emergence of terrorism threats, both domestic and foreign, is a risk to the entire utility industry, including Avista Utilities. Potential disruptions to operations or destruction of facilities from terrorism or other malicious acts are not readily determinable. The Company has taken various steps to mitigate terrorism risks and to prepare contingency plans in the event that its facilities are targeted.

Interest Rate Risk. The Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company manages interest rate risk by taking advantage of market conditions when timing the issuance of long-term financings and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market conditions. Additionally, amounts borrowed under the Company’s $245.0 million committed line of credit have a variable interest rate.

The Company’s credit ratings were downgraded during the fourth quarter of 2001 resulting in an overall corporate credit rating that is below investment grade. These downgrades increased the cost of debt and other securities going forward and may affect the Company’s ability to issue debt and equity securities at reasonable interest rates and prices. The downgrades also required the Company to provide letters of credit and/or collateral to certain parties.

Foreign Currency Risk. The Company has investments in Canadian companies through Avista Energy Canada and its subsidiary, Copac Management, Inc. The Company’s exposure to foreign currency risk and other foreign operations risk was immaterial to the Company’s consolidated results of operations and financial position during 2003. Avista Energy may increase its transactions in Canada and, if so, implement processes to mitigate foreign currency risk related to international business activity.

Risk Management

Risk Policies and Oversight. Avista Utilities and Avista Energy use a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative, for Avista Utilities and Avista Energy. The Company’s Risk Management Committee, which is separate from the units tasked with managing this risk exposure and is overseen by the Audit Committee of the Company’s Board of Directors, monitors compliance with the Company’s risk management policies and procedures. The Company’s Risk Management Committee reviews the status of risk exposures through regular reports and meetings and it monitors compliance with the Company’s risk management policies and procedures on a regular basis. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses in earnings, cash flows and/or fair values.

Avista Utilities and Avista Energy also operate with a wholesale energy markets credit policy. The credit policy is designed to reduce the risk of financial loss in case counterparties default on delivery or settlement obligations and to conserve the Company’s liquidity as other parties may place credit limits or require collateral.

Quantitative Risk Measurements. Avista Utilities has volume limits for its imbalance between projected loads and resources. Normal operations result in seasonal mismatches between power loads and available resources. Avista Utilities is able to vary the operation of its generating resources to match parts of its hourly, daily and weekly load fluctuations. Avista Utilities uses the wholesale power markets to sell projected resource surpluses and obtain resources when deficits are projected. Any load/resource imbalances within a rolling 18-month planning horizon are managed within risk policy volumetric limits. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods. Volume limits for forward periods are based on monthly and

AVISTA CORPORATION

quarterly averages that may vary materially from the actual load and resource variations within any given month or operating day. Future projections of resources are updated as forecasted streamflows and other factors differ from prior estimates. Forward power markets may be illiquid, and market products available may not match Avista Utilities’ desired transaction size and shape. Therefore, open imbalance positions exist at any given time.

Avista Energy measures the risk in its electric and natural gas portfolio daily utilizing a Value-at-Risk (VAR) model, which monitors its risk in comparison to established thresholds. VAR measures the expected portfolio loss under hypothetical adverse price movements, over a given time interval within a given confidence level. The VAR computations utilize historical price movements over a specified period to simulate forward price curves in the energy markets and estimate the potential unfavorable impact of price movement in the portfolio of transactions scheduled to settle within the following eight calendar quarters. The quantification of market risk using VAR provides a consistent measure of risk across Avista Energy’s continually changing portfolio. VAR represents an estimate of reasonably possible net losses in earnings that would be recognized on its portfolio assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur. Avista Energy’s VAR computations utilize several key assumptions, including a 95 percent confidence level for the resultant price movement and holding periods of one and three days. The calculation includes derivative commodity instruments held for trading purposes and excludes the effects of embedded physical options in the trading portfolio. For forward transactions that settle beyond the next eight calendar quarters, Avista Energy applies other risk measurement techniques, including price sensitivity stress tests, to assess the future market risk. Volatility in longer-dated forward markets tends to be significantly less than in near-term markets. Avista Energy also measures its open positions in terms of volumes at each delivery location for each forward time period. The extent of open positions is included in the risk management policy and is measured with stress tests and VAR modeling.

As of December 31, 2003, Avista Energy’s estimated potential one-day unfavorable impact on gross margin as measured by VAR was $0.7 million, compared to $0.7 million as of December 31, 2002. The average daily VAR for 2003 was $0.7 million. The high daily VAR was $1.2 million and the low daily VAR was $0.4 million during 2003. Avista Energy was in compliance with its one-day VAR limits during 2003. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

As of December 31, 2003, 91 percent of Avista Corp’s credit exposure was to investment grade counterparties or noninvestment grade counterparties whose exposure was mitigated by collateral posted to Avista Corp. Of the remaining unmitigated exposure to non-investment grade counterparties, 61 percent represents settlements that were made within thirty days after December 31, 2003.

As of December 31, 2003, 93 percent of Avista Energy’s credit exposure was to investment grade counterparties or noninvestment grade counterparties whose exposure was mitigated through collateral posted to Avista Energy. Of the remaining unmitigated exposure to non-investment grade counterparties, approximately 84 percent represents settlements that were made within thirty days after December 31, 2003.

Economic and Load Growth

Avista Utilities, along with others in the service area, encourages regional economic development, including expanding existing businesses and attracting new businesses to the Inland Northwest region. Agriculture, mining and lumber were the primary industries for many years; today health care, education, finance, electronic and other manufacturing, tourism and the service sectors are growing in importance in Avista Utilities’ service area. Avista Utilities anticipates moderate economic growth to continue in its Oregon service area.

Avista Utilities anticipates residential and commercial electric load growth to average between 2.0 and 2.5 percent annually for the next four years, primarily due to increases in both population and the number of businesses in its service territory. While the number of electric customers is expected to increase, the average annual usage by residential customers is expected to remain steady. Avista Utilities anticipates natural gas load growth to average between 4.0 and 4.5 percent annually in its Washington and Idaho service territory and between 2.5 and 3.0 percent in its Oregon and California service territory for the next four years. The anticipated natural gas load growth is primarily expected through conversions to natural gas from competing space and water heating energy sources, and population increases and business growth in its service territory. Natural gas loads for space heating vary significantly with annual fluctuations in weather within Avista Utilities’ service territories.

The forward-looking projections set forth above regarding retail sales growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail sales growth are also based upon various assumptions including, without limitation, assumptions relating to weather

AVISTA CORPORATION

and economic and competitive conditions, internal analysis of company-specific data, such as energy consumption patterns and internal business plans, and an assumption that Avista Utilities will incur no material loss of retail customers due to self-generation or retail wheeling. Changes in the underlying assumptions can cause actual experience to vary significantly from forward-looking projections.

Management Succession and Employee Issues

Protecting the Company’s culture, mission, and long-term strategy by having a strong succession planning and management development process is one of the key strategic initiatives at Avista Corp. With over 30 percent of Avista Utilities’ current workforce nearing retirement eligibility over the next 5 to 15 years the Company has placed its focus on how it will maintain continuity. The Company’s executive officer team continues to work towards ensuring that an effective succession planning process is in place for the best interests of the Company’s future.

The Company has implemented bench strength analysis in its management group as well as in key technical and craft areas. The focus is on organizational leadership capability as well as technically complex jobs that take years to grow into. The Company has implemented development plans for its future successors that identify areas of strengths and weaknesses. Development plans provide action steps that provide new opportunities to work towards ensuring that successor candidates have the needed experiences for running the Company. The Company believes that its succession planning process is providing the right structure to assure that the Company has the ability to sustain itself successfully into the future.

Environmental Issues and Other Contingencies

See “Note 25 of the Notes to Consolidated Financial Statements.”

Dividends

Avista Energy holds a significant portion of cash and cash equivalents reflected on the Consolidated Balance Sheet. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. These covenants allow for the payment of dividends from Avista Energy to Avista Capital up to current earnings levels. During 2003, Avista Energy paid $12.1 million in dividends to Avista Capital.

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations: Business Risk and Risk Management,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Energy Market and Resource Management-Energy trading activities and positions” and “Note 21 of the Notes to Consolidated Financial Statements.”

Item 8. Financial Statements and Supplementary Data

The Independent Auditor’s Report and Financial Statements begin on the next page.

INDEPENDENT AUDITORS’ REPORT

Avista Corporation
Spokane, Washington

We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and of cash flows, which include the schedule of information by business segments, for each of the three years in the period ended December 31, 2003. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As described in Note 2 to the consolidated financial statements (“Note 2”), during 2003, the Company changed its method of accounting for energy trading activities related to the transition from Emerging Issues Task Force Issue No. 98-10 to Statement of Financial Accounting Standards (“SFAS”) No. 133, also, as described in Note 2, the Company was required to consolidate WP Funding LP, and deconsolidate Avista Capital I and Avista Capital II related to the adoption of FASB Interpretation No. 46. Additionally, as described in Note 2, during 2003, the Company changed its classification of preferred stock to conform to the requirements of SFAS No. 150, and its classification of asset retirement costs to conform to SFAS No. 143. Additionally, as described in Note 1 to the consolidated financial statements, during 2002, the Company changed its method of accounting for goodwill to conform to SFAS No. 142.

/s/ Deloitte & Touche LLP

Seattle, Washington
February 27, 2004

CONSOLIDATED STATEMENTS OF INCOME
Avista Corporation
For the Years Ended December 31
Dollars in thousands, except per share amounts


	2003			2002			2001
OPERATING REVENUES	$	1,123,385		$	1,062,916		$	1,511,751

OPERATING EXPENSES:
Resource costs		576,492			536,714			967,098
Operations and maintenance		138,058			125,930			129,351
Administrative and general		97,494			105,647			103,317
Depreciation and amortization		77,811			71,867			70,506
Taxes other than income taxes		61,827			65,616			57,413

Total operating expenses		951,682			905,774			1,327,685

INCOME FROM OPERATIONS		171,703			157,142			184,066

OTHER INCOME (EXPENSE):
Interest expense		(91,505	)		(104,866	)		(105,819	)
Interest expense to affiliated trusts		(1,480	)		—			—
Capitalized interest		1,092			7,486			10,498

Net interest expense		(91,893	)		(97,380	)		(95,321	)
Other income - - net		6,173			17,261			20,081

Total other income (expense)-net		(85,720	)		(80,119	)		(75,240	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		85,983			77,023			108,826
INCOME TAXES		35,340			34,849			40,585

INCOME FROM CONTINUING OPERATIONS		50,643			42,174			68,241

DISCONTINUED OPERATIONS (Note 3):
Loss before asset impairment charges, minority interest and income taxes		(4,029	)		(10,461	)		(36,838	)
Asset impairment charges		(3,905	)		—			(58,417	)
Minority interest		—			241			5,192
Income tax benefit		2,985			3,501			33,978

LOSS FROM DISCONTINUED OPERATIONS		(4,949	)		(6,719	)		(56,085	)

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		45,694			35,455			12,156
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (net of tax)		(1,190	)		(4,148	)		—

NET INCOME		44,504			31,307			12,156
DEDUCT-Preferred stock dividend requirements		1,125			2,402			2,432

INCOME AVAILABLE FOR COMMON STOCK	$	43,379		$	28,905		$	9,724

Weighted-average common shares outstanding (thousands), Basic		48,232			47,823			47,417
Weighted-average common shares outstanding (thousands), Diluted		48,630			47,874			47,435
EARNINGS PER COMMON SHARE, BASIC (Note 23):
Earnings per common share from continuing operations	$	1.03		$	0.83		$	1.39
Loss per common share from discontinued operations		(0.10	)		(0.14	)		(1.18	)

Earnings per common share before cumulative effect of accounting change		0.93			0.69			0.21
Loss per common share from cumulative effect of accounting change		(0.03	)		(0.09	)		—

Total earnings per common share, basic	$	0.90		$	0.60		$	0.21

EARNINGS PER COMMON SHARE, DILUTED (Note 23):
Earnings per common share from continuing operations	$	1.02		$	0.83		$	1.38
Loss per common share from discontinued operations		(0.10	)		(0.14	)		(1.18	)

Earnings per common share before cumulative effect of accounting change		0.92			0.69			0.20
Loss per common share from cumulative effect of accounting change		(0.03	)		(0.09	)		—

Total earnings per common share, diluted	$	0.89		$	0.60		$	0.20

Dividends paid per common share	$	0.49		$	0.48		$	0.48

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Avista Corporation
For the Years Ended December 31
Dollars in thousands


	2003			2002			2001
NET INCOME	$	44,504		$	31,307		$	12,156

OTHER COMPREHENSIVE INCOME (LOSS):
Foreign currency translation adjustment		931			8			(221	)
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $51 and $(677), respectively		94			(1,258	)		—
Unfunded accumulated benefit obligation - net of taxes of $5,097, $(9,736) and $(398), respectively		9,466			(18,081	)		(740	)
Unrealized gains on derivative commodity instruments - net of taxes of $1,245		2,313			—			—
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(258)		(480	)		—			—
Unrealized investment gains (losses) - net of taxes of $(655) and $783, respectively		—			(1,217	)		1,455
Reclassification adjustment for net realized losses on investments - net of taxes of $152 and $70, respectively		—			283			130

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		12,324			(20,265	)		624

COMPREHENSIVE INCOME	$	56,828		$	11,042		$	12,780

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS
Avista Corporation
As of December 31
Dollars in thousands


				2003		2002

ASSETS:
CURRENT ASSETS:
	Cash and cash equivalents			$	128,126	$	173,286
	Restricted cash				16,472		12,983
	Securities held for trading				18,903		—
	Accounts and notes receivable-less allowances of $46,382 and $46,909, respectively				318,848		320,836
	Energy commodity assets				253,676		365,477
	Materials and supplies, fuel stock and natural gas stored				22,428		21,746
	Prepayments and other current assets				79,472		73,437
	Deferred income taxes				11,455		—
	Assets held for sale from discontinued operations				—		5,900

		Total current assets			849,380		973,665

NET UTILITY PROPERTY:
	Utility plant in service				2,606,012		2,370,811
	Construction work in progress				49,615		17,581

		Total			2,655,627		2,388,392
	Less: Accumulated depreciation and amortization				710,990		639,278

		Total net utility property			1,944,637		1,749,114

OTHER PROPERTY AND INVESTMENTS:
	Investment in exchange power-net				38,383		40,833
	Non-utility properties and investments-net				89,133		199,579
	Non-current energy commodity assets				242,359		348,309
	Investment in affiliated trusts				13,403		—
	Other property and investments-net				17,958		12,702

		Total other property and investments			401,236		601,423

DEFERRED CHARGES:
	Regulatory assets for deferred income tax				131,763		139,138
	Other regulatory assets				44,381		29,735
	Utility energy commodity derivative assets				39,500		60,322
	Power and natural gas deferrals				171,342		166,782
	Unamortized debt expense				48,825		51,128
	Other deferred charges				30,431		28,236

		Total deferred charges			466,242		475,341

			TOTAL ASSETS	$	3,661,495	$	3,799,543

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS (continued)
Avista Corporation
As of December 31
Dollars in thousands


				2003			2002

LIABILITIES AND STOCKHOLDERS’ EQUITY:
CURRENT LIABILITIES:
	Accounts payable			$	298,285		$	339,637
	Energy commodity liabilities				229,642			304,781
	Deposits from counterparties				97,811			92,674
	Current portion of long-term debt				29,711			71,896
	Current portion of preferred stock-cumulative (17,500 shares outstanding)				1,750			—
	Short-term borrowings				80,525			30,000
	Interest accrued				18,504			20,307
	Other current liabilities				82,125			81,141
	Liabilities of discontinued operations				—			2,084

		Total current liabilities			838,353			942,520

LONG-TERM DEBT					925,012			902,635

LONG-TERM DEBT TO AFFILIATED TRUSTS					113,403			—

PREFERRED STOCK-CUMULATIVE (subject to mandatory redemption):
	10,000,000 shares authorized: $6.95 Series K 297,500 shares outstanding ($100 stated value) as of December 31, 2003				29,750			—

OTHER NON-CURRENT LIABILITIES AND DEFERRED CREDITS:
	Non-current energy commodity liabilities				192,731			314,204
	Regulatory liability for utility plant retirement costs				197,697			185,410
	Utility energy commodity derivative liabilities				36,057			50,058
	Deferred income taxes				492,799			452,457
	Other non-current liabilities and deferred credits				84,441			106,218

		Total other non-current liabilities and deferred credits			1,003,725			1,108,347

		TOTAL LIABILITIES			2,910,243			2,953,502

COMMITMENTS AND CONTINGENCIES (See Notes to Consolidated Financial Statements)

COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES					—			100,000

PREFERRED STOCK-CUMULATIVE (subject to mandatory redemption):
	10,000,000 shares authorized: $6.95 Series K 332,500 shares outstanding ($100 stated value) as of December 31, 2002				—			33,250

COMMON EQUITY:
	Common stock, no par value; 200,000,000 shares authorized; 48,344,009 and 48,044,208 shares outstanding				626,788			623,092
	Note receivable from employee stock ownership plan				(2,424	)		(4,146	)
	Capital stock expense and other paid in capital				(10,950	)		(11,928	)
	Accumulated other comprehensive loss				(8,040	)		(20,364	)
	Retained earnings				145,878			126,137

		Total common equity			751,252			712,791

		TOTAL STOCKHOLDERS’ EQUITY			751,252			746,041

			TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,661,495		$	3,799,543

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
Increase (Decrease) in Cash and Cash Equivalents
Avista Corporation
For the Years Ended December 31
Dollars in thousands


				2003			2002			2001

CONTINUING OPERATING ACTIVITIES:
	Net income			$	44,504		$	31,307		$	12,156
	Loss from discontinued operations				4,949			6,719			56,085
	Cumulative effect of accounting change				1,190			4,148			—
	Purchases of securities held for trading				(18,865	)		—			—
	Non-cash items included in net income:
		Depreciation and amortization			77,811			71,867			70,506
		Provision for deferred income taxes			28,395			(40,287	)		79,141
		Power and natural gas cost amortizations (deferrals), net			3,829			68,481			(210,540	)
		Amortization of debt expense			7,972			8,861			5,639
		Impairment of assets			4,900			—			8,240
		Energy commodity assets and liabilities			22,128			87,403			30,238
		Other			(11,214	)		(10,763	)		(12,096	)
		Changes in working capital components:
			Restricted cash		(3,489	)		(11,783	)		1,800
			Sale of customer accounts receivable under revolving agreement-net		7,000			(10,000	)		(5,000	)
			Accounts and notes receivable		(4,485	)		80,342			457,408
			Materials and supplies, fuel stock and natural gas stored		(682	)		(717	)		(106	)
			Other current assets		(6,035	)		(21,906	)		15,172
			Accounts payable		(41,352	)		(27,770	)		(516,778	)
			Deposits from counterparties		5,137			76,954			(80,880	)
			Other current liabilities		871			14,004			22,177

NET CASH PROVIDED BY (USED IN) CONTINUING OPERATING ACTIVITIES					122,564			326,860			(66,838	)

CONTINUING INVESTING ACTIVITIES:
	Utility property construction expenditures (excluding AFUDC)				(102,271	)		(64,207	)		(119,905	)
	Other capital expenditures				(3,388	)		(18,873	)		(160,299	)
	Changes in other property and investments				(5,724	)		1,418			11,561
	Repayments received on notes receivable				1,214			33,752			1,000
	Proceeds from property sales and sale of subsidiary investments				549			586			75,953
	Assets acquired and investments in subsidiaries				(229	)		(461	)		(23,321	)

NET CASH USED IN CONTINUING INVESTING ACTIVITIES					(109,849	)		(47,785	)		(215,011	)

CONTINUING FINANCING ACTIVITIES:
	Increase (decrease) in short-term borrowings				50,525			(45,099	)		(88,061	)
	Proceeds from issuance of long-term debt				44,795			621			550,457
	Redemption and maturity of long-term debt				(124,859	)		(204,014	)		(140,208	)
	Redemption of preferred stock				(1,575	)		(1,750	)		—
	Issuance of common stock				6,155			7,035			8,267
	Repurchase of common stock under equity compensation plans				(658	)		—			—
	Cash dividends paid				(24,777	)		(25,456	)		(25,110	)
	Premiums paid for the redemption of long-term debt				(1,709	)		(9,456	)		—
	Long-term debt and short-term borrowing issuance costs				(2,430	)		(6,534	)		(19,693	)

NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES					(54,533	)		(284,653	)		285,652

NET CASH PROVIDED BY (USED IN) CONTINUING OPERATIONS					(41,818	)		(5,578	)		3,803
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS					(3,342	)		8,967			(28,342	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					(45,160	)		3,389			(24,539	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD					173,286			169,897			194,436

CASH AND CASH EQUIVALENTS AT END OF PERIOD				$	128,126		$	173,286		$	169,897

SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid during the period:
		Interest		$	86,755		$	95,801		$	98,571
		Income taxes			11,476			7,428			(35,874	)
	Non-cash financing and investing activities:
		Property and equipment purchased under capital leases			5,312			—			—
		Accounts receivable from sale of non-operating assets			—			—			22,665
		Unrealized gain (loss) on interest rate swap agreements			145			(1,936	)		—
		Intangible asset related to pension plan			(654	)		6,366			—
		Unfunded accumulated benefit obligation			15,198			(34,164	)		(1,139	)
		Unrealized investment gains (losses)			—			(1,436	)		2,437

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Avista Corporation
For the Years Ended December 31
Dollars in thousands


	Preferred Stock
	Series K						Common Stock

	Shares			Amount			Shares			Amount

Balance as of December 31, 2000		350,000		$	35,000			47,208,689		$	610,741

Net income
Stock distributed under compensatory plans								91,128			1,763
Employee Investment Plan (401-K)								172,681			2,823
Dividend Reinvestment Plan								160,180			2,410
Repayments of note receivable
Other comprehensive income
Cash dividends paid (common stock)
Cash dividends paid (preferred stock)
ESOP dividend tax savings

Balance as of December 31, 2001		350,000		$	35,000			47,632,678		$	617,737

Net income
Stock distributed under compensatory plans								2,730			74
Employee Investment Plan (401-K)								227,585			3,046
Dividend Reinvestment Plan								181,215			2,235
Redemption of preferred stock		(17,500	)		(1,750	)
Repayments of note receivable
Other comprehensive loss
Cash dividends paid (common stock)
Cash dividends paid (preferred stock)
ESOP dividend tax savings

Balance as of December 31, 2002		332,500		$	33,250			48,044,208		$	623,092

Net income
Stock purchased under compensatory plans								(37,439	)		(513	)
Stock distributed under compensatory plans								37,439			366
Employee Investment Plan (401-K)								130,603			1,462
Dividend Reinvestment Plan								169,198			2,381
Redemption of preferred stock		(17,500	)		(1,750	)
Repayments of note receivable
Other comprehensive income
Cash dividends paid (common stock)
Cash dividends paid (preferred stock)
ESOP dividend tax savings
Cumulative effect of accounting change		(315,000	)		(31,500	)

Balance as of December 31, 2003		—			—			48,344,009		$	626,788

[Additional columns below]

[Continued from above table, first column(s) repeated]


	Note
	Receivable			Capital			Accumulated
	from Employee			Stock Expense			Other
	Stock			and Other			Comprehensive			Retained
	Ownership Plan			Paid-in Capital			Income (Loss)			Earnings			Total

Balance as of December 31, 2000	$	(7,040	)	$	(11,696	)	$	(723	)	$	132,942		$	759,224

Net income											12,156			12,156
Stock distributed under compensatory plans					(228	)					(14	)		1,521
Employee Investment Plan (401-K)														2,823
Dividend Reinvestment Plan														2,410
Repayments of note receivable		1,361												1,361
Other comprehensive income								624						624
Cash dividends paid (common stock)											(22,765	)		(22,765	)
Cash dividends paid (preferred stock)											(2,432	)		(2,432	)
ESOP dividend tax savings											141			141

Balance as of December 31, 2001	$	(5,679	)	$	(11,924	)	$	(99	)	$	120,028		$	755,063

Net income											31,307			31,307
Stock distributed under compensatory plans					(4	)								70
Employee Investment Plan (401-K)														3,046
Dividend Reinvestment Plan														2,235
Redemption of preferred stock														(1,750	)
Repayments of note receivable		1,533												1,533
Other comprehensive loss								(20,265	)					(20,265	)
Cash dividends paid (common stock)											(22,955	)		(22,955	)
Cash dividends paid (preferred stock)											(2,402	)		(2,402	)
ESOP dividend tax savings											159			159

Balance as of December 31, 2002	$	(4,146	)	$	(11,928	)	$	(20,364	)	$	126,137		$	746,041

Net income											44,504			44,504
Stock purchased under compensatory plans											(145	)		(658	)
Stock distributed under compensatory plans					219									585
Employee Investment Plan (401-K)														1,462
Dividend Reinvestment Plan														2,381
Redemption of preferred stock					175									(1,575	)
Repayments of note receivable		1,722												1,722
Other comprehensive income								12,324						12,324
Cash dividends paid (common stock)											(23,634	)		(23,634	)
Cash dividends paid (preferred stock)											(1,125	)		(1,125	)
ESOP dividend tax savings											141			141
Cumulative effect of accounting change					584									(30,916	)

Balance as of December 31, 2003	$	(2,424	)	$	(10,950	)	$	(8,040	)	$	145,878		$	751,252

The Accompanying Notes are an Integral Part of These Statements.

SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS
Avista Corporation
For the Years Ended December 31
Dollars in thousands


			2003			2002			2001

OPERATING REVENUES:
	Avista Utilities		$	928,211		$	893,964		$	1,230,847
	Energy Marketing and Resource Management			307,141			222,634			403,743
	Avista Advantage			19,839			16,911			13,151
	Other			13,581			14,645			16,385
	Intersegment eliminations			(145,387	)		(85,238	)		(152,375	)

		Total operating revenues	$	1,123,385		$	1,062,916		$	1,511,751

RESOURCE COSTS:
	Avista Utilities		$	474,927		$	453,525		$	849,996
	Energy Marketing and Resource Management			246,952			168,427			269,477
	Intersegment eliminations			(145,387	)		(85,238	)		(152,375	)

		Total resource costs	$	576,492		$	536,714		$	967,098

GROSS MARGINS (operating revenues less resource costs):
	Avista Utilities		$	453,284		$	440,439		$	380,851
	Energy Marketing and Resource Management			60,189			54,207			134,266

		Total gross margins (operating revenues less resource costs)	$	513,473		$	494,646		$	515,117

OPERATIONS AND MAINTENANCE EXPENSES:
	Avista Utilities		$	107,697		$	97,668		$	97,831
	Energy Marketing and Resource Management			4,900			—			—
	Avista Advantage			11,813			13,569			16,302
	Other			13,648			14,693			15,218

		Total operations and maintenance expenses	$	138,058		$	125,930		$	129,351

ADMINISTRATIVE AND GENERAL EXPENSES:
	Avista Utilities		$	65,951		$	63,751		$	53,416
	Energy Marketing and Resource Management			22,950			21,820			33,494
	Avista Advantage			6,705			6,736			8,019
	Other			1,888			13,340			8,388

		Total administrative and general expenses	$	97,494		$	105,647		$	103,317

DEPRECIATION AND AMORTIZATION EXPENSES:
	Avista Utilities		$	72,068		$	66,243		$	61,383
	Energy Marketing and Resource Management			1,259			1,227			2,188
	Avista Advantage			2,652			2,968			3,928
	Other			1,832			1,429			3,007

		Total depreciation and amortization expenses	$	77,811		$	71,867		$	70,506

INCOME FROM OPERATIONS:
	Avista Utilities		$	146,777		$	149,180		$	114,927
	Energy Marketing and Resource Management			30,078			29,211			94,669
	Avista Advantage			(1,331	)		(6,363	)		(15,098	)
	Other			(3,821	)		(14,886	)		(10,432	)

		Total income from operations	$	171,703		$	157,142		$	184,066

INCOME FROM CONTINUING OPERATIONS:
	Avista Utilities		$	36,241		$	36,382		$	24,164
	Energy Marketing and Resource Management			20,672			22,425			63,246
	Avista Advantage			(1,334	)		(4,253	)		(10,748	)
	Other			(4,936	)		(12,380	)		(8,421	)

		Total income from continuing operations	$	50,643		$	42,174		$	68,241

ASSETS:
	Avista Utilities		$	2,563,572		$	2,369,418		$	2,569,798
	Energy Marketing and Resource Management			1,013,213			1,349,626			1,506,185
	Avista Advantage			36,405			31,733			20,288
	Other			48,305			42,866			86,514
	Discontinued Operations			—			5,900			27,919

		Total assets	$	3,661,495		$	3,799,543		$	4,210,704

CAPITAL EXPENDITURES:
	Avista Utilities		$	102,271		$	64,207		$	119,905
	Energy Marketing and Resource Management			2,013			17,531			157,020
	Avista Advantage			459			1,109			2,664
	Other			916			233			615

		Total capital expenditures	$	105,659		$	83,080		$	280,204

The Accompanying Notes are an Integral Part of These Statements.

AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. Avista Utilities also provides natural gas distribution service in parts of eastern Washington, northern Idaho, northeast and southwest Oregon and in the South Lake Tahoe region of California. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments.

The Company’s operations are exposed to risks including, but not limited to, the price and supply of purchased power, fuel and natural gas, regulatory allowance of power and natural gas costs and capital investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale purchases and sales.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries. The accompanying financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (See Note 9).

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Significant estimates include determining unbilled revenues, the market value of energy commodity assets and liabilities, pension and other postretirement benefit plan liabilities, and contingent liabilities. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

System of Accounts

The accounting records of the Company’s utility operations are maintained in accordance with the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the appropriate state regulatory commissions.

Regulation

The Company is subject to state regulation in Washington, Idaho, Montana, Oregon and California. The Company is subject to federal regulation by the FERC.

Business Segments

Financial information for each of the Company’s business segments is reported in the Schedule of Information by Business Segments. Such information is an integral part of these consolidated financial statements. The business segment presentation reflects the basis currently used by the Company’s management to analyze performance and determine the allocation of resources. Avista Utilities’ business is managed based on the total regulated utility operation. The Energy Marketing and Resource Management business segment primarily consists of electricity and natural gas marketing, trading and resource management including optimization of energy assets owned by other entities and derivative commodity instruments such as futures, options, swaps and other contractual arrangements. Avista Advantage is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. The Other business segment includes other investments and operations of various subsidiaries as well as the operations of Avista Capital on a parent company only basis.

Avista Utilities Operating Revenues

Operating revenues for Avista Utilities related to the sale of energy are generally recorded when service is rendered

AVISTA CORPORATION

or energy is delivered to customers. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. Accounts receivable includes unbilled energy revenues of $9.0 million (net of $47.0 million of unbilled receivables sold) and $6.1 million (net of $40.9 million of unbilled receivables sold) as of December 31, 2003 and 2002, respectively. See Note 5 for information with respect to the sale of accounts receivable.

Avista Energy Operating Revenues

Effective January 1, 2003, Avista Energy follows Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” with respect to all contracts. Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts, which are not accounted for as derivatives under SFAS No. 133 and derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. For all periods ending on or before December 31, 2002, Avista Energy followed Statement of SFAS No. 133 with respect to all contracts entered into after October 25, 2002.

Avista Energy followed the mark-to-market method of accounting for energy contracts entered into for trading and price risk management purposes in compliance with Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” through December 31, 2002 for contracts entered into on or prior to October 25, 2002. Avista Energy recognized revenue based on the change in the market value of outstanding derivative commodity sales contracts, net of future servicing costs and reserves, in addition to revenue related to settled contracts. EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” rescinded EITF Issue No. 98-10 and related interpretative guidance and effectively required a transition to SFAS No. 133. Under EITF Issue No. 02-3, mark-to-market accounting is precluded for energy trading contracts that are not derivatives pursuant to SFAS No. 133. The rescission of EITF Issue No. 98-10 also eliminated the recognition of physical inventories at fair value other than provided by other accounting standards.

Research and Development Expenses

Company-sponsored research and development expenditures are expensed as incurred. Research and development expenses totaled $0.4 million, $3.8 million and $8.4 million in 2003, 2002 and 2001, respectively. These expenses primarily related to the activities of Avista Labs and are included in discontinued operations.

Advertising Expenses

The Company expenses advertising costs as incurred. Advertising expenses totaled $1.4 million, $1.3 million and $1.8 million in 2003, 2002 and 2001, respectively.

Taxes other than income taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers are recorded as both operating revenue and expense and totaled $31.7 million, $33.1 million and $26.3 million in 2003, 2002 and 2001, respectively.

Other Income-Net

Other income-net consisted of the following items for the years ended December 31 (dollars in thousands):


		2003			2002			2001

Interest income		$	4,810		$	7,716		$	19,049
Interest on power and natural gas deferrals			8,361			9,597			12,995
Impairment of non-operating assets			—			—			(8,240	)
Net gain (loss) on the disposition of assets			(334	)		(33	)		2,884
Net gain (loss) on subsidiary investments			(1,207	)		2,084			(180	)
Minority interest			—			—			(656	)
Other expense			(7,063	)		(6,570	)		(10,208	)
Other income			1,606			4,467			4,437

	Total	$	6,173		$	17,261		$	20,081

AVISTA CORPORATION

Income Taxes

The Company and its eligible subsidiaries file consolidated federal income tax returns. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Company’s federal income tax returns were examined with all issues resolved, and all payments made, through the 2000 return.

The Company accounts for income taxes using the liability method. Under the liability method, a deferred tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The deferred tax expense for the period is equal to the net change in the deferred tax asset and liability accounts from the beginning to the end of the period. The effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date.

Stock-Based Compensation

The Company follows the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, employee stock options are accounted for under Accounting Principle Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Stock options are granted at exercise prices not less than the fair value of common stock on the date of grant. Under APB No. 25, no compensation expense is recognized pursuant to the Company’s stock option plans.

If compensation expense for the Company’s stock option plans were determined consistent with SFAS No. 123, net income and earnings per common share would have been the following pro forma amounts for the years ended December 31:


		2003		2002		2001

Net income (dollars in thousands):
	As reported	$	44,504	$	31,307	$	12,156
	Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of tax		2,186		3,051		2,801

	Pro forma	$	42,318	$	28,256	$	9,355

Basic earnings per common share
	As reported	$	0.90	$	0.60	$	0.21
	Pro forma	$	0.85	$	0.54	$	0.15
Diluted earnings per common share As reported
	As reported	$	0.89	$	0.60	$	0.20
	Pro forma	$	0.85	$	0.54	$	0.15

Comprehensive Income

The Company’s comprehensive income is comprised of net income, foreign currency translation adjustments, changes in the unfunded accumulated benefit obligation for the pension plan, unrealized gains and losses on interest rate swap agreements, unrealized gains and losses on derivative commodity instruments and unrealized gains and losses on investments available-for-sale.

Foreign Currency Translation Adjustment

The assets and liabilities of Avista Energy Canada, Ltd. and its subsidiary, Copac Management, Inc., are denominated in Canadian dollars and translated to United States dollars at exchange rates in effect on the balance sheet date. Revenues and expenses are translated using an average exchange rate. Translation adjustments resulting from this process are reflected as a component of other comprehensive income (loss) in the Consolidated Statements of Comprehensive Income.

Earnings Per Common Share

Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share is calculated by dividing income available for common stock by diluted weighted average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options, contingently issuable shares and restricted stock. See Note 23 for earnings per common share calculations.

Cash and Cash Equivalents

For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a purchased maturity of three months or less to be cash equivalents. Cash and cash equivalents include cash

AVISTA CORPORATION

deposits from counterparties. See Note 8 for further information with respect to cash deposits from counterparties.

Restricted Cash

Restricted cash includes bank deposits of $15.0 million and $8.7 million as collateral for letters of credit issued under Avista Energy’s credit agreement as of December 31, 2003 and 2002, respectively. See Note 16 for further information with respect to Avista Energy’s credit agreement. Restricted cash also includes deposits held in trust of $1.5 million and $4.3 million for certain employees of Avista Energy as part of a bonus retention plan as of December 31, 2003 and 2002, respectively.

Securities held for trading

Securities held for trading represent the investment of cash held at Avista Energy in short-term instruments and are recorded at fair value on the Consolidated Balance Sheet with realized and unrealized gains and losses included in the Consolidated Statements of Income. Realized gains, realized losses and net unrealized gains were not material for 2003. The cost basis approximated the fair value of $18.9 million as of December 31, 2003. The Company did not have any securities held for trading during 2002 and 2001.

Allowance for Doubtful Accounts

The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts. The following table documents the activity in the allowance for doubtful accounts during the years ended December 31 (dollars in thousands):


	2003			2002			2001

Allowance as of the beginning of the year	$	46,909		$	50,211		$	14,404
Additions expensed during the year		1,912			3,469			39,947
Net deductions		(2,439	)		(6,771	)		(4,140	)

Allowance as of the end of the year	$	46,382		$	46,909		$	50,211

Inventory

Inventory consists primarily of materials and supplies, fuel stock and natural gas stored. Inventory is recorded at the lower of cost or market, primarily using the average cost method.

Utility Plant in Service

The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of property and improvements, is capitalized. Costs of depreciable units of property retired plus costs of removal less salvage are charged to accumulated depreciation.

Allowance for Funds Used During Construction

The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. In accordance with the uniform system of accounts prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and is credited currently as a non-cash item in the Consolidated Statements of Income in the line item capitalized interest. The Company generally is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a fair return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC generally does not occur until the related utility plant is placed in service and included in rate base.

The effective AFUDC rate was 9.72 percent for 2003 and the second half of 2002 and 9.03 percent for the first half of 2002 and 2001. The Company’s AFUDC rates do not exceed the maximum allowable rates as determined in accordance with the requirements of regulatory authorities.

Depreciation

For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing unit rates for hydroelectric plants and composite rates for other utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. The rates for hydroelectric plants include annuity and interest components, in which the interest component is 9 percent. For utility operations, the ratio of depreciation provisions to average depreciable property was 2.98 percent in 2003, 2.92 percent in 2002 and 2.84 percent in 2001.

AVISTA CORPORATION

The average service lives for the following broad categories of utility property are: electric thermal production - 30 years; hydroelectric production - - 77 years; electric transmission - 41 years; electric distribution - 46 years; and natural gas distribution property - 35 years.

The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense. The Company had estimated retirement costs of $197.7 million and $185.4 million included as a regulatory liability on the Consolidated Balance Sheet as of December 31, 2003 and 2002, respectively. These costs do not represent legal or contractual obligations.

Goodwill

Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a discounted cash flow model on at least an annual basis or more frequently if impairment indicators arise. Goodwill is included in non-utility properties and investments-net on the Consolidated Balance Sheets and totaled $7.5 million ($6.6 million in the Other business segment and $0.9 million in Energy Marketing and Resource Management) and $7.3 million ($6.6 million in the Other business segment and $0.7 million in Energy Marketing and Resource Management) as of December 31, 2003 and 2002 respectively. The level of goodwill as of December 31, 2003 and 2002 was supported by the value attributed to the operations acquired.

On January 1, 2002, the Company adopted a new accounting standard for goodwill, SFAS No. 142, “Goodwill and Other Intangible Assets” that requires that goodwill no longer be amortized. Accordingly, the Company determined that $4.1 million (net of tax) of goodwill was impaired and recorded this as a cumulative effect of accounting change for 2002. Goodwill amortization was $1.8 million, net of taxes, for 2001. Net income and basic and diluted earnings per common share would have been $14.0 million, $0.24 and $0.24, respectively, excluding goodwill amortization for 2001.

Regulatory Deferred Charges and Credits

The Company prepares its consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The Company prepares its financial statements in accordance with SFAS No. 71 because (i) the Company’s rates for regulated services are established by or subject to approval by an independent third-party regulator, (ii) the regulated rates are designed to recover the Company’s cost of providing the regulated services and (iii) in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover the Company’s costs. SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its financial statements. SFAS No. 71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) are reflected as deferred charges on the balance sheet. These costs and/or obligations are not reflected in the statement of income until the period during which matching revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to all or a portion of the Company’s regulated operations, the Company could be required to write off its regulatory assets. The Company could also be precluded from the future deferral of costs not recovered through rates at the time such costs were incurred, even if the Company expected to recover such costs in the future.

The Company’s primary regulatory assets include power and natural gas deferrals (see “Power Cost Deferrals and Recovery Mechanisms” and “Natural Gas Cost Deferrals and Recovery Mechanisms” below for further information), investment in exchange power (see “Investment in Exchange Power-Net” below for further information), regulatory assets for deferred income taxes (see Note 12 for further information), unamortized debt expense (see “Unamortized Debt Expense” below for further information), regulatory asset for consolidation of variable interest entity (see Note 2 for further information), demand side management programs, conservation programs and the provision for postretirement benefits. Those items without a specific line on the Consolidated Balance Sheets are included in other regulatory assets. Other regulatory assets consisted of the following as of December 31 (dollars in thousands):


		2003		2002

Regulatory asset for consolidation of variable interest entity		$	16,707	$	—
Regulatory asset for postretirement benefit obligation			4,255		4,728
Demand side management and conservation programs			19,683		23,733
Other			3,736		1,274

	Total	$	44,381	$	29,735

AVISTA CORPORATION

Regulatory liabilities include utility plant retirement costs. Deferred credits include, among other items, regulatory liabilities created when the Centralia Power Plant (Centralia) was sold, regulatory liabilities offsetting net energy commodity derivative assets (see Note 6 for further information) and the gain on the general office building sale/leaseback, which is being amortized over the life of the lease, and are included on the Consolidated Balance Sheets as other non-current liabilities and deferred credits.

Regulatory assets that are not currently included in rate base, being recovered in current rates or earning a return (accruing interest), totaled $24.3 million as of December 31, 2003. The most significant of these assets was the $16.7 million regulatory asset for the consolidation of a variable interest entity (WP Funding LP) and $5.3 million of demand side management programs. Avista Utilities’ lease payments to WP Funding LP of $4.5 million are being recovered in current rates; the regulatory asset primarily represents the accumulated difference between depreciation expense on the plant and the principal payments made on the debt obligation (see Note 2), which will be reversed in future periods as debt principal payments are made. The balance of the demand side management regulatory asset will be reduced through future recoveries from customers that are more than future amounts expended on such programs.

Investment in Exchange Power-Net

The investment in exchange power represents the Company’s previous investment in Washington Public Power Supply System Project 3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power Administration in 1985, Avista Utilities began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3. Through a settlement agreement with the Washington Utilities and Transportation Commission (WUTC) in the Washington jurisdiction, Avista Utilities is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange power) over a 32.5 year period beginning in 1987. For the Idaho jurisdiction, Avista Utilities has fully amortized the recoverable portion of its investment in exchange power.

Unamortized Debt Expense

Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt, as well as premiums paid to repurchase debt, which are amortized over the average remaining maturity of outstanding debt in accordance with regulatory accounting practices under SFAS No. 71. These costs are recovered through retail rates as a component of interest expense.

Natural Gas Benchmark Mechanism

The Idaho Public Utilities Commission (IPUC), WUTC and Oregon Public Utilities Commission (OPUC) approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations in Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets are managed by Avista Energy through an Agency Agreement. Avista Utilities continues to manage natural gas procurement for its California operations, which currently represents approximately four percent of its total natural gas therm sales.

In accordance with SFAS No. 71, profits recognized by Avista Energy on natural gas sales to Avista Utilities, including gains and losses on natural gas contracts, are not eliminated in the consolidated financial statements. This is due to the fact that Avista Utilities expects to recover the costs of natural gas purchases to serve retail customers and for fuel for electric generation through future retail rates.

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs as approved by the WUTC. Deferred power supply costs are recorded as a deferred charge on the balance sheet for future review and

AVISTA CORPORATION

the opportunity for recovery through retail rates. The power supply costs deferred include certain differences between actual power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in power supply costs primarily results from changes in short-term wholesale market prices, changes in the level of hydroelectric generation and changes in the level of thermal generation (including changes in fuel prices). Avista Utilities accrues interest on deferred power costs in the Washington jurisdiction at a rate, which is adjusted semi-annually, of 8.5 percent as of December 31, 2003. Total deferred power costs for Washington customers were $125.7 million and $123.7 million as of December 31, 2003 and 2002, respectively.

The WUTC issued an order that became effective July 1, 2002 for restructuring of rate increases previously approved by the WUTC totaling 31.2 percent. The July 2002 rate change increased base retail rates 19.3 percent and provided an 11.9 percent continuing surcharge for the recovery of deferred power costs. The WUTC rate order also established an Energy Recovery Mechanism (ERM) effective July 1, 2002. The ERM replaced a series of temporary deferral mechanisms that had been in place in Washington since mid-2000. The ERM allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of annual power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company.

Under the ERM, Avista Utilities makes an annual filing to provide the opportunity for the WUTC and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. Avista Utilities made its first annual filing with the WUTC in March 2003 related to $18.4 million of deferred power costs incurred for the period July 1, 2002 through December 31, 2002. In January 2004, the WUTC approved a settlement agreement among Avista Utilities, the WUTC staff and the Industrial Customers of Northwest Utilities, which provided for Avista Utilities to write off $2.5 million (recorded in 2003) of previously deferred power costs related to the delay of the Coyote Springs 2 project in 2002 and 2003 and allows recovery of all other deferred power costs incurred through December 31, 2002.

Avista Utilities has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the authorized level of net power supply expenses approved in the last Idaho general rate case. Avista Utilities accrues interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 1.0 percent on current year deferrals and 3.0 percent on carryover balances as of December 31, 2003. The IPUC originally approved a 19.4 percent surcharge in October 2001, which has been extended through October 2004 for recovery of previously deferred power costs. Based on IPUC staff recommendations and IPUC orders, the prudence of $11.9 million of deferred power costs will be reviewed in the electric general rate case that Avista Utilities filed in February 2004. Total deferred power costs for Idaho customers were $30.3 million and $31.5 million as of December 31, 2003 and 2002, respectively.

Natural Gas Cost Deferrals and Recovery Mechanisms

Under established regulatory practices in each respective state, Avista Utilities is allowed to adjust its natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs already included in retail rates are deferred and charged or credited to expense when regulators approve inclusion of the cost changes in rates. Total deferred natural gas costs were $15.4 million and $11.5 million as of December 31, 2003 and 2002, respectively.

Intersegment Eliminations

Intersegment eliminations represent the transactions between Avista Utilities and Avista Energy for energy commodities and services, primarily natural gas purchased by Avista Utilities under the Agency Agreement.

Reclassifications

Certain prior period amounts were reclassified to conform to current statement format. These reclassifications were made for comparative purposes and to conform to changes in accounting standards and have not affected previously reported total net income or common equity.

AVISTA CORPORATION

NOTE 2. NEW ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations” which addresses financial accounting and reporting for legal or contractual obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires the recording of the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the associated costs of the asset retirement obligation will be capitalized as part of the carrying amount of the related long-lived asset. The liability will be accreted to its present value each period and the related capitalized costs will be depreciated over the useful life of the related asset. Upon retirement of the asset, the Company will either settle the retirement obligation for its recorded amount or incur a gain or loss. The adoption of this statement on January 1, 2003 did not have a material effect on the Company’s financial condition or results of operations.

The Company recovers certain utility plant retirement costs through rates charged to customers as a component of depreciation expense. To conform to SFAS No. 143, the Company has reclassified $197.7 million and $185.4 million of utility plant retirement costs previously recorded in accumulated depreciation to regulatory liabilities as of December 31, 2003 and 2002, respectively. These costs do not represent legal or contractual obligations.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” which nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” This statement requires that a liability for a cost associated with an exit or disposal activity is recognized when the liability is incurred. Under EITF Issue No. 94-3, a liability for an exit cost was recognized at the date of an entity’s commitment to an exit plan. SFAS No. 146 also requires the initial measurement of the liability at fair value. This statement is effective for exit or disposal activities that were initiated after December 31, 2002. The adoption of this statement did not have any effect on the Company’s financial condition or results of operations.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” which amends SFAS No. 123 “Accounting for Stock-Based Compensation.” This statement provides alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. In addition, this statement requires the disclosure of pro forma net income and earnings per common share had the Company adopted the fair value method of accounting for stock-based compensation in a more prominent place in the financial statements (see Note 1 “Stock-based Compensation”). This statement also requires the disclosure of pro forma net income and earnings per common share in interim as well as annual financial statements. The alternative transition methods and annual financial statement disclosures are effective for fiscal years ending after December 15, 2002. Interim disclosures are required for periods ending after December 15, 2002. The adoption of this statement affects the Company’s disclosures. As the Company has not elected to adopt the fair value method of accounting for stock-based compensation, the adoption of this statement does not have any effect on the Company’s financial condition or results of operations.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends SFAS No. 133 for decisions made: (1) as part of the Derivatives Implementation Group process that effectively required amendments to SFAS No. 133; (2) in connection with other FASB projects dealing with financial instruments; and (3) in connection with implementation issues raised in relation to the application of the definition of a derivative, (in particular, the meaning of an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, the meaning of underlying, and the characteristics of a derivative that contain financing components). This statement is effective for contracts entered into or modified after June 30, 2003, except as stated below and for hedging relationships designated after June 30, 2003. The provisions of SFAS No. 149 that relate to SFAS No. 133 implementation issues that were effective for fiscal quarters that began prior to June 15, 2003 should continue to be applied in accordance with their respective effective dates. In addition, certain provisions relating to forward purchases or sales of “when-issued” securities or other securities that do not yet exist, should be applied to existing contracts as well as new contracts entered into after June 30, 2003. Avista Utilities has entered into certain forward contracts to purchase or sell power and natural gas used for generation that no longer meet the normal purchases and sales exception in accordance with the provisions of SFAS No. 149. This statement requires that substantially all new forward contracts to purchase or sell power and natural gas used for generation, which were entered into on or after July 1, 2003, be recorded as assets or liabilities at market value with an offsetting regulatory asset or liability as authorized by regulatory accounting orders (see Note 6). In accordance with the provisions of

AVISTA CORPORATION

SFAS No. 149, Avista Utilities recorded derivative assets of $1.5 million and derivative liabilities of $0.1 million as of December 31, 2003.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This statement requires the Company to classify certain financial instruments as liabilities that have historically been classified as equity. This statement requires the Company to classify as a liability financial instruments that are subject to mandatory redemption at a specified or determinable date or upon an event that is certain to occur. This statement was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. The restatement of financial statements for prior periods is not permitted. The adoption of this statement required the Company to classify $31.5 million of preferred stock subject to mandatory redemption as liabilities on the Consolidated Balance Sheet. The adoption of this statement also required the Company to classify preferred stock dividends of $1.1 million for the period from July 1, 2003 through December 31, 2003 as interest expense in the Consolidated Statements of Income. The adoption of this statement does not cause the Company to fail to meet any of the covenants of the Company’s $245.0 million committed line of credit, including covenants not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at the end of any fiscal quarter as the covenant calculations exclude the effect of changes in accounting standards.

In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This statement requires expanded disclosures with respect to pension plan assets, benefit obligations, cash flows, benefit costs and other relevant information. However, this statement does not change the measurement and recognition provisions of previous FASB statements related to pensions and other postretirement benefits. The Company was required to adopt this statement for 2003. The adoption of this statement did not have any effect on the Company’s financial condition or results of operations. The expanded disclosures required by this statement are included in Note 11.

Avista Energy accounted for energy commodity trading activity in compliance with EITF Issue No. 98-10 through December 31, 2002 for contracts entered into on or prior to October 25, 2002. Under EITF Issue No. 98-10, Avista Energy recognized revenue based on the change in the market value of outstanding derivative commodity sales contracts, net of future servicing costs and reserves, in addition to revenue related to settled contracts. In October 2002, the EITF rescinded Issue No. 98-10. As such, Avista Energy was required to account for energy trading contracts that meet the definition of a derivative at market value in compliance with SFAS No. 133 as of January 1, 2003. Contracts not meeting the definition of a derivative are no longer accounted for at market value and include Avista Energy’s Agency Agreement with Avista Utilities, natural gas storage contracts, tolling agreements and natural gas transportation agreements. The transition from EITF Issue No. 98-10 to accrual based accounting resulted in the adjustment of the contracts not considered derivatives from their market value to their cost basis. Any gains or losses on contracts that are not considered derivatives are recognized when the contracts are settled or realized. The Company anticipates that the changes will primarily affect the timing of the recognition of income or loss in earnings, and not change the underlying economics or cash flows of transactions entered into by Avista Energy. The transition to SFAS No. 133 increased the volatility in reported earnings due to the fact that certain contracts, which are not considered derivatives, are economically hedged by contracts that are accounted for as derivative instruments at market value under SFAS No. 133. During September 2003, Avista Energy implemented hedge accounting for certain transactions (see Note 7). This should partially mitigate the effects from the transition to SFAS No. 133 and reduce the volatility of reporting earnings on a prospective basis. On January 1, 2003, Avista Energy recorded as a cumulative effect of accounting change a charge of $1.2 million (net of tax) related to the transition from EITF Issue No. 98-10 to SFAS No. 133.

In July 2003, the EITF reached consensus on Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as Defined in EITF Issue No. 02-3.” This EITF Issue requires that revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) should be reported on a net basis as part of operating revenues effective October 1, 2003. Derivatives not held for trading purposes at Avista Energy are reported gross; unless they are “booked out” or the economic substance indicates that net reporting is appropriate. The adoption of this EITF Issue resulted in a reduction in operating revenues and resource costs of approximately $1.2 million for 2003 as compared to historical periods for Avista Utilities. This effect on operating revenues and resource costs will be more significant in 2004 and subsequent years as the netting of “booked out” contracts will be recorded for the entire year.

AVISTA CORPORATION

In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” This interpretation clarifies the requirements of SFAS No. 5, “Accounting for Contingencies” relating to a guarantor’s accounting for, and disclosure of, the issuance of certain types of guarantees. This interpretation requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. The initial recognition and measurement provisions of this interpretation are to be applied on a prospective basis to guarantees issued or modified subsequent to December 31, 2002 and did not have a material effect on the Company’s financial condition or results of operations. The disclosure requirements of this interpretation are effective for financial statements issued for periods that end after December 15, 2002. See Note 19 for disclosure of the Company’s guarantees.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised in December 2003 (collectively referred to as FIN 46). In October 2003, the implementation of FIN 46 was delayed from the third quarter of 2003 to the fourth quarter of 2003. In general, a variable interest entity does not have equity investors with voting rights or it has equity investors that do not provide sufficient financial resources for the entity to support its activities. Variable interest entities are commonly referred to as special purpose entities or off-balance sheet structures; however, FIN 46 applies to a broader group of entities. FIN 46 requires a variable interest entity to be consolidated by the primary beneficiary of that entity. The primary beneficiary is subject to a majority of the risk of loss from the variable interest entity’s activities or it is entitled to receive a majority of the entity’s residual returns. FIN 46 also requires disclosure of variable interest entities that a company is not required to consolidate but in which it has a significant variable interest. The consolidation requirements of FIN 46 applied immediately to variable interest entities created after January 31, 2003 and applied to certain existing variable interest entities for the first fiscal year or interim period ending after December 15, 2003. Application for all other types of entities is required for periods ending after March 15, 2004.

FIN 46 required the Company to consolidate WP Funding LP effective for the period ended December 31, 2003. WP Funding LP is an entity that was formed in 1993 for the purpose of acquiring the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT). WP Funding LP purchased the Rathdrum CT from the Company with funds provided by unrelated investors of which 97 percent represented debt and 3 percent represented equity. The Company operates the Rathdrum CT and leases it from WP Funding LP. The total amount of WP Funding LP debt outstanding was $54.6 million as of December 31, 2003. The lease term expires in February 2020; however, the current debt matures in October 2005 and will need to be refinanced at that time. As of December 31, 2003, the book value of the debt and equity of WP Funding LP exceeded the book value of the Rathdrum CT by $16.7 million. In accordance with regulatory accounting practices, the Company recorded this amount as a regulatory asset upon the consolidation of WP Funding LP. The addition of the Rathdrum CT to Avista Utilities’ generation resource base, which entered commercial operation in 1995, was reviewed in previous state regulatory filings with the WUTC and IPUC. The consolidation of WP Funding LP increased long-term debt by $54.6 million, net utility property by $39.6 million, other regulatory assets by $16.7 million and other liabilities by $1.7 million (representing minority interest) as of December 31, 2003.

FIN 46 also resulted in the Company no longer including Avista Capital I and Avista Capital II in its consolidated financial statements for the period ended December 31, 2003. Avista Capital I and Avista Capital II are business trusts formed in 1997 for the purpose of issuing a combined $110.0 million of preferred trust securities to third parties and $3.4 million of common trust securities to Avista Corp. The sole assets of Avista Capital I and Avista Capital II are $113.4 million of junior subordinated deferrable interest debentures of Avista Corp. Avista Capital I and Avista Capital II are considered variable interest entities under the provisions of FIN 46. As Avista Corp. is not the primary beneficiary, these entities are no longer included in Avista Corp.’s consolidated financial statements. The removal of Avista Capital I and Avista Capital II resulted in a decrease in preferred trust securities of $100.0 million, an increase in long-term debt to affiliated trusts of $113.4 million and an increase in investments in affiliated trusts of $13.4 million (representing the $3.4 million of common trust securities and $10.0 million of preferred trust securities purchased by Avista Corp. in 2000) as of December 31, 2003. Interest expense to affiliated trusts of $1.5 million in the Consolidated Statements of Income for 2003 represents interest expense on the $113.4 million of long-term debt to affiliated trusts for the fourth quarter of 2003.

The adoption FIN 46 does not cause the Company to fail to meet any of the covenants of the Company’s $245.0 million committed line of credit, including covenants not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at the end of any fiscal quarter as the covenant calculations exclude the effect of changes in accounting standards.

AVISTA CORPORATION

Recent FASB staff interpretations of FIN 46 indicate that certain forward contracts, such as tolling agreements, may be variable interests. Depending on these interpretations and the Company’s evaluation of certain contracts, Avista Energy may need to consolidate Rathdrum Power, LLC (RP LLC) in the first quarter of 2004. RP LLC, an unconsolidated entity that is 49 percent owned by Avista Power, operates a 270 MW natural gas-fired combustion turbine plant in northern Idaho (Lancaster Project). All of the output from the Lancaster Project is contracted to Avista Energy through 2026 years under a Power Purchase Agreement. As of December 31, 2003, RP LLC had total assets of $141.0 million, which primarily consisted of net property, plant and equipment of $125.3 million. As of December 31, 2003 RP LLC had $117.2 million of debt outstanding and $19.3 million of shareholders’ equity. There is no recourse to the Company with respect to the debt of RP LLC.

NOTE 3. DISCONTINUED OPERATIONS

In July and September 2003, Avista Corp. announced total investments of $12.2 million by private equity investors in a new entity, AVLB, Inc., which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. As of December 31, 2003, Avista Corp. had an ownership interest of approximately 17.5 percent in AVLB, Inc., with the opportunity but no further obligation to fund or invest in this business. Avista Corp.’s investment in AVLB, Inc. is accounted for under the cost method. Revenues for Avista Labs were $0.5 million, $0.7 million and $0.7 million in 2003 (through June 30), 2002 and 2001, respectively.

In September 2001, the Company reached a decision that it would dispose of substantially all of the assets of Avista Communications. The divestiture of the operating assets of Avista Communications was complete by the end of 2002. Revenues for Avista Communications were $3.5 million and $11.5 million in 2002 and 2001, respectively.

Concurrent with the decision to dispose of Avista Communications, the Company assessed the carrying value of assets and goodwill of Avista Communications. The assets and goodwill of Avista Communications were written down to the estimated fair value based upon the planned disposal of the assets. The total charges of $58.4 million incurred in 2001 were comprised of the following: $48.2 million for asset impairment, $7.1 million for goodwill impairment and $3.1 million for exit costs and other costs to sell Avista Communications.

Amounts reported as discontinued operations for 2003 represent the operations of Avista Labs. Amounts reported as discontinued operations for 2002 and 2001 represents the operations of Avista Labs and Avista Communications as follows:


			Avista Labs			Avista Communications			Total

Year ended December 31, 2002
	Income (loss) before income taxes		$	(12,960	)	$	2,499		$	(10,461	)
	Minority interest			241			—			241
	Income tax benefit (expense)			4,855			(1,354	)		3,501

		Income (loss) from discontinued operations	$	(7,864	)	$	1,145		$	(6,719	)

Year ended December 31, 2001
	Loss before income taxes		$	(15,708	)	$	(21,130	)	$	(36,838	)
	Asset impairment charges			—			(58,417	)		(58,417	)
	Minority interest			873			4,319			5,192
	Income tax benefit			6,199			27,779			33,978

		Loss from discontinued operations	$	(8,636	)	$	(47,449	)	$	(56,085	)

NOTE 4. IMPAIRMENT OF ASSETS

During the fourth quarter of 2003, the Company recorded an impairment related to a turbine owned by Avista Power (Energy Marketing and Resource Management segment). This charge of $4.9 million for 2003 is included in operations and maintenance expense in the Consolidated Statements of Income. The Company originally planned to use four turbines in a non-regulated generation project. Due to changing market conditions during 2001, the Company decided to no longer pursue the development of this project and reached an agreement to sell three of the turbines (see paragraph below). During 2002 and the first three quarters of 2003, the Company explored various options for use of the fourth turbine, primarily for added generation at Avista Utilities. However, during the fourth quarter of 2003, the Company determined these options were not economically feasible and wrote down the carrying value of the turbine to estimated fair value less selling costs.

In 2001, the Company recorded an impairment related to three turbines owned by Avista Power. This resulted in a charge of $8.2 million for 2001 included in other income-net in the Consolidated Statements of Income.

AVISTA CORPORATION

NOTE 5. ACCOUNTS RECEIVABLE SALE

In 1997, Avista Receivables Corp. (ARC) was formed as a wholly owned, bankruptcy-remote subsidiary of the Company for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On May 29, 2002, ARC, the Company and a third-party financial institution entered into a three-year agreement whereby ARC can sell without recourse, on a revolving basis, up to $100.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in operating expenses of the Company. As of December 31, 2003 and 2002, $72.0 million and $65.0 million, respectively, in accounts receivables were sold under this revolving agreement.

NOTE 6. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

SFAS No. 133, as amended by SFAS No. 138, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recording of all derivatives as either assets or liabilities on the balance sheet measured at estimated fair value and the recognition of the unrealized gains and losses. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.

Avista Utilities enters into forward contracts to purchase or sell energy. Under these forward contracts, Avista Utilities commits to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. Certain of these forward contracts are considered derivative instruments. Avista Utilities also records derivative commodity assets and liabilities for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered into as part of Avista Utilities’ management of its loads and resources as discussed in Note 7. In conjunction with the issuance of SFAS No. 133, the WUTC and the IPUC issued accounting orders authorizing Avista Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The order provides for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement subject to current or future recovery in retail rates. Realized gains and losses are reflected as adjustments through purchased gas cost adjustments, the ERM and the PCA mechanism.

Prior to the adoption of SFAS No. 149 on July 1, 2003, Avista Utilities elected the normal purchases and sales exception for substantially all of its contracts for both capacity and energy under SFAS No. 133. As such, Avista Utilities was not required to record these contracts as derivative commodity assets and liabilities. See Note 2 for a discussion of prospective changes that impact the accounting for contracts when entered on or after July 1, 2003, in accordance with SFAS No. 149. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for at cost until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary.

As of December 31, 2003, the utility derivative commodity asset balance was $39.5 million, the derivative commodity liability balance was $36.1 million and the offsetting net regulatory liability was $3.4 million. As of December 31, 2002, the utility derivative commodity asset balance was $60.3 million, the derivative commodity liability balance was $50.1 million and the offsetting net regulatory liability was $10.2 million. Utility derivative assets and liabilities, as well as the offsetting net regulatory asset or liability, can change significantly from period to period due to the settlement of contracts, the entering of new contracts and changes in commodity prices. The offsetting net regulatory liability is included in other non-current liabilities and deferred credits on the Consolidated Balance Sheet.

NOTE 7. ENERGY COMMODITY TRADING

The Company’s energy-related businesses are exposed to risks relating to, but not limited to, changes in certain commodity prices, interest rates, foreign currency and counterparty performance. In order to manage the various risks relating to these exposures, Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options, and Avista Energy engages in the trading of such instruments. Avista Utilities and Avista Energy use a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative, for

AVISTA CORPORATION

Avista Utilities and Avista Energy. The Company’s Risk Management Committee, which is separate from the units tasked with managing this risk exposure and is overseen by the Audit Committee of the Company’s Board of Directors, monitors compliance with the Company’s risk management policies and procedures.

Avista Utilities

Avista Utilities manages the impact of fluctuations in electric energy prices by establishing volume limits for the imbalance between projected loads and resources and through the use of derivative commodity instruments for hedging purposes. Any load/resource imbalances within a rolling 18-month planning horizon are managed within risk policy volumetric limits. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods. Avista Energy is responsible for the daily management of natural gas supplies to meet the requirements of Avista Utilities’ customers in the states of Washington, Idaho and Oregon. In February 2004, the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers (see description of Natural Gas Benchmark Mechanism in Note 1). Avista Utilities continues to manage natural gas procurement for its California operations, which currently represents approximately four percent of its total natural gas therm sales.

Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business. Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric and natural gas transmission and transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy purchases natural gas and electricity from producers and energy marketing and trading companies. Its customers include commercial and industrial end-users, electric utilities, natural gas distribution companies, and energy marketing and trading companies.

Avista Energy’s marketing and energy risk management services are provided through the use of a variety of derivative commodity contracts to purchase or supply natural gas and electric energy at specified delivery points and at specified future dates. Avista Energy trades natural gas and electricity derivative commodity instruments on national exchanges and through other exchanges and brokers, and therefore can experience net open positions in terms of price, volume, and specified delivery point. The open positions expose Avista Energy to the risk that fluctuating market prices may adversely impact its financial condition or results of operations. However, the net open position is actively managed with strict policies designed to limit the exposure to market risk and requiring daily reporting to management of potential financial exposure.

AVISTA CORPORATION

Derivative commodity instruments sold and purchased by Avista Energy include: forward contracts, which involve physical delivery of an energy commodity; futures contracts, which involve the buying or selling of natural gas or electricity at a fixed price; over-the-counter swap agreements, which require Avista Energy to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity; and options, which mitigate price risk by providing for the right, but not the requirement, to buy or sell energy-related commodities at a fixed price. Foreign currency risks are primarily related to Canadian exchange rates and are managed using standard instruments available in the foreign currency markets.

Avista Energy’s derivative commodity instruments accounted for under SFAS No. 133 are subject to mark-to-market accounting, under which changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as unrealized gains or losses in the period of change. Market prices are utilized in determining the value of the electric, natural gas and related derivative commodity instruments. For electric derivative commodity instruments, these market prices are generally available through two years. For natural gas derivative commodity instruments, these market prices are generally available through three years. For longer-term positions and certain short-term positions for which market prices are not available, a model to estimate forward price curves is utilized. Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts, which are not accounted for as derivatives under SFAS No. 133 and derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Costs from contracts, which are not accounted for as derivatives under SFAS No. 133 and derivative instruments not held for trading, are reported on a gross basis in resource costs. Contracts in a receivable position, as well as the options held, are reported as assets. Similarly, contracts in a payable position, as well as options written, are reported as liabilities. Net cash flows are recognized in the period of settlement.

During 2003, a gain of less than $0.1 million related to hedge ineffectiveness was recorded in earnings as operating revenues. As of December 31, 2003, there was a gain of $1.8 million (net of tax) in accumulated other comprehensive income (loss) related to designated cash flow hedges, while a gain of $0.5 million (net of tax) was reclassified from accumulated comprehensive income (loss) and recognized in earnings during 2003. Of the amount in accumulated other comprehensive income (loss) as of December 31, 2003, Avista Energy expects to recognize $1.7 million in earnings during the next 12 months. The actual amounts that will be recognized in earnings during the next 12 months will vary from the expected amounts as a result of changes in market prices. The maximum term of the designated hedging instruments was 15 months.

Contract Amounts and Terms Under Avista Energy’s derivative instruments, Avista Energy either (i) as “fixed price payor,” is obligated to pay a fixed price or a fixed amount and is entitled to receive the commodity or a fixed amount or (ii) as “fixed price receiver,” is entitled to receive a fixed price or a fixed amount and is obligated to deliver the commodity or pay a fixed amount or (iii) as “index price payor,” is obligated to pay an indexed price or an indexed amount and is entitled to receive the commodity or a variable amount or (iv) as “index price receiver,” is entitled to receive an indexed price or amount and is obligated to deliver the commodity or pay a variable amount.

AVISTA CORPORATION

The contract or notional amounts and terms of Avista Energy’s derivative commodity instruments outstanding as of December 31, 2003 are set forth below (in thousands of mmBTUs and MWhs):

Fixed

Maximum

Index

Maximum

Price

Terms in

Price

Terms in

Payor

Receiver

Years

Payor

Receiver

Years

Energy commodities (volumes)

Electric

41,975

43,524

113

402

Natural gas

159,207

140,548

1,061,402

1,050,424

The weighted average term of Avista Energy’s electric derivative commodity instruments as of December 31, 2003 was approximately 9 months. The weighted average term of Avista Energy’s natural gas derivative commodity instruments as of December 31, 2003 was approximately 4 months.

Estimated Fair Value The estimated fair value of Avista Energy’s derivative commodity instruments outstanding as of December 31, 2003, and the average estimated fair value of those instruments held during the year ended December 31, 2003, are set forth below (dollars in thousands):


Estimated Fair Value									Average Estimated Fair Value for the
as of December 31, 2003									year ended December 31, 2003

	Current		Long-term		Current		Long-term		Current		Long-term		Current		Long-term
	Assets		Assets		Liabilities		Liabilities		Assets		Assets		Liabilities		Liabilities

Electric	$	134,454	$	226,086	$	112,105	$	184,862	$	241,426	$	295,949	$	219,915	$	261,737
Natural gas		119,222		16,273		117,537		7,869		94,037		14,621		71,909		11,220

Total	$	253,676	$	242,359	$	229,642	$	192,731	$	335,463	$	310,570	$	291,824	$	272,957

The change in the estimated fair value position of Avista Energy’s energy commodity portfolio, net of reserves for credit and market risk for 2003 was an unrealized loss of $22.1 million and is included in the Consolidated Statements of Income in operating revenues. The change in the fair value position for 2002 was an unrealized loss of $91.9 million. In 2001, the unrealized loss was $30.2 million.

Market Risk

Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Market risk is influenced to the extent that the performance or nonperformance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity.

Avista Utilities and Avista Energy manage, on a portfolio basis and on a delivery point basis, the market risks inherent in their activities subject to parameters established by the Company’s Risk Management Committee. These parameters include but are not limited to overall portfolio and delivery point volumetric limits. Market risks are monitored by the Risk Management Committee to ensure compliance with the Company’s risk management policies. Avista Utilities measures exposure to market risk through daily evaluation of the imbalance between projected loads and resources. Avista Energy measures the risk in its portfolio on a daily basis utilizing a VAR model and monitors its risk in comparison to established thresholds.

Credit Risk

Credit risk relates to the risk of loss that Avista Utilities and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy and make financial settlements. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it and the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Avista Utilities and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by actively monitoring current credit exposures. These policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees, and the use of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty.

AVISTA CORPORATION

Credit risk also involves the exposure that counterparties perceive related to the ability of Avista Utilities and Avista Energy to perform deliveries and settlement of energy transactions. These counterparties may seek assurance of performance in the form of letters of credit, prepayment or cash deposits and, in the case of Avista Energy, parent company (Avista Capital) performance guarantees. In periods of price volatility, the level of exposure can change significantly, with the result that sudden and significant demands may be made against the Company’s capital resource reserves (credit facilities and cash). Avista Utilities and Avista Energy actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

Other Operating Risks

In addition to commodity price risk, Avista Utilities’ commodity positions are subject to operational and event risks including, among others, increases in load demand, transmission or transport disruptions, fuel quality specifications, changes in regulatory requirements, forced outages at generating plants and disruptions to information systems and other administrative tools required for normal operations. Avista Utilities also has exposure to weather conditions and natural disasters that can cause physical damage to property, requiring repairs to restore utility service. The emergence of terrorism threats, both domestic and foreign, is a risk to the entire utility industry, including Avista Utilities. Potential disruptions to operations or destruction of facilities from terrorism or other malicious acts are not readily determinable. The Company has taken various steps to mitigate terrorism risks and to prepare contingency plans in the event that its facilities are targeted.

NOTE 8. CASH DEPOSITS WITH AND FROM COUNTERPARTIES

Cash deposits from counterparties totaled $97.8 million and $92.7 million as of December 31, 2003 and 2002, respectively, and are disclosed as deposits from counterparties on the Consolidated Balance Sheet. These funds are held by Avista Utilities and Avista Energy to mitigate the potential impact of counterparty default risk. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of non-cash collateral.

Cash deposited with counterparties totaled $36.8 million and $35.7 million as of December 31, 2003 and 2002, respectively, and is included in prepayments and other current assets on the Consolidated Balance Sheet.

As is common industry practice, Avista Utilities and Avista Energy maintain margin agreements with certain counterparties. Margin calls are triggered when exposures exceed predetermined contractual limits or when there are changes in a counterparty’s creditworthiness. Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. From time to time, margin calls are made and/or received by Avista Utilities and Avista Energy. Negotiating for collateral in the form of cash, letters of credit, or parent company performance guarantees is a common industry practice.

NOTE 9. JOINTLY OWNED ELECTRIC FACILITIES

The Company has a 50 percent ownership interest in a combined cycle natural gas-fired turbine power plant, the Coyote Springs 2 Generation Plant (Coyote Springs 2) located in north-central Oregon, which was placed into operation in 2003. The Company’s investment in Coyote Springs 2 was held by Avista Power as of December 31, 2002 and was included in non-utility properties and investments-net on the Consolidated Balance Sheet. In January 2003, the Company’s ownership interest in the plant was transferred from Avista Power to Avista Corp. to be operated as an asset of Avista Utilities and was included in utility plant in service on the Consolidated Balance Sheet as of December 31, 2003. The Company’s share of related fuel costs as well as operating and maintenance expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Coyote Springs 2 was $109.0 million and accumulated depreciation was $2.2 million as of December 31, 2003.

The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, the Colstrip

AVISTA CORPORATION

Generating Project (Colstrip) located in southeastern Montana, and provides financing for its ownership interest in the project. The Company’s share of related fuel costs as well as operating and maintenance expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Colstrip was $323.6 million and accumulated depreciation was $167.6 million as of December 31, 2003.

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

The balances of the major classifications of property, plant and equipment are detailed in the following table as of December 31 (dollars in thousands):


				2003		2002

Avista Utilities:
	Electric production			$	914,021	$	740,736
	Electric transmission				304,827		295,284
	Electric distribution				724,054		698,757
	Construction work-in-progress (CWIP) and other				119,552		85,631

		Electric total			2,062,454		1,820,408

	Natural gas underground storage				18,543		18,285
	Natural gas distribution				449,501		430,273
	CWIP and other				45,340		44,675

		Natural gas total			513,384		493,233

	Common plant (including CWIP)				79,789		74,751

	Total Avista Utilities				2,655,627		2,388,392
Energy Marketing and Resource Management					30,162		142,428
Avista Advantage					12,847		10,183
Other					23,886		20,611

			Total	$	2,722,522	$	2,561,614

Equipment under capital leases at Avista Utilities totaled $3.9 million and $0.7 million as of December 31, 2003 and 2002, respectively. The associated accumulated depreciation totaled $0.2 million and $0.1 million as of December 31, 2003 and 2002, respectively. Property, plant, and equipment under capital leases at Avista Capital’s subsidiaries totaled $5.3 million and $3.3 million as of December 31, 2003 and 2002, respectively. The associated accumulated depreciation totaled $2.9 million and $2.1 million as of December 31, 2003 and 2002, respectively.

NOTE 11. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

Pension fund assets are invested primarily in marketable debt and equity securities. However, fund assets may also be invested in real estate and other investments, including hedge funds and venture capital funds. In selecting an assumed long-term rate of return on plan assets, the Company considered past performance and economic forecasts for the types of investments held by the plan. The fair value of pension plan assets invested in debt and equity securities was based primarily on outside market prices. The fair value of pension plan assets invested in real estate was determined based on three basic approaches: (1) current cost of reproducing a property less deterioration and functional economic obsolescence (2) capitalization of the property’s net earnings power; and (3) value indicated by recent sales of comparable properties in the market. The fair value of plan assets was determined as of December 31, 2003 and 2002.

As of December 31, 2003 and 2002, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. In 2003, the pension plan funding deficit was reduced as compared to the end of 2002 and as such the Company reduced the additional minimum liability for the unfunded accumulated benefit obligation by $15.5 million and the intangible asset by $0.6 million (representing the

AVISTA CORPORATION

amount of unrecognized prior service cost) related to the pension plan. This resulted in an increase to other comprehensive income of $9.7 million, net of taxes of $5.2 million for 2003. In 2002, the Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $33.4 million and an intangible asset of $6.4 million (representing the amount of unrecognized prior service cost) related to the pension plan. This resulted in a charge to other comprehensive income of $17.6 million, net of taxes of $9.4 million for 2002.

The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $0.3 million, $0.7 million and $1.1 million related to the SERP for 2003, 2002 and 2001, respectively. This resulted in a charge to other comprehensive income of $0.2 million, $0.5 million and $0.7 million, net of taxes, for 2003, 2002 and 2001, respectively.

The Company uses a December 31 measurement date for its pension and postretirement plans. The following table sets forth the pension and postretirement plan disclosures as of December 31, 2003 and 2002 and the components of net periodic benefit costs for the years ended December 31, 2003, 2002 and 2001 (dollars in thousands):


								Post-
		Pension Benefits						retirement Benefits

		2003			2002			2003			2002

Change in benefit obligation:
Benefit obligation as of beginning of year		$	238,385		$	210,510		$	29,062		$	36,355
Service cost			7,806			6,734			482			304
Interest cost			15,705			15,119			2,477			2,184
Plan amendment			—			(2,530	)		—			(5,821	)
Actuarial loss (gain)			18,046			22,243			10,973			(660	)
Benefits paid			(12,648	)		(12,229	)		(3,741	)		(3,091	)
Expenses paid			(1,504	)		(1,462	)		(68	)		(209	)

Benefit obligation as of end of year		$	265,790		$	238,385		$	39,185		$	29,062

Change in plan assets:
Fair value of plan assets as of beginning of year		$	136,125		$	153,705		$	11,301		$	13,969
Actual return on plan assets			33,129			(16,677	)		3,282			(1,451	)
Employer contributions			12,000			12,000			1,785			—
Benefits paid			(11,788	)		(11,441	)		(1,713	)		(1,008	)
Expenses paid			(1,504	)		(1,462	)		(68	)		(209	)

Fair value of plan assets as of end of year		$	167,962		$	136,125		$	14,587		$	11,301

Funded status		$	(97,828	)	$	(102,260	)	$	(24,598	)	$	(17,761	)
Unrecognized net actuarial loss			71,695			79,812			9,455			1,425
Unrecognized prior service cost			5,712			6,366			—			—
Unrecognized net transition obligation/(asset)			(1,585	)		(2,671	)		8,809			9,788

Accrued benefit cost			(22,006	)		(18,753	)		(6,334	)		(6,548	)
Additional minimum liability			(20,081	)		(35,303	)		—			—

Accrued benefit liability		$	(42,087	)	$	(54,056	)	$	(6,334	)	$	(6,548	)

Accumulated pension benefit obligation		$	210,049		$	190,181			—			—
Accumulated postretirement benefit obligation:
	For retirees							$	26,073		$	21,582
	For fully eligible employees							$	5,427		$	3,297
	For other participants							$	7,685		$	4,183
Weighted-average asset allocations as of December 31
Equity securities			64	%		65	%		59	%		51	%
Debt securities			25	%		32	%		41	%		38	%
Real estate			5	%		—			—			—
Other			6	%		3	%		—			11	%

AVISTA CORPORATION


							Post-
	Pension Benefits						retirement Benefits

	2003			2002			2003			2002

Target asset allocations as of December 31
Equity securities		54-68	%		58-72	%
Debt securities		22-28	%		25-35	%
Real estate		3-7	%		—
Other		5-13	%		3-5	%
Assumptions as of December 31
Discount rate		6.25	%		6.75	%		6.25	%		6.75	%
Expected long-term return on plan assets		8.00	%		8.00	%		8.00	%		8.00	%
Rate of compensation increase		5.00	%		5.00	%
Medical cost trend pre-age 65 - initial								9.00	%		9.00	%
Medical cost trend pre-age 65 - ultimate								5.00	%		5.00	%
Ultimate medical cost trend year pre-age 65								2007			2007
Medical cost trend post-age 65 - initial								10.00	%		10.00	%
Medical cost trend post-age 65 - ultimate								6.00	%		6.00	%
Ultimate medical cost trend year post-age 65								2007			2007


	2003			2002			2001			2003			2002			2001

Components of net periodic benefit cost:
Service cost	$	7,806		$	6,734		$	5,716		$	482		$	304		$	460
Interest cost		15,705			15,119			14,293			2,477			2,184			2,567
Expected return on plan assets		(10,862	)		(12,311	)		(15,254	)		(842	)		(1,064	)		(1,311	)
Transition (asset)/obligation recognition		(1,086	)		(1,086	)		(1,086	)		979			1,256			1,534
Amortization of prior service cost		653			831			989			—			—			—
Net (gain) loss recognition		3,896			1,021			139			405			—			(52	)

Net periodic benefit cost	$	16,112		$	10,308		$	4,797		$	3,501		$	2,680		$	3,198

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2003 by $3.0 million and the service and interest cost by $0.2 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2003 by $2.6 million and the service and interest cost by $0.2 million.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act) was signed into law. The 2003 Medicare Act expanded Medicare to include, for the first time, coverage for prescription drugs. The Company expects that the 2003 Medicare Act may eventually reduce the costs of postretirement medical benefits. Because of various uncertainties related to the Company’s response to the 2003 Medicare Act and the appropriate accounting for this event, the Company has elected to defer financial recognition of this legislation until the FASB issues final accounting guidance.

The Company has a salary deferral 401(k) plan (Employee Investment Plan) that is a defined contribution plan and covers substantially all employees. Employees can make contributions to their respective accounts in the Employee Investment Plan on a pre-tax basis up to the maximum amount permitted by law. The Company matches a portion of the salary deferred by each participant according to the schedule in the Employee Investment Plan. Employer matching contributions of $3.6 million, $3.4 million and $3.5 million were expensed in 2003, 2002 and 2001, respectively.

NOTE 12. ACCOUNTING FOR INCOME TAXES

As of December 31, 2003 and 2002, the Company had net regulatory assets of $131.8 million and $139.1 million, respectively, related to the probable recovery of certain deferred tax liabilities from customers through future rates.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards.

AVISTA CORPORATION

The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands):


				2003		2002

Deferred income tax assets:
	Allowance for doubtful accounts			$	16,201	$	16,343
	Reserves not currently deductible				23,669		15,750
	Contributions in aid of construction				8,677		9,709
	Deferred compensation				4,904		4,112
	Centralia sale regulatory liability				2,336		2,954
	Unfunded accumulated benefit obligation				4,645		9,736
	Other				5,705		7,172

		Total deferred income tax assets			66,137		65,776

Deferred income tax liabilities:
	Differences between book and tax basis of utility plant				404,017		364,827
	Power and natural gas deferrals				58,912		58,081
	Unrealized energy commodity gains				27,290		34,231
	Power exchange contract				41,725		44,533
	Demand side management programs				4,459		5,064
	Loss on reacquired debt				8,405		8,781
	Other				2,673		4,406

			Total deferred income tax liabilities		547,481		519,923

	Net deferred income tax liability			$	481,344	$	454,147

Net current deferred income taxes were an $11.5 million asset and a $1.7 million liability as of December 31, 2003 and 2002, respectively. Net non-current deferred tax liabilities were $492.8 million and $452.5 million as of December 31, 2003 and 2002, respectively.

The realization of deferred tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred tax assets and determined it is more likely than not that deferred tax assets will be realized.

A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2003, 2002 and 2001) applied to pre-tax income from continuing operations as set forth in the accompanying Consolidated Statements of Income is as follows for the years ended December 31 (dollars in thousands):


			2003			2002			2001

Federal income taxes at statutory rates			$	30,094		$	26,958		$	38,089
Increase (decrease) in tax resulting from:
	Accelerated tax depreciation			4,046			5,166			5,849
	State income tax expense			1,283			2,348			(8,870	)
	Prior year audit adjustments			457			—			(395	)
	Other-net			(540	)		377			5,912

Total income tax expense			$	35,340		$	34,849		$	40,585

Income Tax Expense Consisted of the Following:
		Federal taxes currently provided	$	6,945		$	75,136		$	(38,556	)
		Deferred federal income taxes		28,395			(40,287	)		79,141

Total income tax expense			$	35,340		$	34,849		$	40,585

Income Tax Expense by Business Segment:
		Avista Utilities	$	26,884		$	32,137		$	20,177
		Energy Marketing and Resource Management		11,457			12,311			32,489
		Avista Advantage		(718	)		(2,289	)		(5,778	)
		Other		(2,283	)		(7,310	)		(6,303	)

Total income tax expense			$	35,340		$	34,849		$	40,585

AVISTA CORPORATION

NOTE 13. ENERGY PURCHASE CONTRACTS

Avista Utilities has contracts related to the purchase of fuel for thermal generation, natural gas and hydroelectric power. The termination dates of the contracts range from one month to the year 2044. Avista Utilities also has various agreements for the purchase, sale or exchange of electric energy with other utilities, cogenerators, small power producers and government agencies. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in resource costs in the Consolidated Statements of Income, were $464.1 million, $382.4 million and $1,054.2 million in 2003, 2002 and 2001, respectively.

The following table details future contractual commitments for power resources (including transmission contracts) and natural gas resources (including transportation contracts) (dollars in thousands):


	2004		2005		2006		2007		2008		Thereafter		Total

Power resources	$	156,729	$	90,379	$	90,124	$	92,203	$	91,788	$	439,079	$	960,302
Natural gas resources		183,207		76,593		49,375		49,872		43,421		355,856		758,324

Total	$	339,936	$	166,972	$	139,499	$	142,075	$	135,209	$	794,935	$	1,718,626

All of the energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail natural gas and electric customers’ energy requirements. As a result, these costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms.

In addition, Avista Utilities has operational agreements, settlements and other contractual obligations with respect to its generation, transmission and distribution facilities. The expenses associated with these agreements are reflected as operations and maintenance expenses in the Consolidated Statements of Income. The following table details future contractual commitments with respect to these agreements (dollars in thousands):


	2004		2005		2006		2007		2008		Thereafter		Total

Contractual obligations	$	12,417	$	12,417	$	12,417	$	12,417	$	12,417	$	173,870	$	235,955

Avista Utilities has fixed contracts with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating facilities. Although Avista Utilities has no investment in the PUD generating facilities, the fixed contracts obligate Avista Utilities to pay certain minimum amounts (based in part on the debt service requirements of the PUD) whether or not the facility is operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in resource costs in the Consolidated Statements of Income. Expenses under these PUD contracts were $8.5 million, $7.8 million and $7.4 million in 2003, 2002 and 2001, respectively.

Information as of December 31, 2003, pertaining to these PUD contracts is summarized in the following table (dollars in thousands):


			Company’s Current Share of

										Debt				Expira-
						Kilowatt		Annual		Service		Bonds		tion
			Output			Capability		Costs (1)		Costs (1)		Outstanding		Date

Chelan County PUD:
	Rocky Reach Project			2.9	%		37,000	$	2,222	$	1,405	$	3,441		2011
Douglas County PUD:
	Wells Project			3.5			30,000		1,168		550		4,966		2018
Grant County PUD:
	Priest Rapids Project			6.1			55,000		1,992		798		11,265		2040
	Wanapum Project			8.2			75,000		3,139		1,587		15,290		2040

		Totals					197,000	$	8,521	$	4,340	$	34,962

(1)

The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts represent the operating costs for the year 2003. Debt service costs are included in annual costs.

AVISTA CORPORATION

The estimated aggregate amounts of required minimum payments (Avista Utilities’ share of existing debt service costs) under these PUD contracts are as follows (dollars in thousands):


	2004		2005		2006		2007		2008		Thereafter		Total

Minimum payments	$	3,351	$	3,665	$	2,845	$	3,310	$	3,172	$	22,758	$	39,101

In addition, Avista Utilities will be required to pay its proportionate share of the variable operating expenses of these projects.

Avista Energy has commitments to purchase physical energy commodities in future periods. The following table details future commitments for Avista Energy’s physical energy contracts (dollars in thousands):


	2004		2005		2006		2007		2008		Thereafter		Total

Physical contracts	$	862,969	$	272,683	$	237,506	$	174,653	$	187,083	$	666,799	$	2,401,693

Avista Energy also has sales commitments related to energy commodities in future periods.

NOTE 14. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of December 31 (dollars in thousands):


Maturity				Interest
Year		Description		Rate			2003			2002

	2003	Secured Medium-Term Notes			6.25	%	$	—		$	15,000
	2005	Secured Medium-Term Notes			6.39%-6.68	%		29,500			29,500
	2005	WP Funding LP Note			8.36	%		54,572	(1)		—
	2006	Secured Medium-Term Notes			7.89%-7.90	%		30,000			30,000
	2007	First Mortgage Bonds			7.75	%		150,000			150,000
	2008	Secured Medium-Term Notes			6.89%-6.95	%		20,000			20,000
	2010	Secured Medium-Term Notes			6.67%-6.90	%		10,000			10,000
	2012	Secured Medium-Term Notes			7.37	%		7,000			7,000
	2013	First Mortgage Bonds			6.13	%		45,000			—
	2018	Secured Medium-Term Notes			7.26%-7.45	%		27,500			27,500
	2023	Secured Medium-Term Notes			7.18%-7.54	%		24,500			24,500

			Total secured long-term debt					398,072			313,500

	2003	Unsecured Medium-Term Notes			6.75%-9.13	%		—			56,250
	2004	Unsecured Medium-Term Notes			7.42	%		28,500			30,000
	2006	Unsecured Medium-Term Notes			8.14	%		8,000			8,000
	2007	Unsecured Medium-Term Notes			5.99%-7.94	%		25,850			26,000
	2008	Senior Notes			9.75	%		317,683			341,529
	2008	Unsecured Medium-Term Notes			6.06	%		25,000			25,000
	2010	Unsecured Medium-Term Notes			8.02	%		25,000			25,000
	2012	Unsecured Medium-Term Notes			8.05	%		—			12,000
	2022	Unsecured Medium-Term Notes			8.15%-8.23	%		5,000			10,000
	2023	Unsecured Medium-Term Notes			7.99	%		5,000			5,000
	2023	Pollution Control Bonds			6.00	%		4,100			4,100
	2028	Unsecured Medium-Term Notes			6.37%-6.88	%		25,000			35,000
	2032	Pollution Control Bonds			5.00	%		66,700			66,700
	2034	Pollution Control Bonds			5.13	%		17,000			17,000

			Total unsecured long-term debt					552,833			661,579

			Capital lease obligations					5,812			1,613

			Unamortized debt discount					(1,994	)		(2,161	)

			Total					954,723			974,531
			Current portion of long-term debt					(29,711	)		(71,896	)

			Total long-term debt				$	925,012		$	902,635

(1)

As discussed in Note 2, represents the long-term debt of WP Funding LP, an entity that was consolidated in 2003 under FIN 46.

AVISTA CORPORATION

The following table details future long-term debt maturities, including long-term debt to affiliated trusts (see Note 15) (dollars in thousands):


Year	2004		2005		2006		2007		2008		Thereafter		Total

Debt maturities	$	28,500	$	84,072	$	38,000	$	175,850	$	362,683	$	375,203	$	1,064,308

In addition to the required maturities documented in the table above, the Company has sinking fund requirements of $3.4 million in each of 2004 and 2005, $3.1 million in 2006, $2.8 million in 2007 and $1.3 million in 2008. Under its Mortgage and Deed of Trust, the Company’s sinking fund requirements may be met by certification of property additions at the rate of 143 percent of requirements. All of the Company’s utility plant is subject to the lien of the Mortgage and Deed of Trust securing outstanding First Mortgage Bonds.

In September 2003, the Company issued $45.0 million of 6.125 percent First Mortgage Bonds due in 2013. The proceeds were used to repay a portion of the borrowings under the $245.0 million line of credit that were used on an interim basis to fund $46.0 million of maturing 9.125 percent Unsecured Medium-Term Notes.

In September 1999, $83.7 million of Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project), Series 1999A due 2032 and Series 1999B due 2034 were issued by the City of Forsyth, Montana. The proceeds of the bonds were utilized to refund the $66.7 million of 7.13 percent First Mortgage Bonds due 2013 and the $17.0 million of 7.40 percent First Mortgage Bonds due 2016. The Series 1999A and Series 1999B Bonds are backed by an insurance policy issued by AMBAC Assurance Corporation. In January 2002, the interest rate on the bonds was fixed for a period of seven years at a rate of 5.00 percent for Series 1999A and 5.13 percent for Series 1999B.

The following table details the Company’s debt repurchases prior to scheduled maturity during 2003 (dollars in thousands):


Repurchase			Interest			Maturity		Principal
Date	Description		Rate			Year		Amount

January 2003	Unsecured Senior Notes			9.75	%		2008	$	10,000
February 2003	Unsecured Senior Notes			9.75	%		2008		505
March 2003	Unsecured Medium-Term Notes			8.23	%		2022		5,000
April 2003	Unsecured Medium-Term Notes			6.88	%		2028		10,000
May 2003	Unsecured Medium-Term Notes			5.99	%		2007		150
June 2003	Unsecured Medium-Term Notes			7.42	%		2004		1,500
July 2003	Unsecured Medium-Term Notes			8.05	%		2012		12,000
July 2003	Unsecured Senior Notes			9.75	%		2008		3,000
August 2003	Unsecured Senior Notes			9.75	%		2008		10,330

		Total debt repurchases						$	52,485

In accordance with regulatory accounting practices, the total net premium on the repurchase of debt of $1.7 million will be amortized over the average remaining maturity of outstanding debt.

As of December 31, 2003, the Company had remaining authorization to issue up to $176.0 million of Unsecured Medium-Term Notes. The Company also has $105.0 million of either secured or unsecured debt remaining under a registration statement filed on Form S-3 with the Securities and Exchange Commission in June 2003.

The Mortgage and Deed of Trust securing the Company’s First Mortgage Bonds contains limitations on the amount of First Mortgage Bonds, which may be issued based on, among other things, a 70 percent debt-to-collateral ratio, and/or retired First Mortgage Bonds, and a 2.00 to 1 net earnings to First Mortgage Bond interest ratio. Under various financing agreements, the Company is also restricted as to the amount of additional First Mortgage Bonds that it can issue. As of December 31, 2003, the Company could issue $93.1 million of additional First Mortgage Bonds under the most restrictive of these financing agreements.

AVISTA CORPORATION

NOTE 15. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 1997, the Company issued 7.875 percent Junior Subordinated Deferrable Interest Debentures, Series A, with a principal amount of $61.9 million to Avista Capital I, a business trust. Avista Capital I issued $60.0 million of Preferred Trust Securities with an annual distribution rate of 7.875 percent. Concurrent with the issuance of the Preferred Trust Securities, Avista Capital I issued $1.9 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital I on or after January 15, 2002 and mature January 15, 2037; however, this is limited by an agreement under the Company’s 9.75 percent Senior Notes that mature in 2008.

In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, a business trust. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The annual distribution rate paid during 2003 ranged from 2.02 percent to 2.30 percent. As of December 31, 2003, the annual distribution rate was 2.02 percent. Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II on or after June 1, 2007 and mature June 1, 2037; however, this is limited by an agreement under the Company’s 9.75 percent Senior Notes that mature in 2008. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.

The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount with respect to, the Preferred Trust Securities to the extent that Avista Capital I and Avista Capital II have funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Trust Securities will be mandatorily redeemed. As discussed in Note 2, FIN 46 results in the Company no longer including Avista Capital I and Avista Capital II in its consolidated financial statements as of December 31, 2003.

NOTE 16. SHORT-TERM BORROWINGS

The committed line of credit agreement contains customary covenants and default provisions, including covenants not to permit the ratio of “consolidated total debt” (not including preferred stock, long-term debt to affiliated trusts or WP Funding LP debt) to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at the end of any fiscal quarter. As of December 31, 2003, the Company was in compliance with this covenant with a ratio of 52.6 percent. The committed line of credit also has a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the twelve-month period ending December 31, 2003 to be greater than 1.6 to 1. As of December 31, 2003, the Company was in compliance with this covenant with a ratio of 2.3 to 1. The covenant calculations exclude the effect of changes in accounting standards.

The Company had a commercial paper program that also provided for fixed-term loans during 2001. None of these arrangements were in place as of December 31, 2003 and 2002.

AVISTA CORPORATION

Balances and interest rates of bank borrowings under these arrangements were as follows as of and for the years ended December 31 (dollars in thousands):


		2003			2002			2001

Balance outstanding at end of period:
	Commercial paper	$	—		$	—		$	—
	Revolving credit agreement		80,000			30,000			55,000
Maximum balance outstanding during the period:
	Commercial paper	$	—		$	—		$	11,160
	Revolving credit agreement		85,000			90,000			223,000
Average balance outstanding during the period:
	Commercial paper	$	—		$	—		$	558
	Revolving credit agreement		26,304			47,027			108,996
Average interest rate during the period:
	Commercial paper		—	%		—	%		7.80	%
	Revolving credit agreement		2.99			3.59			5.95
Average interest rate at end of period:
	Commercial paper		—	%		—	%		—	%
	Revolving credit agreement		3.70			3.39			5.42

On July 25, 2003, Avista Energy and its subsidiary, Avista Energy Canada, Ltd., as co-borrowers, entered into a committed credit agreement with a group of banks in the aggregate amount of $110.0 million expiring July 23, 2004, replacing a previous uncommitted credit agreement that had an extended expiration date of July 31, 2003. This new committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties. This facility is guaranteed by Avista Capital and secured by Avista Energy’s assets. The maximum amount of credit extended by the banks for the issuance of letters of credit is the subscribed amount of the facility less the amount of outstanding cash advances, if any. The maximum amount of credit extended by the banks for cash advances is $30.0 million. No cash advances were outstanding as of December 31, 2003 and 2002. Letters of credit in the aggregate amount of $15.0 million and $17.4 million were outstanding as of December 31, 2003 and 2002, respectively. The cash deposits of Avista Energy at the respective banks collateralize these letters of credit, which is reflected as restricted cash on the Consolidated Balance Sheet.

The Avista Energy credit agreement contains customary covenants and default provisions, including covenants to maintain “minimum net working capital” and “minimum net worth,” as well as a covenant limiting the amount of indebtedness that the co-borrowers may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. Also, a reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement. These covenants, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. Avista Energy was in compliance with the covenants of its credit agreement as of December 31, 2003.

NOTE 17. INTEREST RATE SWAP AGREEMENTS

On May 7, 2003, Avista Corp. terminated an interest rate swap agreement that was entered into on July 17, 2002. This interest rate swap agreement effectively changed the interest rate on $25 million of Unsecured Senior Notes from a fixed rate of 9.75 percent to a variable rate based on LIBOR. With the termination of the interest rate swap agreement, Avista Corp. received $1.5 million, which was recorded as a deferred credit (as part of long-term debt) and will be amortized over the remaining term of the original agreement (through June 1, 2008).

RP LLC has entered into two interest rate swap agreements, maturing in 2006, to manage the risk that changes in interest rates may affect the amount of future interest payments. RP LLC agreed to pay fixed rates of interest with the differential paid or received under the interest rate swap agreements recognized as an adjustment to interest expense. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133. The fair value of the interest rate swap agreements was determined by reference to market values obtained from various third party sources. Avista Power’s 49 percent ownership interest in RP LLC is accounted for under the equity method of accounting. As of December 31, 2003, there was an unrealized loss of $1.2 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheet. See Note 2 for discussion of the potential consolidation of RP LLC pursuant to FIN 46.

AVISTA CORPORATION

NOTE 18. LEASES

The Company has multiple lease arrangements involving various assets, with minimum terms ranging from one to twenty-five years. The Company’s most significant leased asset is the corporate office building. Certain lease arrangements require the Company, upon the occurrence of specified events, to purchase the leased assets. The Company’s management believes the likelihood of the occurrence of the specified events under which the Company could be required to purchase the leased assets is remote. Rental expense under operating leases for 2003, 2002 and 2001 was $14.2 million, $21.7 million and $19.8 million, respectively.

Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year as of December 31, 2003 were as follows (dollars in thousands):


Year ending December 31:	2004		2005		2006		2007		2008		Thereafter		Total

Minimum payments required	$	7,479	$	3,405	$	2,835	$	2,651	$	2,655	$	6,939	$	25,964

The payments under the Avista Corp. capital leases are $0.8 million in each of 2004, 2005 and 2006, $0.7 million in 2007 and $0.6 million in 2008.

The payments under the Avista Capital subsidiaries’ capital leases are $0.7 million in 2004, $0.5 million in each of 2005, 2006 and 2007 and $0.4 million in 2008.

NOTE 19. GUARANTEES

The $110.0 million committed credit agreement of Avista Energy and its subsidiary, Avista Energy Canada, Ltd., as co-borrowers, is guaranteed by Avista Capital and secured by Avista Energy’s assets. This credit agreement expires on July 23, 2004. This agreement also provides for the issuance of letters of credit to secure contractual obligations to counterparties. No cash advances were outstanding as of December 31, 2003. Letters of credit in the aggregate amount of $15.0 million were outstanding as of December 31, 2003. Under an uncommitted credit facility that was guaranteed by Avista Capital that expired in July 2003, there were no cash advances outstanding and $17.4 million in letters of credit were outstanding as of December 31, 2002.

The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount with respect to, the Preferred Trust Securities issued by its affiliates, Avista Capital I and Avista Capital II, to the extent that these entities have funds available for such payments from the respective debt securities.

In the course of the energy trading business, Avista Capital provides guarantees to other parties with whom Avista Energy may be doing business. At any point in time, Avista Capital is only liable for the outstanding portion of the guarantee, which was $35.0 million and $64.6 million as of December 31, 2003 and 2002, respectively. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $411.7 million and $451.7 million as of December 31, 2003 and 2002, respectively. Most guarantees do not have set expiration dates; however, either party may terminate the guarantee at any time with minimal written notice.

Avista Power, through its equity investment in RP LLC, is a 49 percent owner of the Lancaster Project, which commenced commercial operation in September 2001. Commencing with commercial operations, all of the output from the Lancaster Project is contracted to Avista Energy through 2026 years under a Power Purchase Agreement. Avista Corp. has guaranteed the Power Purchase Agreement with respect to the performance of Avista Energy.

NOTE 20. PREFERRED STOCK-CUMULATIVE

In March 2003, the Company repurchased 17,500 shares of preferred stock for $1.6 million, satisfying its redemption requirement for 2003. In September 2002, the Company made a mandatory redemption of 17,500 shares of preferred stock for $1.75 million. On September 15, 2004, 2005 and 2006, the Company must redeem 17,500 shares at $100 per share plus accumulated dividends through a mandatory sinking fund. As such, redemption requirements are $1.75 million in each of the years 2004 through 2006. The remaining shares must be redeemed on September 15, 2007. The Company has the right to redeem an additional 17,500 shares on each September 15 redemption date; however, this right is limited by an agreement under the Company’s 9.75 percent Senior Notes that mature in 2008. Upon involuntary liquidation, all preferred stock will be entitled to $100 per share plus accrued dividends.

As discussed in Note 2, the Company adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement

AVISTA CORPORATION

requires the Company to classify preferred stock subject to mandatory redemption as liabilities and preferred stock dividends as interest expense. The restatement of prior periods was not permitted.

NOTE 21. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying values of cash and cash equivalents, restricted cash, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Energy commodity assets and liabilities as well as securities held for trading are reported at estimated fair value on the Consolidated Balance Sheet.

The fair value of the Company’s long-term debt (including current-portion, but excluding capital leases) as of December 31, 2003 and 2002 was estimated to be $1,067.3 million, or 112 percent of the carrying value of $950.9 million, and $1,001.2 million, or 103 percent of the carrying value of $975.1 million, respectively. The fair value of the Company’s mandatorily redeemable preferred stock as of December 31, 2003 and 2002 was estimated to be $29.9 million, or 95 percent of the carrying value of $31.5 million, and $29.3 million, or 88 percent of the carrying value of $33.3 million, respectively. The fair value of the Company’s long-term debt to affiliated trusts as of December 31, 2003 was estimated to be $99.5 million, or 90 percent of the carrying value of $110.0 million. The carrying value as of December 31, 2003 does not include $3.4 million of debt that is considered common equity by the affiliated trusts. The fair value of the Company’s preferred trust securities as of December 31, 2002 was estimated to be $89.6 million, or 90 percent of the carrying value of $100.0 million. These estimates were primarily based on available market information.

NOTE 22. COMMON STOCK

In April 1990, the Company sold 1,000,000 shares of its common stock to the Trustee of the Investment and Employee Stock Ownership Plan for Employees of the Company (Plan) for the benefit of the participants and beneficiaries of the Plan. In payment for the shares of common stock, the Trustee issued a promissory note payable to the Company in the amount of $14.1 million. Dividends paid on the stock held by the Trustee, plus Company contributions to the Plan, if any, are used by the Trustee to make interest and principal payments on the promissory note. The balance of the promissory note receivable from the Trustee ($2.4 million as of December 31, 2003) is reflected as a reduction to common equity. The shares of common stock are allocated to the accounts of participants in the Plan as the note is repaid. During 2003, the cost recorded for the Plan was $6.9 million. Interest on the note payable to the Company, cash and stock contributions to the Plan and dividends on the shares held by the Trustee was $0.3 million, $1.7 million and $0.1 million, respectively during 2003.

In November 1999, the Company adopted a shareholder rights plan pursuant to which holders of common stock outstanding on February 15, 1999, or issued thereafter, were granted one preferred share purchase right (Right) on each outstanding share of common stock. Each Right, initially evidenced by and traded with the shares of common stock, entitles the registered holder to purchase one one-hundredth of a share of preferred stock of the Company, without par value, at a purchase price of $70, subject to certain adjustments, regulatory approval and other specified conditions. The Rights will be exercisable only if a person or group acquires 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer, the consummation of which would result in the beneficial ownership by a person or group of 10 percent or more of the outstanding shares of common stock. Upon any such acquisition, each Right will entitle its holder to purchase, at the purchase price, that number of shares of common stock or preferred stock of the Company (or, in the case of a merger of the Company into another person or group, common stock of the acquiring person or group) that has a market value at that time equal to twice the purchase price. In no event will the Rights be exercisable by a person that has acquired 10 percent or more of the Company’s common stock. The Rights may be redeemed, at a redemption price of $0.01 per Right, by the Board of Directors of the Company at any time until any person or group has acquired 10 percent or more of the common stock. The Rights expire on March 31, 2009. This plan replaced a similar shareholder rights plan that expired in February 2000.

The Company has a Dividend Reinvestment and Stock Purchase Plan under which the Company’s shareholders may automatically reinvest their dividends and make optional cash payments for the purchase of the Company’s common stock at current market value.

From March 2000 through May 2003, the Company issued shares of its common stock to the Employee Investment Plan rather than having the Plan purchase shares of common stock on the open market. In the fourth quarter of 2000, the Company also began issuing new shares of common stock for the Dividend Reinvestment and Stock Purchase

AVISTA CORPORATION

Plan. During 2003, 2002 and 2001, a total of 299,801, 408,800 and 332,861 shares of common stock were issued, respectively, to these plans.

NOTE 23. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the years ended December 31 (in thousands, except per share amounts):


			2003			2002			2001

Numerator:
Income from continuing operations			$	50,643		$	42,174		$	68,241
Loss from discontinued operations				(4,949	)		(6,719	)		(56,085	)

Net income before cumulative effect of accounting change				45,694			35,455			12,156
Cumulative effect of accounting change				(1,190	)		(4,148	)		—

Net income				44,504			31,307			12,156
Deduct: Preferred stock dividend requirements				1,125			2,402			2,432

Income available for common stock			$	43,379		$	28,905		$	9,724

Denominator:
Weighted-average number of common shares outstanding-basic				48,232			47,823			47,417
Effect of dilutive securities:
		Restricted stock		—			2			5
		Contingent stock		244			—			—
		Stock options		154			49			13

Weighted-average number of common shares outstanding-diluted				48,630			47,874			47,435

Earnings per common share, basic:
	Earnings per common share from continuing operations		$	1.03		$	0.83		$	1.39
	Loss per common share from discontinued operations			(0.10	)		(0.14	)		(1.18	)

	Earnings per common share before cumulative effect of accounting change			0.93			0.69			0.21
	Loss per common share from cumulative effect of accounting change			(0.03	)		(0.09	)		—

	Total earnings per common share, basic		$	0.90		$	0.60		$	0.21

Earnings per common share, diluted:
	Earnings per common share from continuing operations		$	1.02		$	0.83		$	1.38
	Loss per common share from discontinued operations			(0.10	)		(0.14	)		(1.18	)

	Earnings per common share before cumulative effect of accounting change			0.92			0.69			0.20
	Loss per common share from cumulative effect of accounting change			(0.03	)		(0.09	)		—

	Total earnings per common share, diluted		$	0.89		$	0.60		$	0.20

NOTE 24. STOCK COMPENSATION PLANS

Avista Corp.

In 1998, the Company adopted and shareholders approved an incentive compensation plan, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain key employees, directors and officers of the Company and its subsidiaries may be granted stock options, stock appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The Company has available a maximum of 2.5 million shares of its common stock for grant under the 1998 Plan. Beginning in 2000, non-employee directors began receiving options under this plan.

In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the exclusion of directors and executive officers of the Company. The Company has available a maximum of 2.5 million shares of its common stock for grant under the 2000 Plan.

AVISTA CORPORATION

The Board of Directors has determined that it is no longer in the Company’s best interest to issue stock options under the 1998 Plan and the 2000 Plan. Other forms of compensation are in place including the issuance of performance shares to certain officers and other key employees under the 1998 Plan and the 2000 Plan.

The Company accounts for stock based compensation using APB No. 25, “Accounting for Stock Issued to Employees,” which requires the recognition of compensation expense on the excess, if any, of the market price of the stock at the date of grant over the exercise price of the option. As the exercise price for options granted under the 1998 Plan and the 2000 Plan was equal to the market price at the date of grant, there was no compensation expense recorded by the Company. SFAS No. 123, “Accounting for Stock-Based Compensation,” requires the disclosure of pro forma net income and earnings per common share had the Company adopted the fair value method of accounting for stock options. Under this statement, the fair value of stock-based awards is calculated with option pricing models. These models require the use of subjective assumptions, including stock price volatility, dividend yield, risk-free interest rate and expected time to exercise. The fair value of options is estimated on the date of grant using the Black-Scholes option-pricing model. See Note 1 for disclosure of pro forma net income and earnings per common share.

In 2003, the Company granted 162,600 performance shares to certain officers and other key employees under the 1998 Plan and the 2000 Plan. The performance shares will be payable at the Company’s option in either cash or common stock three years from the date of grant. The amount of cash paid or common stock issued will range from 0 to 150 percent of the performance shares granted depending on the change in the value of the Company’s common stock relative to an external benchmark.

Shares of common stock issued from the exercise of stock options under the 1998 Plan and the 2000 Plan are acquired by the Company on the open market. As of December 31, 2003, there were 2.2 million shares available for future stock grants under the 1998 Plan and the 2000 Plan.

The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:


		2003			2002			2001

Number of shares under stock options:
Options outstanding at beginning of year			2,684,350			2,440,475			1,843,900
	Options granted		24,000			569,800			781,900
	Options exercised		(37,439	)		—			(2,750	)
	Options canceled		(189,025	)		(325,925	)		(182,575	)

Options outstanding at end of year			2,481,886			2,684,350			2,440,475

Options exercisable at end of year			1,615,455			1,192,775			883,075

Weighted average exercise price:
	Options granted	$	12.41		$	10.51		$	12.43
	Options exercised	$	11.43			—		$	17.96
	Options canceled	$	17.78		$	19.88		$	19.22
	Options outstanding at end of year	$	15.57		$	15.69		$	17.49
	Options exercisable at end of year	$	17.18		$	18.28		$	19.28
Weighted average fair value of options granted during the year		$	4.30		$	3.43		$	5.54
Principal assumptions used in applying the Black-Scholes model:
	Risk-free interest rate		3.17	%		3.25%-4.96	%		4.05%-5.13	%
	Expected life, in years		7			7			7
	Expected volatility		37.10	%		47.13	%		60.80	%
	Expected dividend yield		3.87	%		4.61	%		3.93	%

AVISTA CORPORATION

Information with respect to options outstanding and options exercisable as of December 31, 2003 was as follows:


	Options Outstanding						Options Exercisable

			Weighted		Weighted				Weighted
			Average		Average				Average
Range of	Number		Exercise		Remaining		Number		Exercise
Exercise Prices	of Shares		Price		Life (in years)		of Shares		Price

$8.77-$11.68		523,161	$	10.25		8.8		131,605	$	10.25
$11.69-$14.61		652,525		11.82		7.9		312,825		11.80
$14.62-$17.53		540,400		17.14		6.1		504,900		17.20
$17.54-$20.45		289,800		18.73		5.1		288,750		18.72
$20.46-$23.38		449,800		22.56		6.7		353,975		22.56
$26.30-$28.47		26,200		27.39		6.2		23,400		27.26

Total		2,481,886	$	15.57		7.2		1,615,455	$	17.18

Avista Capital Companies

Certain subsidiaries of Avista Capital have employee stock incentive plans under which certain employees and directors of the Company and the subsidiaries are granted options to purchase subsidiary shares at prices no less than the fair market value on the date of grant. Options outstanding under these plans usually vest over periods of between three and five years from the date granted and terminate ten years from the date granted. Upon termination of employment, vested options may be exercised and the related subsidiary shares may be, but are not required to be, repurchased by the applicable subsidiary at estimated fair value.

Non-Employee Director Stock Plan

In 1996, the Company adopted and shareholders approved the Non-Employee Director Stock Plan (1996 Director Plan). Under the 1996 Director Plan, directors who are not employees of the Company receive two-thirds of their annual retainer in Avista Corp. common stock. The Company acquires the common stock on the open market. The Company has available a maximum of 150,000 shares of its common stock under the 1996 Director Plan and there were 65,553 shares available for future compensation to non-employee directors as of December 31, 2003.

NOTE 25. COMMITMENTS AND CONTINGENCIES

The Company believes, based on the information presently known, that the ultimate liability for the matters discussed in this note, individually or in the aggregate, taking into account established accruals for estimated liabilities, will not be material to the consolidated financial condition of the Company, but could be material to results of operations or cash flows for a particular quarter or annual period. No assurance can be given, however, as to the ultimate outcome with respect to any particular issue.

Federal Energy Regulatory Commission Inquiry

In February 2002, the Federal Energy Regulatory Commission (FERC) issued an order commencing a fact-finding investigation of potential manipulation of electric and natural gas prices in the California energy markets by multiple companies. On May 8, 2002, the FERC requested data and information with respect to certain trading strategies in which the companies may have engaged. Specifically, the requests inquired as to whether or not the Company engaged in certain trading strategies that were the same or similar to those used by Enron Corporation (Enron) and its affiliates. These requests were made to all sellers of wholesale electricity and/or ancillary services in power markets in the western United States during 2000 and 2001, including Avista Corp. and Avista Energy. On May 22, 2002, Avista Corp. and Avista Energy filed their responses to this request indicating that both companies had engaged in sound business practices in accordance with established market rules, and that no information was evident from business records or employee interviews that would indicate that Avista Corp. or Avista Energy, or its employees, were knowingly engaged in these trading strategies, or any variant of the strategies.

On June 4, 2002, the FERC issued an additional order to Avista Corp. and three other companies requiring these companies to show cause within ten days as to why their authority to charge market-based rates should not be revoked. In this order, the FERC alleged that Avista Corp. failed to respond fully and accurately to the data request made on May 8, 2002. On June 14, 2002, Avista Corp. provided additional information in response to the June 4, 2002 FERC order to establish that its initial response was appropriate and adequate.

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AVISTA CORPORATION

On August 13, 2002, the FERC issued an order to initiate an investigation into possible misconduct by Avista Corp. and Avista Energy and two affiliates of Enron: Enron Power Marketing, Inc. (EPMI) and Portland General Electric Corporation (PGE). The purpose of the investigation was to determine whether Avista Corp. and Avista Energy engaged in or facilitated certain Enron trading strategies, whether Avista Corp.’s or Avista Energy’s role in transactions with EPMI and PGE resulted in the circumvention of a code of conduct governing transactions with affiliates, and the imposition of any appropriate remedies such as refunds and revocation of market-based rates. The investigation also explored whether the companies provided all relevant information in response to the May 8, 2002 data request.

In December 2002, as a result of the investigation, the FERC trial staff, Avista Corp. and Avista Energy filed a joint motion announcing that the parties had reached an agreement in principle and requested that the procedural schedule be suspended. In the joint motion, the FERC trial staff stated that its investigation found no evidence that: (1) any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy; (2) Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) Avista Utilities or Avista Energy withheld relevant information from the FERC’s inquiry into the western energy markets for 2000 and 2001. In December 2002, the FERC’s administrative law judge approved the joint motion, suspending the procedural schedule in the FERC investigation regarding Avista Corp. and Avista Energy. In January 2003, the FERC trial staff, Avista Corp. and Avista Energy filed a completed agreement in resolution of the proceeding with the administrative law judge. The parties requested that the administrative law judge certify the agreement and forward it to the FERC commissioners for acceptance following a 30-day comment period.

In February 2003, the City of Tacoma (Tacoma) and California Parties (the Office of the Attorney General, the California Public Utilities Commission (CPUC), and the California Electricity Oversight Board, filing jointly) filed comments in opposition to the agreement in resolution between the FERC trial staff, Avista Corp. and Avista Energy. PGE filed comments supporting the agreement in resolution, but took exception to how certain transactions were reported. On March 3, 2003, Avista Corp. and Avista Energy filed joint reply comments in response to Tacoma, the California Parties, and PGE. The FERC trial staff filed separate reply comments supporting the agreement in resolution and responding to Tacoma, the California Parties and PGE. The reply comments of Avista Corp., Avista Energy and the FERC trial staff also reiterated the request that the administrative law judge certify the agreement in resolution and forward it to the FERC commissioners for approval.

On March 26, 2003, the FERC policy staff issued its final report on their investigation of western energy markets. In the report, the FERC policy staff recommended the issuance of “show cause” orders to dozens of companies to respond to allegations of possible misconduct in the western energy markets during 2000 and 2001. Of the companies named in the March 26, 2003 report, Avista Corp. and Avista Energy were among the few that had already been the subjects of a FERC investigation.

At an April 9, 2003 prehearing conference relating to the ongoing investigation of Avista Corp. and Avista Energy, Avista Corp. proposed that the decision to certify the agreement between Avista Corp., Avista Energy and the FERC trial staff be delayed to further address certain issues and to allow for potential uncertainty to be removed with respect to the final resolution of the case. The FERC’s administrative law judge agreed and ordered a further prehearing conference to clarify certain issues raised in the March 26, 2003 FERC policy staff report on western energy markets.

On May 15, 2003, the FERC’s trial staff submitted supplementary information explaining its conclusions and addressing three narrowly focused issues related to the March 26, 2003 FERC policy staff report on western energy markets. The FERC’s administrative law judge held a further prehearing conference on May 20, 2003, at which time the FERC trial staff reviewed its findings and conclusions, and reiterated their recommendation to certify the agreement in resolution as supplemented. On May 27, 2003, Tacoma and the California Parties reiterated their objections to the proposed agreement in resolution. Avista Corp., Avista Energy and the FERC trial staff each filed reply comments to Tacoma and the California Parties on June 3, 2003, reiterating their recommendations to the FERC’s administrative law judge for certification of the agreement in resolution.

On June 25, 2003, the FERC’s administrative law judge issued an order denying the request to certify the agreement in resolution and to forward it to the FERC commissioners for final approval. In the June 25, 2003 order, the FERC’s administrative law judge reinstated a procedural schedule that called for further testimony and hearings in the case.

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On July 10, 2003, Avista Corp. and Avista Energy filed an appeal to the June 25, 2003 order. In the appeal, Avista Corp. and Avista Energy asserted that the FERC’s administrative law judge did not have the opportunity to consider how other orders, which were also issued on June 25, 2003 by the FERC with respect to western energy markets and Enron, would impact the case. Those orders provided additional guidance with respect to defining improper trading activities with the effect of further validating the findings of the FERC trial staff’s investigation of Avista Corp. and Avista Energy. On July 10, 2003, the FERC trial staff also filed a motion with the FERC’s administrative law judge asking for clarification and reconsideration of the June 25, 2003 order. The FERC’s trial staff requested that the agreement in resolution be certified and forwarded to the FERC commissioners for final approval without the need for a further hearing. On July 17, 2003, Avista Corp. and Avista Energy filed an answer to this motion with the FERC, which supported the FERC trial staff’s position.

On July 24, 2003, the FERC’s administrative law judge issued an order, which granted the FERC trial staff’s July 10, 2003 motion for reconsideration. In the order, the judge found that there were no unresolved issues of material fact and that the record was sufficient for the FERC to make a determination on the merits of the settlement. The judge certified the agreement in resolution and forwarded it to the FERC commissioners for final approval. In reaching this conclusion, the FERC’s administrative law judge considered the July 10, 2003 appeal by Avista Corp. and Avista Energy. However, this appeal was denied as moot in view of granting the FERC trial staff motion for reconsideration. The certification stated that “the Chief Judge further finds that the proposed settlement disposes of all issues set for hearing in this proceeding, that it is just, reasonable, and in the public interest.”

On August 8, 2003, the California Parties filed a motion with the FERC and the chief administrative law judge requesting that the judge reconsider his July 24, 2003 order granting reconsideration and canceling the procedural schedule, as well as the judge’s certification of the agreement in resolution. In response to the filing, the chief administrative law judge stated that he certified the agreement in resolution and forwarded it to the FERC commissioners for their consideration. The chief administrative law judge indicated that he would advise the Secretary of the FERC that the California Parties’ motion be referred to the FERC commissioners for consideration. On August 22, 2003, Avista Corp. and Avista Energy filed a response to the August 8, 2003 motion of the California Parties. The response reiterated, among other things, that the agreement in resolution is strongly supported by the extensive investigation conducted by the FERC trial staff, and should be approved by the FERC commissioners.

Final approval of the agreement in resolution has remained pending before the FERC since July 2003.

U.S. Commodity Futures Trading Commission (CFTC) Subpoena

Beginning in June 2002, the CFTC issued several subpoenas directing Avista Corp. and Avista Energy to produce certain materials and make employees available to be interviewed. The inquiries related to whether electricity and natural gas trades by Avista Corp. and Avista Energy involved “round trip trades,” “wash trades,” or “sell/buyback trades” and whether Avista Corp. and Avista Energy properly reported trading prices to publishers of power and natural gas indices. Avista Corp. and Avista Energy cooperated with the CFTC and provided the information requested by the CFTC. While the CFTC always reserves the right to reopen its investigation, the CFTC provided written notification to Avista Corp. and Avista Energy on January 29, 2004 that it has determined to close the investigation.

Class Action Securities Litigation

On September 27, 2002, Ronald R. Wambolt filed a class action lawsuit in the United States District Court for the Eastern District of Washington against Avista Corp., Thomas M. Matthews, the former Chairman of the Board, President and Chief Executive Officer of the Company, Gary G. Ely, the current Chairman of the Board, President and Chief Executive Officer of the Company, and Jon E. Eliassen, the former Senior Vice President and Chief Financial Officer of the Company. In October and November 2002, Gail West, Michael Atlas and Peter Arnone filed similar class action lawsuits in the same court against the same parties. On February 3, 2003, the court issued an order consolidating the complaints under the name “In re Avista Corp. Securities Litigation,” and on February 7, 2003 appointed the lead plaintiff and co-lead counsel. On August 19, 2003, the plaintiffs filed their consolidated amended class action complaint in the same court against the same parties. In their complaint, the plaintiffs continue to assert violations of the federal securities laws in connection with alleged misstatements and omissions of material fact pursuant to Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The plaintiffs allege that the Company did not have adequate risk management processes, procedures and controls. The plaintiffs further allege

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that the Company engaged in unlawful energy trading practices and allegedly manipulated western power markets. The plaintiffs assert that alleged misstatements and omissions have occurred in the Company’s filings with the Securities and Exchange Commission and other information made publicly available by the Company, including press releases. The class action complaint asserts claims on behalf of all persons who purchased, converted, exchanged or otherwise acquired the Company’s common stock during the period between November 23, 1999 and August 13, 2002. The Company filed a motion to dismiss this complaint in October 2003 and the plaintiffs filed an answer to this motion in January 2004. Arguments before the Court on the motion are scheduled to be held on March 19, 2004. The Company intends to vigorously defend against this lawsuit.

California Energy Markets

In April 2002, several subsidiaries of Reliant Energy, Inc. (Reliant) and Duke Energy Corporation (Duke) filed cross-complaints against Avista Energy and numerous other participants in the California energy markets. The cross-complaints seek indemnification for any liability that may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair business practices in the California energy markets under California law. In June 2002, Avista Energy filed motions to dismiss the cross-complaints. In the meantime, the U.S. District Court remanded the case to California State Court, which remand is itself the subject of an appeal to the United States Court of Appeals for the Ninth Circuit.

In March 2002, the Attorney General of the State of California (California AG) filed a complaint with the FERC against certain specific companies (not including Avista Corp. or its subsidiaries) and “all other public utility sellers” in California. The complaint alleges that sellers with market-based rates have violated their tariffs by not filing with the FERC transaction-specific information about all of their sales and purchases at market-based rates. As a result, the California AG contends that all past sales should be subject to refund if found to be above just and reasonable levels. In May 2002, the FERC issued an order denying the claim to issue refunds. In July 2002, the California AG requested a rehearing on the FERC order, which request was denied in September 2002. The California AG filed a Petition for Review of the FERC’s decision with the United States Court of Appeals for the Ninth Circuit and awaits decision.

Port of Seattle Complaint

On May 21, 2003, the Port of Seattle filed a complaint in the United States District Court for the Western District of Washington against numerous companies, including Avista Corp., Avista Energy and Avista Power. The complaint seeks compensatory and treble damages for alleged violations of the Sherman Act and the Racketeer Influenced and Corrupt Organization Act by transmitting, via wire communications, false information intended to increase the price of power, knowing that others would rely upon such information. The complaint alleges that the defendants and others knowingly devised and attempted to devise a scheme to defraud and to obtain money and property from electricity customers throughout the WECC, by means of false and fraudulent pretenses, representations and promises. The alleged purpose of the scheme was to artificially increase the price that the defendants received for their electricity and ancillary services, to receive payments for services they did not provide and to manipulate the price of electricity throughout the WECC. In August 2003, the Company filed a motion to dismiss this complaint. A transfer order has been granted, which moves this case to the United States District Court for the Southern District of California to consolidate it with other pending actions. Arguments with respect to the motions to dismiss filed by the Company and other defendants are scheduled for March 26, 2004.

State of Montana Proceedings

On June 30, 2003, the Attorney General of the State of Montana (Montana AG) filed a complaint in the Montana District Court on behalf of the people of Montana and the Flathead Electric Cooperative, Inc. against numerous companies, including Avista Corp. The complaint alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. This case was subsequently moved to the United States District Court for the District of Montana; however, it has since been remanded back to the Montana District Court.

The Montana AG also petitioned the Montana Public Service Commission (MPSC) to fine public utilities $1,000 a day for each day it finds they engaged in alleged “deceptive, fraudulent, anticompetitive or abusive practices” and order refunds when consumers were forced to pay more than just and reasonable rates. On February 12, 2004, the MPSC issued an order initiating investigation of the Montana retail electricity market for the purpose of determining whether there is evidence of unlawful manipulation of that market.

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Montana Public School Trust Fund Lawsuit

On October 20, 2003, Richard Dolan and Denise Hayman filed a lawsuit in the United States District Court for the District of Montana against all private owners of hydroelectric dams in Montana, including Avista Corp. The lawsuit alleges that the hydroelectric facilities are located on state-owned riverbeds and the owners have never paid compensation to the state’s public school trust fund. The lawsuit requests lease payments dating back to the construction of the respective dams and also requests damages for trespassing and unjust enrichment. An Amended Complaint adding Great Falls Elementary School District No. 1 and Great Falls High School District 1A was filed on January 16, 2004. On February 2, 2004, the Company filed its motion to dismiss this lawsuit; PacifiCorp and PPL Montana, as the other named defendants also filed a motion to dismiss, or joined therein.

State of Washington Business and Occupation Tax

The State of Washington’s Business and Occupation Tax applies to gross revenue from business activities. For most types of business, the tax applies to the gross sales price received for goods or services. For certain types of financial trading activities, including the sale of stocks, bonds and other securities, the tax applies to the realized gain from the sale of the financial asset. On an audit for the period from July 1, 1997 through June 30, 2000, the Department of Revenue (DOR) took the position that approximately 20 percent of the forward energy trades of Avista Energy should not be treated as securities trades, but rather as energy deliveries. As a result, the DOR applied tax against the gross sales price of the energy contracts at issue. Avista Energy subsequently received an assessment of $14.5 million for tax and interest related to the disputed issue. It is the position of Avista Energy that all of its forward contract trading activities are substantively the same and there is no proper basis for the distinction made by the DOR. An administrative appeal was filed with the DOR and a hearing was held in September 2001. The DOR issued a Proposed Determination in December 2002, which reiterated the original $14.5 million assessment. In December 2003, Avista Energy and the DOR reached a settlement in principle with respect to a final resolution of this matter within the amount that Avista Energy had previously accrued for this matter.

Colstrip Generating Project Complaint

In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed a consolidated complaint against the owners of the Colstrip Generating Project (Colstrip) in Montana District Court. Avista Corp. owns a 15 percent interest in units 3 and 4 of Colstrip, which is located in southeastern Montana. The plaintiffs allege damages to buildings as a result of rising ground water, as well as damages from contaminated waters leaking from the lakes and ponds of Colstrip. The plaintiffs are seeking punitive damages, an order by the court to remove the lakes and ponds and the forfeiture of all profits earned from the generation of Colstrip. The Company intends to work with the other owners of Colstrip in defense of this complaint.

Hamilton Street Bridge Site

A portion of the Hamilton Street Bridge Site in Spokane, Washington (including a former coal gasification plant site that operated for approximately 60 years until 1948) was acquired by the Company through a merger in 1958. The Company no longer owns the property. In January 1999, the Company received notice from the State of Washington’s Department of Ecology (DOE) that it had been designated as a potentially liable party (PLP) with respect to any hazardous substances located on this site, stemming from the Company’s past ownership of the former gas plant site. In its notice, the DOE stated that it intended to complete an on-going remedial investigation of this site, complete a feasibility study to determine the most effective means of halting or controlling future releases of substances from the site, and to implement appropriate remedial measures. The Company responded to the DOE acknowledging its listing as a PLP, but requested that additional parties also be listed as PLPs. In the spring of 1999, the DOE named two other parties as additional PLPs.

The DOE, the Company and another PLP, Burlington Northern & Santa Fe Railway Co. (BNSF) signed an Agreed Order in March 2000 that provided for the completion of a remedial investigation and a feasibility study. The work to be performed under the Agreed Order includes three major technical parts: completion of the remedial investigation; performance of a focused feasibility study; and implementation of an interim groundwater monitoring plan. During the second quarter of 2000, the Company received comments from the DOE on its initial remedial investigation, and then submitted another draft of the remedial investigation, which was accepted as final by the DOE. After responding to comments from the DOE, the feasibility study was accepted by the DOE during the fourth quarter of 2000. After receiving input from the Company and the other PLPs, the final Cleanup Action Plan (CAP) was issued by the DOE in August 2001. In September 2001, the DOE issued an initial draft Consent Decree for the

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PLPs to review. During the first quarter of 2002, the Company and BNSF signed a cost sharing agreement. In September 2002, the Company, BNSF and the DOE finalized the Consent Decree to implement the CAP. The third PLP has indicated it will not sign the Consent Decree. It is currently estimated that the Company’s share of the costs will be less than $1.0 million. The Engineering and Design Report for the CAP was submitted to the DOE in January 2003 and approved by the DOE in May 2003. Work under the CAP commenced during the second quarter of 2003. Negotiations are continuing with the third PLP with respect to the logistics of the CAP.

Spokane River

In March 2001, the DOE informed Avista Development, a subsidiary of Avista Capital, of a health advisory concerning PCBs found in fish caught in a portion of the Spokane River. In June 2001, Avista Development received official notice that it had been designated as a PLP with respect to contaminated sites on the Spokane River. The DOE discovered PCBs in fish and sediments in the Spokane River in the 1970s and 1980s. In the 1990s, the DOE performed subsequent sampling of the river and identified potential sources of the PCBs, including the Spokane Industrial Park (SIP) and a number of other entities in the area. The SIP, renamed Pentzer Development Corporation (Pentzer Development) in 1990, operated a wastewater treatment plant at the site until it was closed in December 1993. The SIP’s treatment plant discharged to the Spokane River under the terms of a National Pollutant Discharge Elimination System permit issued by the DOE. Pentzer Development sold the property in 1996 and merged with Avista Development in 1998. Avista Development filed a response to this notice in August 2001. In December 2001, the DOE confirmed Avista Development’s status as a PLP and named at least two other PLPs in this matter.

During the fourth quarter of 2002, Avista Development and one other PLP finalized the Consent Decree and Scope of Work for the remedial investigation and feasibility study of the site, which was formally entered into Spokane County Superior Court in January 2003. One other PLP has not been participating in the process. As directed by Avista Development and the other PLP, the field work for the remedial investigation began in April 2003 and was completed by the end of 2003 with a draft remedial investigation report and feasibility study technical memorandum due March 29, 2004. The other PLP that has been participating with Avista Development has filed for bankruptcy and is expected to file its reorganization plan in mid-2004. The other PLP has initiated negotiations with the DOE and Avista Development to settle its future financial liabilities associated with the site.

Lake Coeur d’Alene

In July 1998, the United States District Court for the District of Idaho issued its finding that the Coeur d’Alene Tribe of Idaho owns portions of the bed and banks of Lake Coeur d’Alene and the St. Joe River lying within the current boundaries of the Coeur d’Alene Reservation. This action was brought by the United States on behalf of the Tribe against the State of Idaho. While the Company has not been a party to this action, the Company is continuing to evaluate the potential impact of this decision on the operation of its hydroelectric facilities on the Spokane River, downstream of Lake Coeur d’Alene. The United States District Court decision was affirmed by the United States Court of Appeals for the Ninth Circuit. The United States Supreme Court affirmed this decision in June 2001. This will result in the Company being liable to the Coeur d’Alene Tribe of Idaho for payments for use of reservation lands under Section 10(e) of the Federal Power Act.

Spokane River Relicensing

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groups is underway. The Company’s goal is to develop with the stakeholders a comprehensive and cost-effective settlement agreement to be filed as part of the Company’s license application to the FERC in July 2005.

Clark Fork Settlement Agreement

Dissolved gas levels exceed Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Mitigation of the dissolved gas levels continues to be studied as agreed to in the Clark Fork Settlement Agreement. To date, intensive biological studies in the lower Clark Fork River and Lake Pend Oreille have documented no significant biological effects of high dissolved gas levels on free ranging fish. Under the terms of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other signatories to the agreement and submitted the plan in December 2002 for review and approval to the Idaho Department of Environmental Quality and the U.S. Fish and Wildlife Service. In December 2003, the Idaho Department of Environmental Quality provided modifications to the plan that have been reviewed by the Company. The modifications did not result in any significant changes to the Company’s plan. The structural alternative proposed by the Company provides for the modification of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. The costs of modifications to the first tunnel are currently estimated to be $37 million (including AFUDC and inflation) and would be incurred between 2004 and 2009. The second tunnel would be modified only after evaluation of the performance of the first tunnel and such modifications would commence no later than 10 years following the completion of the first tunnel. It is currently estimated that the costs to modify the second tunnel would be $23 million (including AFUDC and inflation). As part of the plan, the Company will also provide $0.5 million annually commencing as early as 2004, as mitigation for aquatic resources that might be adversely affected by high dissolved gas levels. Mitigation funds will continue until the modification of the second tunnel commences or if the second tunnel is not modified to an agreed upon point in time commensurate with the biological effects of high dissolved gas levels. The Company will seek regulatory recovery of the costs for the modification of Cabinet Gorge and the mitigation payments.

The operating license for the Clark Fork Project describes the approach to restore bull trout populations in the project areas. Using the concept of adaptive management and working closely with the U.S. Fish and Wildlife Service, the Company is evaluating the feasibility of fish passage. The results of these studies will help the Company and other parties determine the best use of funds toward continuing fish passage efforts or other population enhancement measures.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

The Company routinely assesses, based on in-depth studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who have and have not agreed to a settlement and recoveries from insurance carriers. The Company’s policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred.

The Company has potential liabilities under the Federal Endangered Species Act for species of fish that have either already been added to the endangered species list, been listed as “threatened” or been petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company.

Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. The State of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River basin could potentially adversely affect the energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The Company is participating in this extensive adjudication process, which is unlikely to be concluded in the foreseeable future.

The Company must be in compliance with requirements under the Clean Air Act Amendments at the Colstrip thermal generating plant, in which the Company maintains an ownership interest. The anticipated share of costs at Colstrip is not expected to have a major economic impact on the Company.

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As of December 31, 2003, the Company’s collective bargaining agreement with the International Brotherhood of Electrical Workers represented approximately 48 percent of all Avista Utilities employees. The current agreement with the local union representing the majority of the bargaining unit employees expires on March 25, 2005. A local agreement in the South Lake Tahoe area, which represents 5 employees, also expires on March 25, 2005. A local agreement in Medford, Oregon, which covers approximately 40 employees, will expire on March 31, 2005. Negotiations are currently ongoing with respect to two other labor agreements in Oregon covering approximately 15 employees.

NOTE 26. SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s energy operations are significantly affected by weather conditions. Consequently, there can be large variances in revenues, expenses and net income between quarters based on seasonal factors such as temperatures and streamflow conditions. During the second quarter of 2003, Avista Corp. reported Avista Labs as discontinued operations (see Note 3). Accordingly, periods prior to the second quarter of 2003 have been restated to reflect Avista Labs as discontinued operations. Several accounting standards have been issued and rescinded, which have changed the accounting and reporting for derivative commodity instruments. This has resulted in the restatement of operating revenues and resource costs (operating expenses) for periods prior to the issuance or rescission of the respective accounting standards. Such restatements have not had any impact on income from operations, income from continuing operations, net income or income available for common stock. A summary of quarterly operations (in thousands, except per share amounts) for 2003 and 2002 follows:


			Three Months Ended

			March			June			September			December
			31			30			30			31

2003
Operating revenues			$	338,892		$	236,735		$	238,750		$	309,008
Operating expenses:
	Resource costs			185,916			102,309			122,591			165,676
	Operations and maintenance			33,323			33,459			31,722			39,554
	Administrative and general			27,863			22,684			22,780			24,167
	Depreciation and amortization			18,942			18,904			20,114			19,851
	Taxes other than income taxes			17,858			15,270			13,424			15,275

		Total operating expenses		283,902			192,626			210,631			264,523

Income from operations				54,990			44,109			28,119			44,485

Income from continuing operations				18,442			12,713			4,386			15,102
Loss from discontinued operations				(1,120	)		(3,744	)		(66	)		(19	)

Net income before cumulative effect of accounting change				17,322			8,969			4,320			15,083
Cumulative effect of accounting change				(1,190	)		—			—			—

Net income				16,132			8,969			4,320			15,083
Income available for common stock			$	15,554		$	8,422		$	4,320		$	15,083
Outstanding common stock:
	Weighted average			48,100			48,224			48,281			48,319
	End of period			48,182			47,830			48,311			48,344
Earnings per share, diluted:
	Earnings per share from continuing operations		$	0.37		$	0.25		$	0.09		$	0.31
	Loss per share from discontinued operations			(0.02	)		(0.08	)		—			—

	Earnings per share before cumulative effect of accounting change			0.35			0.17			0.09			0.31
	Cumulative effect of accounting change			(0.03	)		—			—			—

	Total earnings per share, diluted		$	0.32		$	0.17		$	0.09		$	0.31

Dividends paid per common share			$	0.12		$	0.12		$	0.125		$	0.125
Trading price range per common share:
	High		$	12.65		$	14.80		$	16.53		$	18.70
	Low		$	9.80		$	10.49		$	13.91		$	15.55

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			Three Months Ended

			March			June			September			December
			31			30			30			31

2002
Operating revenues			$	337,617		$	231,082		$	206,821		$	287,396
Operating expenses:
	Resource costs			196,734			91,040			97,944			150,996
	Operations and maintenance			31,691			30,236			31,799			32,204
	Administrative and general			22,310			33,879			21,795			27,663
	Depreciation and amortization			17,753			17,737			17,440			18,937
	Taxes other than income taxes			19,917			16,290			13,991			15,418

		Total operating expenses		288,405			189,182			182,969			245,218

Income from operations				49,212			41,900			23,852			42,178

Income from continuing operations				16,976			12,292			864			12,042
Loss from discontinued operations				(1,728	)		(1,947	)		(2,479	)		(565	)

Net income (loss) before cumulative effect of accounting change				15,248			10,345			(1,615	)		11,477
Cumulative effect of accounting change				(4,148	)		—			—			—

Net income (loss)				11,100			10,345			(1,615	)		11,477
Income (loss) available for common stock			$	10,492		$	9,737		$	(2,223	)	$	10,899
Outstanding common stock:
	Weighted average			47,671			47,774			47,866			47,978
	End of period			47,737			47,830			47,930			48,044
Earnings (loss) per share, diluted:
	Earnings per share from continuing operations		$	0.35		$	0.24		$	0.00		$	0.24
	Loss per share from discontinued operations			(0.04	)		(0.04	)		(0.05	)		(0.01	)

	Earnings (loss) per share before cumulative effect of accounting change			0.31			0.20			(0.05	)		0.23
	Cumulative effect of accounting change			(0.09	)		—			—			—

	Total earnings (loss) per share, diluted		$	0.22		$	0.20		$	(0.05	)	$	0.23

Dividends paid per common share			$	0.12		$	0.12		$	0.12		$	0.12
Trading price range per common share:
	High		$	16.47		$	16.60		$	13.89		$	12.10
	Low		$	13.00		$	11.00		$	10.16		$	8.75

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9a. Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) to ensure that material information contained in its filings with the Securities and Exchange Commission is recorded, processed, summarized and reported on a timely and accurate basis. The Company’s principal executive officer and principal financial officer have reviewed and evaluated the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on such evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at ensuring that material information is recorded, processed, summarized and reported on a timely and accurate basis in the Company’s filings with the Securities and Exchange Commission. Since such evaluation there have not been any significant changes in the Company’s internal controls, or in other factors that could significantly affect these controls.

There have been no changes in the Company’s internal control over financial reporting identified in connection with the evaluation required by the Securities Exchange Act rules 13a-15(d) and 15d-15(d) that occurred during the Company’s last fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART III

Item 10. Directors and Executive Officers of the Registrant

Information regarding the directors of the Registrant has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 13, 2004.


Executive Officers of the Registrant
Name	Age		Business Experience During the Past 5 Years

Gary G. Ely		56	Director and Chairman of the Board since May 2001. President and Chief Executive Officer since October 2000; Executive Vice President February 1999 - October 2000; Senior Vice President and General Manager August 1996 - February 1999; various other staff and management positions with the Company since 1967.

Malyn K. Malquist		51	Senior Vice President, Chief Financial Officer and Treasurer since February 2004; Senior Vice President and Chief Financial Officer November 2002 – February 2004; Senior Vice President September 2002 – November 2002; prior to employment with the Company: General Manager of Truckee Meadows Water Authority June 2001 – September 2002; President of Malyn Malquist Consulting January 2001 – June 2001; Chief Executive Officer of Data Engines, Inc. June 2000 – October 2000; Various positions at Sierra Pacific Resources April 1994 – April 2000, positions included Chairman of the Board, Chief Executive Officer, President, Senior Vice President, Chief Financial Officer and Principal Operations Officer.

Scott L. Morris		46	Senior Vice President since February 2002; Vice President November 2000 – February 2002; President - Avista Utilities since August 2000; General Manager - Avista Utilities for the Oregon and California operations October 1991 - August 2000; various other staff and management positions with the Company since 1981.

David A. Brukardt		49	Resigned in February 2004; Vice President and Treasurer March 2003 – February 2004; Chief Communication Officer and Vice President of Corporate Relations and Strategic Planning September 2001 – March 2003; Chief Communication Officer and Vice President of Investor and Corporate

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Executive Officers of the Registrant
Name	Age		Business Experience During the Past 5 Years

			Relations August 2000 – September 2001; Vice President of Investor Relations August 1999 - August 2000; prior to employment with the Company: Director - Investor and Corporate Relations - Harnischfeger Industries, Inc. and Vice President - - Harnischfeger Foundation July 1995 - July 1999.

Christy M. Burmeister-Smith		47	Vice President and Controller since June 1999; Controller - Energy Delivery and various other staff and management positions with the Company since 1980.

Karen S. Feltes		48	Vice President of Human Resources and Corporate Secretary since March 2003; Vice President of Human Resources and Corporate Services February 2002 – March 2003; Various Human Resources positions with the Company April 1998 – February 2002; prior to employment with the Company: Adjunct Instructor-City University and Director of Human Resources-Spokane Club 1996-1998.

David J. Meyer		50	Vice President and Chief Counsel for Regulatory and Governmental Affairs since February 2004; Senior Vice President and General Counsel September 1998 – February 2004; prior to employment with the Company: Attorney - Paine Hamblen Coffin Brooke & Miller 1978 - September 1998.

Kelly O. Norwood		45	Vice President since November 2000; Vice President of State and Federal Regulation – Avista Utilities since March 2002; Vice President and General Manager of Energy Resources - Avista Utilities August 2000 – March 2002; various other staff and management positions with the Company since 1981.

Ronald R. Peterson		51	Vice President of Energy Resources and Optimization since March 2003; Vice President and Treasurer November 1998 – March 2003; Vice President Finance - Avista Utilities September 2001 – March 2003; Vice President and Controller February 1998 - November 1998; Controller August 1996 - February 1998; various other staff and management positions with the Company since 1975.

Terry L. Syms		55	Retired in January 2004; Vice President and Assistant to the Chairman March 2003 – January 2004; Vice President and Corporate Secretary February 1998 – March 2003; Corporate Secretary March 1988 – February 1998.

Roger D. Woodworth		47	Vice President since November 1998; Vice President, Business Development and Service Optimization of Avista Utilities since March 2003; Vice President of Utility Operations of Avista Utilities September 2001 – March 2003; Vice President – Corporate Development November 1998 – September 2001; Director of Corporate Development and various other staff and management positions with the Company since 1979.

All of the Company’s executive officers, with the exception of Kelly O. Norwood, were officers or directors of one or more of the Company’s subsidiaries in 2003. The Company’s executive officers are elected annually by the Board of Directors.

The Company has adopted a Code of Business Conduct and Ethics (Code of Conduct) for directors, officers (including the principal executive officer, principal financial officer and controller), and employees. The Code of Conduct is available on the Company’s Web site at www.avistacorp.com and will also be provided to any shareholder upon written request to:

Avista Corp.
Corporate Secretary
P.O. Box 3727 MSC-10
Spokane, Washington 99220-3727

Any changes to or waivers for executive officers and directors of the Company’s Code of Conduct will be posted on the Company’s Web site.

110

AVISTA CORPORATION

Item 11. Executive Compensation

Information regarding executive compensation has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 13, 2004.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

(a)

Security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities):

Information regarding security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities) has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 13, 2004.

(b)

Security ownership of management:

Information regarding security ownership of management has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 13, 2004.

(c)

Changes in control:

None.

(d)

Securities authorized for issuance under equity compensation plans:


	(a)		(b)		(c)
	Number of securities to be		Weighted average		Number of securities remaining
	issued upon exercise of		exercise price of		available for future issuance under
	outstanding options,		outstanding options,		equity compensation plans (excluding
Plan category	warrants and rights		warrants and rights		securities reflected in column (a))

Equity compensation plans approved by security holders (1)		1,955,088	$	13.95		562,740	(3)
Equity compensation plans not approved by security holders (2)		805,336	$	14.12		1,657,325

Total		2,760,424	$	14.00		2,220,065

(1)		Includes the Long-Term Incentive Plan approved by shareholders in 1998 and the Non-Employee Director Stock Plan approved by shareholders in 1996.

(2)		Represents stock options outstanding and stock available for future issuance under the Non-Officer Employee Long-Term Incentive Plan, which was adopted by the Company in 2000. Under this plan, employees (excluding directors and executive officers) of the Company and its subsidiaries may be granted stock options, stock appreciation rights, stock awards, performance awards, other stock-based awards and dividend equivalent rights. Stock options granted under this plan are equal to the market price of the Company’s common stock on the date of grant. Stock options granted under this plan have terms of up to 10 years and generally vest at a rate of 25 percent per year over a four-year period.

(3)		Includes 65,553 of shares available for future compensation to non-employee directors under the Non-Employee Director Stock Plan.

Item 13. Certain Relationships and Related Transactions

Information regarding certain relationships and related transactions has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 13, 2004.

111

AVISTA CORPORATION

Item 14. Principal Accountant Fees and Services

Information regarding principal accountant fees and services has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 13, 2004.

PART IV

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

(a) 1. Financial Statements (Included in Part II of this report):

			Independent Auditors’ Report

			Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001

			Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2003, 2002 and 2001

			Consolidated Balance Sheets as of December 31, 2003 and 2002

			Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001

			Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001

			Schedule of Information by Business Segments for the Years Ended December 31, 2003, 2002 and 2001

			Notes to Consolidated Financial Statements

(a) 2. Financial Statement Schedules:

None

(a) 3. Exhibits:

Reference is made to the Exhibit Index commencing on page 115. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.

(b) Reports on Form 8-K:

			Furnished under items 7 and 12, dated October 24, 2003, with respect to 2003 third quarter earnings.

			Filed under item 5, dated November 18, 2003, with respect to an order issued by the IPUC that extends a 19.4 percent PCA surcharge and that $11.9 million of deferred power costs will be reviewed in an electric general rate case.

112

AVISTA CORPORATION

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		AVISTA CORPORATION
March 8, 2004	By	/s/ Gary G. Ely

Date		Gary G. Ely Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Gary G. Ely Gary G. Ely Chairman of the Board, President and Chief Executive Officer	Principal Executive Officer	March 8, 2004

/s/ Malyn K. Malquist Malyn K. Malquist (Senior Vice President, Chief Financial Officer and Treasurer)	Principal Financial and Accounting Officer	March 8, 2004

/s/ Erik J. Anderson Erik J. Anderson	Director	March 8, 2004

/s/ Kristianne Blake Kristianne Blake	Director	March 8, 2004

/s/ David A. Clack David A. Clack	Director	March 8, 2004

/s/ Roy L. Eiguren Roy L. Eiguren	Director	March 8, 2004

/s/ Jack W. Gustavel Jack W. Gustavel	Director	March 8, 2004

/s/ John F. Kelly John F. Kelly	Director	March 8, 2004

/s/ Jessie J. Knight, Jr. Jessie J. Knight, Jr.	Director	March 8, 2004

/s/ Michael L. Noel Michael L. Noel	Director	March 8, 2004

/s/ Lura J. Powell Lura J. Powell	Director	March 8, 2004

/s/ R. John Taylor R. John Taylor	Director	March 8, 2004

113

INDEPENDENT AUDITORS’ CONSENT

We consent to the incorporation by reference in Registration Statement Nos. 2-81697, 2-94816, 33-54791, 333-03601, 333-22373, 333-58197, 33-32148, 333-33790, and 333-47290 on Form S-8, in Registration Statement Nos. 333-106491, 33-53655, 333-39551, 333-82165, 333-63243, 333-16353, 333-16353-01, 333-16353-02, 333-16353-03, 033-60-136, and 333-64652 on Form S-3, and in Registration Statement Nos. 333-62232, and 333-82502 on Form S-4 of our report dated February 27, 2004, which includes as explanatory paragraph for certain changes in accounting and presentation resulting from the impact of recently adopted accounting standards, appearing in this Annual Report on Form 10-K of Avista Corporation for the year ended December 31, 2003.

/s/ Deloitte & Touche LLP

Seattle, Washington
March 5, 2004

114

AVISTA CORPORATION

EXHIBIT INDEX


	Previously Filed*

	With
	Registration	As
Exhibit	Number	Exhibit

3(a)	1-3701 (with 2001 Form 10-K)	3(a)	Restated Articles of Incorporation of Avista Corporation as amended November 1, 1999.

3(b)	**		Bylaws of Avista Corporation, as amended February 6, 2004.

4(a)-1	2-4077	B-3	Mortgage and Deed of Trust, dated as of June 1, 1939.

4(a)-2	2-9812	4(c)	First Supplemental Indenture, dated as of October 1, 1952.

4(a)-3	2-60728	2(b)-2	Second Supplemental Indenture, dated as of May 1, 1953.

4(a)-4	2-13421	4(b)-3	Third Supplemental Indenture, dated as of December 1, 1955.

4(a)-5	2-13421	4(b)-4	Fourth Supplemental Indenture, dated as of March 15, 1967.

4(a)-6	2-60728	2(b)-5	Fifth Supplemental Indenture, dated as of July 1, 1957.

4(a)-7	2-60728	2(b)-6	Sixth Supplemental Indenture, dated as of January 1, 1958.

4(a)-8	2-60728	2(b)-7	Seventh Supplemental Indenture, dated as of August 1, 1958.

4(a)-9	2-60728	2(b)-8	Eighth Supplemental Indenture, dated as of January 1, 1959.

4(a)-10	2-60728	2(b)-9	Ninth Supplemental Indenture, dated as of January 1, 1960.

4(a)-11	2-60728	2(b)-10	Tenth Supplemental Indenture, dated as of April 1, 1964.

4(a)-12	2-60728	2(b)-11	Eleventh Supplemental Indenture, dated as of March 1, 1965.

4(a)-13	2-60728	2(b)-12	Twelfth Supplemental Indenture, dated as of May 1, 1966.

4(a)-14	2-60728	2(b)-13	Thirteenth Supplemental Indenture, dated as of August 1, 1966.

4(a)-15	2-60728	2(b)-14	Fourteenth Supplemental Indenture, dated as of April 1, 1970.

4(a)-16	2-60728	2(b)-15	Fifteenth Supplemental Indenture, dated as of May 1, 1973.

4(a)-17	2-60728	2(b)-16	Sixteenth Supplemental Indenture, dated as of February 1, 1975.

4(a)-18	2-60728	2(b)-17	Seventeenth Supplemental Indenture, dated as of November 1, 1976.

4(a)-19	2-69080	2(b)-18	Eighteenth Supplemental Indenture, dated as of June 1, 1980.

4(a)-20	1-3701 (with 1980 Form 10-K)	4(a)-20	Nineteenth Supplemental Indenture, dated as of January 1, 1981.

4(a)-21	2-79571	4(a)-21	Twentieth Supplemental Indenture, dated as of August 1, 1982.

*		Incorporated herein by reference.

**		Filed herewith.

115

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*

	With
	Registration	As
Exhibit	Number	Exhibit

4(a)-22	1-3701 (with Form 8-K dated September 20, 1983)	4(a)-22	Twenty-First Supplemental Indenture, dated as of September 1, 1983.

4(a)-23	2-94816	4(a)-23	Twenty-Second Supplemental Indenture, dated as of March 1, 1984.

4(a)-24	1-3701 (with 1986 Form 10-K)	4(a)-24	Twenty-Third Supplemental Indenture, dated as of December 1, 1986.

4(a)-25	1-3701 (with 1987 Form 10-K)	4(a)-25	Twenty-Fourth Supplemental Indenture, dated as of January 1, 1988.

4(a)-26	1-3701 (with 1989 Form 10-K)	4(a)-26	Twenty-Fifth Supplemental Indenture, dated as of October 1, 1989.

4(a)-27	33-51669	4(a)-27	Twenty-Sixth Supplemental Indenture, dated as of April 1, 1993.

4(a)-28	1-3701 (with 1993 Form 10-K)	4(a)-28	Twenty-Seventh Supplemental Indenture, dated as of January 1, 1994.

4(a)-29	1-3701 (with 2001 Form 10-K)	4(a)-29	Twenty-Eighth Supplemental Indenture, dated as of September 1, 2001

4(a)-30	333-82502	4(b)	Twenty-Ninth Supplemental Indenture, dated as of December 1, 2001

4(a)-31	1-3701 (with June 30, 2002 10-Q)	4(f)	Thirtieth Supplemental Indenture, dated as of May 1, 2002

4(a)-32	333-39551	4(b)	Thirty-First Supplemental Indenture, dated as of May 1, 2003

4(a)-33	1-3701 (with September 30, 2003 10-Q)	4(f)	Thirty-Second Supplemental Indenture, dated as of September 1, 2003

4(a)-34	333-82165	4(a)	Indenture dated as of April 1, 1998 between Avista Corp. Corporation and The Chase Manhattan Bank, as Trustee.

4(a)-35	1-3701 (with March 31, 2001 Form 10-Q)	4(f)	Indenture dated as of April 3, 2001, by and among the Company and Chase Manhattan Bank and Trust Company, National Association, as Trustee

4(b)-1	1-3701 (with 1999 Form 10-K)	4(b)-1	Loan Agreement between City of Forsyth, Montana, and the Company, dated as of September 1, 1999 (Series 1999A).

4(b)-2	1-3701 (with 1999 Form 10-K)	4(b)-2	Indenture of Trust, Pollution Control Revenue Refunding Bonds (Series 1999A) between City of Forsyth, Montana, and Chase Manhattan Bank and Trust Company, N.A., dated as of September 1, 1999.

4(b)-3	1-3701 (with 1999 Form 10-K)	4(b)-3	Loan Agreement between City of Forsyth, Montana, and the Company, dated as of September 1, 1999 (Series 1999B).

*		Incorporated herein by reference.

**		Filed herewith.

116

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*

	With
	Registration	As
Exhibit	Number	Exhibit

4(b)-4	1-3701 (with 1999 Form 10-K)	4(b)-4	Indenture of Trust, Pollution Control Revenue Refunding Bonds (Series 1999B) between City of Forsyth, Montana, and Chase Manhattan Bank and Trust Company, N.A., dated as of September 1, 1999.

4(c)	1-3701 (with 1988 Form 10-K)	4(h)-1	Indenture between the Company and Chemical Bank dated as of July 1, 1988 (Series A and B Medium-Term Notes).

4(d)	1-3701 (with June 30, 2002 Form 10-Q)	4(d)	Credit Agreement, dated as of May 21, 2002, among Avista Corporation, The Banks Party Hereto, Keybank and Washington Mutual Bank, as Co-Agents, U.S. Bank, National Association, as Managing Agent, Fleet National Bank and Wells Fargo Bank, as Documentation Agents, Union Bank of California, N.A., as Syndication Agent and The Bank of New York, as Administrative Agent and Issuing Bank.

4(e)	1-3701 (with June 30, 2003 Form 10-Q)	4(d)	Amendment No. 1, dated as of May 13, 2003, extending the expiration date of the Credit Agreement dated as of May 21, 2002 among Avista Corporation, the Banks Party Hereto, Washington Mutual Bank, as Managing Agent, Fleet National Bank, Keybank National Association, U.S. Bank, National Association and Wells Fargo Bank, as Documentation Agents, Union Bank of California, N.A., as Syndication Agent and The Bank of New York, as Administrative Agent and Issuing Bank.

4(f)	1-3701 (with June 30, 2002 Form 10-Q)	4(e)	Receivables Purchase Agreement, dated as of May 29, 2002, among Avista Receivables Corp., as Seller, Avista Corporation, as initial Servicer and Eaglefunding Capital Corporation, as Conduit Purchaser and Fleet National Bank, as Committed Purchaser and Fleet Securities, Inc. as Administrator.

4(g)	1-3701 (with Form 8-K dated November 15, 1999)	4	Rights Agreement, dated as of November 15, 1999, between the Company and the Bank of New York as successor Rights Agent.

4(h)	333-82502	4(c)	Exchange and Registration Rights Agreement, dated December 19, 2001 among the Company and Goldman, Sach & Co., BNY Capital Markets, Inc., Fleet Securities, Inc. and TD Securities (USA), Inc.

10(a)-l	2-13788	13(e)	Power Sales Contract (Rocky Reach Project) with Public Utility District No. 1 of Chelan County, Washington, dated as of November 14, 1957.

10(a)-2	2-60728	10(b)-1	Amendment to Power Sales Contract (Rocky Reach Project) with Public Utility District No. 1 of Chelan County, Washington, dated as of June 1, 1968.

*		Incorporated herein by reference.

**		Filed herewith.

117

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*

	With
	Registration	As
Exhibit	Number	Exhibit

10(b)-1	2-13421	13(d)	Power Sales Contract (Priest Rapids Project) with Public Utility District No. 2 of Grant County, Washington, dated as of May 22, 1956 (effective until November 1, 2005.

10(b)-2	2-60728	5(d)-1	Second Amendment to Power Sales Contract (Priest Rapids Project) with Public Utility District No. 2 of Grant County, Washington, dated as of December 19, 1977 (effective until November 1, 2005).

10(b)-3	1-3701 (with 2002 Form 10-K)	10(b)-3	Priest Rapids Project Product Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).

10(b)-4	1-3701 (with 2002 Form 10-K)	10(b)-4	Priest Rapids Project Reasonable Portion Power Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).

10(b)-5	1-3701 (with 2002 Form 10-K)	10(b)-5	Additional Product Sales Agreement (Priest Rapids Project) executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).

10(c)-1	2-60728	5(e)	Power Sales Contract (Wanapum Project) with Public Utility District No. 2 of Grant County, Washington, dated as of June 22, 1959 (effective until November 1, 2009).

10(c)-2	2-60728	5(e)-1	First Amendment to Power Sales Contract (Wanapum Project) with Public Utility District No. 2 of Grant County, Washington, dated as of December 19, 1977 (effective until November 1, 2009).

10(d)-1	2-60728	5(g)	Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.

10(d)-2	2-60728	5(g)-1	Amendment to Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.

*		Incorporated herein by reference.

**		Filed herewith.

118

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*

	With
	Registration	As
Exhibit	Number	Exhibit

10(d)-3	2-60728	5(h)	Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.

10(d)-4	2-60728	5(h)-1	Amendment to Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.

10(e)	2-60728	5(i)	Canadian Entitlement Exchange Agreement executed by Bonneville Power Administration Columbia Storage Power Exchange and the Company, dated as of August 13, 1964.

10(f)	2-60728	5(j)	Pacific Northwest Coordination Agreement, dated as of September 15, 1964.

10(g)-1	1-3701 (with September 30, 1985 Form 10-Q)	1	Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company, dated as of September 17, 1985, describing the settlement of Project 3 litigation.

10(g)-2	1-3701 (with September 30, 1985 Form 10-Q)	2	Agreement to Dismiss Claims and Covenant Not to Sue between the Washington Public Power Supply System and the Company, dated as of September 17, 1985, describing the settlement of Project 3 litigation with the Supply System.

10(g)-3	1-3701 (with September 30, 1985 Form 10-Q)	3	Agreement among Puget Sound Power & Light Company, the Company, Portland General Electric Company and PacifiCorp, dba Pacific Power & Light Company, agreeing to execute contemporaneously an irrevocable offer, to and for the benefit of the Bonneville Power Administration, dated as of September 17, 1985.

10(h)-1	2-66184	5(r)	Service Agreement (Natural Gas Storage Service), dated as of August 27, 1979, between the Company and Northwest Pipeline Corporation.

10(h)-2	2-60728	5(s)	Service Agreement (Liquefaction-Storage Natural Gas Service), dated as of December 7, 1977, between the Company and Northwest Pipeline Corporation.

*		Incorporated herein by reference.

**		Filed herewith.

119

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*

	With
	Registration	As
Exhibit	Number	Exhibit

10(h)-3	1-3701 (with 1989 Form 10-K)	10(k)-4	Amendment dated as of January 1, 1990, to Firm Transportation Agreement, dated as of June 15, 1988, between the Company and Northwest Pipeline Corporation.

10(h)-4	1-3701 (with 1992 Form 10-K)	10(k)-6	Firm Transportation Service Agreement, dated as of April 25, 1991, between the Company and Pacific Gas Transmission Company.

10(h)-5	1-3701 (with 1992 Form 10-K)	10(k)-7	Service Agreement Applicable to Firm Transportation Service, dated June 12, 1991, between the Company and Alberta Natural Gas Company Ltd.

10(i)-1	1-3701 (with Form 8-K for August 1976)	13(b)	Letter of Intent for the Construction and Ownership of Colstrip Units No. 3 and 4, dated as of April 16, 1974.

10(i)-2	1-3701 (with 1981 Form 10-K)	10(s)-7	Ownership and Operation Agreement for Colstrip Units No. 3 and 4, dated as of May 6, 1981.

10(i)-3	1-3701 (with 1981 Form 10-K	10(s)-2	Coal Supply Agreement for Colstrip Units No. 3 and 4 between The Montana Power Company, Puget Sound Power & Light Company, Portland General Electric Company, Pacific Power & Light Company, Western Energy Company and the Company, dated as of July 2, 1980.

10(i)-4	1-3701 (with 1981 Form 10-K)	10(s)-4	Amendment No. 1 to Coal Supply Agreement for Colstrip Units No. 3 and 4, dated as of July 10, 1981.

10(i)-5	1-3701 (with 1988 Form 10-K)	10(l)-5	Amendment No. 4 to Coal Supply Agreement for Colstrip Units No. 3 and 4, dated as of January 1, 1988.

10(j)	1-3701 (with 1986 Form 10-K)	10(n)-2	Lease Agreement between the Company and IRE-4 New York, Inc., dated as of December 15, 1986, relating to the Company’s central operating facility.

10(k)	1-3701 (with 1992 Form 10-K)	10(s)-1	Agreements for Purchase and Sale of Firm Capacity between Company and Portland General Electric Company dated March and June 1992.

10(l)	**		Power Purchase and Sale Agreement between Avista Corporation and Potlatch Corporation, dated as of July 22, 2003.

10(m)-1	1-3701 (with 1992 Form 10-K)	10(t)-8	Executive Deferral Plan of the Company. (***)

*		Incorporated herein by reference.

**		Filed herewith.

***		Management contracts or compensatory plans filed as exhibits by reference per Item 601(10)(iii) of Regulation S-K.

120

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*

	With
	Registration	As
Exhibit	Number	Exhibit

10(m)-2	1-3701 (with 1992 Form 10-K)	10(t)-10	The Company’s Unfunded Supplemental Executive Retirement Plan. (***)

10(m)-3	1-3701 (with 1992 Form 10-K)	10(t)-11	The Company’s Unfunded Supplemental Executive Disability Plan. (***)

10(m)-4	1-3701 (with 1992 Form 10-K)	10(t)-12	Income Continuation Plan of the Company. (***)

10(m)-5	333-03601	10	Non-Employee Director Stock Plan. (***)

10(m)-6	1-3701 (with 1998 Form 10-K)	10(q)-5	Long-Term Incentive Plan. (***)

10(m)-7	1-3701 (with 1999 Form 10-K)	10(q)-7	Employment Agreement between the Company and David J. Meyer. (***)

10(m)-8	1-3701 (with 2002 Form 10-K)	10(q)-8	Employment Agreement between the Company and Malyn K. Malquist. (***)

10(m)-9	333-47290	99.1	Non-Officer Employee Long-Term Incentive Plan

10(m)-10	1-3701(with 2002 Form 10-K)	10(q)-10	Form of Change of Control Agreement between the Company and its Executive Officers. (***) (1)

10(m)-11	1-3701 (with 2002 Form 10-K)	10(q)-11	Form of Change of Control Agreement between the Company and its Executive Officers. (***) (2)

10(m)-12	1-3701 (with 2002 Form 10-K)	10(q)-12	Form of Change of Control Agreement between the Company and its Executive Officers. (***) (3)

12	**		Statement re computation of ratio of earnings to fixed charges and preferred dividend requirements.

21	**		Subsidiaries of Registrant

31(a)	**		Certification of Chief Executive Officer

31(b)	**		Certification of Chief Financial Officer

32	****		Certification of Corporate Officers (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

*		Incorporated herein by reference.

**		Filed herewith.

***		Management contracts or compensatory plans filed as exhibits by reference per Item 601(10)(iii) of Regulation S-K.

****		Furnished herewith.

(1)		Applies for Karen S. Feltes and Kelly O. Norwood.

(2)		Applies for Malyn K. Malquist and, Scott L. Morris.

(3)		Applies for Gary G. Ely, David J. Meyer, David A. Brukardt, Christy M. Burmeister-Smith, Ronald R. Peterson, Terry L. Syms and Roger D. Woodworth. New agreements will be entered into during 2004 for these officers consistent with the Change of Control Agreements listed in exhibits 10(m)-10 and 10(m)-11.

121

EXHIBIT 3(b) BYLAWS OF AVISTA CORPORATION AS AMENDED FEBRUARY 6, 2004

BYLAWS OF AVISTA CORPORATION * * * * * ARTICLE I. OFFICES The principal office of the Corporation shall be in the City of Spokane, Washington. The Corporation may have such other offices, either within or without the State of Washington, as the Board of Directors may designate from time to time. ARTICLE II. SHAREHOLDERS SECTION 1. ANNUAL MEETING. The Annual Meeting of Shareholders shall be held on such date in the month of May in each year as determined by the Board of Directors for the purpose of electing directors and for the transaction of such other business as may come before the meeting. If the day fixed for the Annual Meeting shall be a legal holiday, such meeting shall be held on the next succeeding business day. SECTION 2. SPECIAL MEETINGS. Special meetings of the shareholders may be called by the President, the Chairman of the Board, the majority of the Board of Directors, the Executive Committee of the Board, and shall be called by the President at the request of the holders of not less than two-thirds (2/3) of the voting power of all shares of the voting stock voting together as a single class. Only those matters that are specified in the call of or request for a special meeting may be considered or voted at such meeting. SECTION 3. PLACE OF MEETING. Meetings of the shareholders, whether they be annual or special, shall be held at the principal office of the Corporation, unless a place, either within or without the state, is otherwise designated by the Board of Directors in the notice provided to shareholders of such meetings. SECTION 4. NOTICE OF MEETING. Written or printed notice of every meeting of shareholders shall be mailed by the Corporate Secretary or any Assistant Corporate Secretary, not less than ten (10) nor more than fifty (50) days before the date of the meeting, to each holder of record of stock entitled to vote at the meeting. The notice shall be mailed to each shareholder at his last known post office address, provided, however, that if a shareholder is present at a meeting, or waives notice thereof in writing before or after the meeting, the notice of the meeting to such shareholders shall be unnecessary. SECTION 5. VOTING OF SHARES. At every meeting of shareholders each holder of stock entitled to vote thereat shall be entitled to one vote for each share of such stock held in his name on the books of the Corporation, subject to the provisions of applicable law and the Articles of Incorporation, and may vote and otherwise act in person or by proxy; provided, however, that in elections of directors there shall be cumulative voting as provided by law and by the Articles of Incorporation.

SECTION 6. QUORUM. The holders of a majority of the number of outstanding shares of stock of the Corporation entitled to vote thereat, present in person or by proxy at any meeting, shall constitute a quorum, but less than a quorum shall have power to adjourn any meeting from time to time without notice. No change shall be made in this Section 6 without the affirmative vote of the holders of at least a majority of the outstanding shares of stock entitled to vote. SECTION 7. CLOSING OF TRANSFER BOOKS OR FIXING OF RECORD DATE. For the purposes of determining shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or shareholders entitled to receive payment of any dividend, or in order to make a determination of shareholders for any other proper purpose, the Board of Directors of the Corporation may provide that the stock transfer books shall be closed for a stated period but not to exceed, in any case, fifty (50) days. If the stock transfer books shall be closed for the purpose of determining shareholders entitled to notice of or to vote at a meeting of shareholders, such books shall be closed for at least ten (10) days immediately preceding such meeting. In lieu of closing the stock transfer books, the Board of Directors may fix in advance a date as the record date for any such determination of shareholders, such date in any case to be not more than seventy (70) days and, in case of a meeting of shareholders, not less than ten (10) days prior to the date on which the particular action, requiring such determination of shareholders, is to be taken. When a determination of shareholders entitled to vote at any meeting of shareholders has been made as provided in this section, such determination shall apply to any adjournment thereof. SECTION 8. VOTING RECORD. The officer or agent having charge of the stock transfer books for shares of the Corporation shall make, at least ten (10) days before each meeting of shareholders, a complete record of the shareholders entitled to vote at such meeting or any adjournment thereof, arranged in alphabetical order, with the address of and the number of shares held by each, which record, for a period of ten (10) days prior to such meeting, shall be kept on file at the registered office of the Corporation. Such record shall be produced and kept open at the time and place of the meeting and shall be subject to the inspection of any shareholder during the whole time of the meeting for the purposes thereof. SECTION 9. CONDUCT OF PROCEEDINGS. The Chairman of the Board shall preside at all meetings of the shareholders. In the absence of the Chairman, the President shall preside and in the absence of both, the Executive Vice President shall preside. The members of the Board of Directors present at the meeting may appoint any officer of the Corporation or member of the Board to act as Chairman of any meeting in the absence of the Chairman, the President, or Executive Vice President. The Corporate Secretary of the Corporation, or in his absence, an Assistant Corporate Secretary, shall act as Secretary at all meetings of the shareholders. In the absence of the Corporate Secretary or Assistant Corporate Secretary at any meeting of the shareholders, the presiding officer may appoint any person to act as Secretary of the meeting. SECTION 10. PROXIES. At all meetings of shareholders, a shareholder may vote in person or by proxy. A shareholder or the shareholder's duly authorized agent or attorney-in-fact may appoint a proxy by (i) executing a proxy in writing or (ii) transmitting or authorizing the transmission of an electronic proxy in any manner permitted by law. Such proxy shall be filed with the Corporate Secretary of the Corporation before or at the time of the meeting. 2

ARTICLE III. BOARD OF DIRECTORS SECTION 1. GENERAL POWERS. The powers of the Corporation shall be exercised by or under the authority of the Board of Directors, except as otherwise provided by the laws of the State of Washington and the Articles of Incorporation. SECTION 2. NUMBER AND TENURE. The number of Directors of the Corporation shall be eleven (11); provided, however, that if the right to elect a majority of the Board of Directors shall have accrued to the holders of the Preferred Stock as provided in paragraph (1) of subdivision (j) of Article THIRD of the Articles of Incorporation, then, during such period as such holders shall have such right, the number of directors may exceed eleven (11). Directors shall be divided into three classes, as nearly equal in number as possible. At each Annual Meeting of Shareholders, directors elected to succeed those directors whose terms expire shall be elected for a term of office to expire at the third succeeding Annual Meeting of Shareholders after their election. Notwithstanding the foregoing, directors elected by the holders of the Preferred Stock in accordance with paragraph (1) of subdivision (j) of Article THIRD of the Articles of Incorporation shall be elected for a term which shall expire not later than the next Annual Meeting of Shareholders. All directors shall hold office until the expiration of their respective terms of office and until their successors shall have been elected and qualified. SECTION 3. REGULAR MEETINGS. The regular annual meeting of the Board of Directors shall be held immediately following the adjournment of the annual meeting of the shareholders or as soon as practicable after said annual meeting of shareholders. But, in any event, said regular annual meeting of the Board of Directors must be held on either the same day as the annual meeting of shareholders or the next business day following said annual meeting of shareholders. At such meeting the Board of Directors, including directors newly elected, shall organize itself for the coming year, shall elect officers of the Corporation for the ensuing year, and shall transact all such further business as may be necessary or appropriate. The Board shall hold regular quarterly meetings, without call or notice, on such dates as determined by the Board of Directors. At such quarterly meetings the Board of Directors shall transact all business properly brought before the Board. SECTION 4. SPECIAL MEETINGS. Special meetings of the Board of Directors may be called by or at the request of the Chairman of the Board, the President, the Executive Vice President or any three (3) directors. Notice of any special meeting shall be given to each director at least two (2) days in advance of the meeting. SECTION 5. EMERGENCY MEETINGS. In the event of a catastrophe or a disaster causing the injury or death to members of the Board of Directors and the principal officers of the Corporation, any director or officer may call an emergency meeting of the Board of Directors. Notice of the time and place of the emergency meeting shall be given not less than two (2) days prior to the meeting and may be given by any available means of communication. The director or directors present at the meeting shall constitute a quorum for the purpose of filling vacancies determined to exist. The directors present at the emergency meeting may appoint such officers as necessary to fill any vacancies determined to exist. All appointments under this section shall be 3

temporary until a special meeting of the shareholders and directors is held as provided in these Bylaws. SECTION 6. CONFERENCE BY TELEPHONE. The members of the Board of Directors, or of any committee created by the Board, may participate in a meeting of the Board or of the committee by means of a conference telephone or similar communication equipment by means of which all persons participating in the meeting can hear each other at the same time. Participation in a meeting by such means shall constitute presence in person at a meeting. SECTION 7. QUORUM. A majority of the number of directors shall constitute a quorum for the transaction of business at any meeting of the Board of Directors. The action of a majority of the directors present at a meeting at which a quorum is present shall be the action of the Board. SECTION 8. ACTION WITHOUT A MEETING. Any action required by law to be taken at a meeting of the directors of the Corporation, or any action which may be taken at a meeting of the directors or of a committee, may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the directors, or all of the members of the committee, as the case may be. Such consent shall have the same effect as a unanimous vote. SECTION 9. VACANCIES. Subject to the provisions of paragraph (1) of subdivision (j) of Article THIRD of the Articles of Incorporation, (a) any vacancy occurring in the Board of Directors may be filled by the affirmative vote of a majority of the remaining directors though less than a quorum of the Board of Directors and any director so elected to fill a vacancy shall be elected for the unexpired term of his or her predecessor in office and (b) any directorship to be filled by reason of an increase in the number of directors may be filled by the Board of Directors for a term of office continuing only until the next election of directors by the shareholders. SECTION 10. RESIGNATION OF DIRECTOR. Any director or member of any committee may resign at any time. Such resignation shall be made in writing and shall take effect at the time specified therein. If no time is specified, it shall take effect from the time of its receipt by the Corporate Secretary, who shall record such resignation, noting the day, hour and minute of its reception. The acceptance of a resignation shall not be necessary to make it effective. SECTION 11. REMOVAL. Subject to the provisions of paragraph (1) of subdivision (j) of Article THIRD of the Articles of Incorporation, any director may be removed from office at any time, but only for cause and only by the affirmative vote of the holders of at least a majority of the voting power of all of the shares of capital stock of the Corporation entitled generally to vote in the election of directors voting together as a single class, at a meeting of shareholders called expressly for that purpose; provided, however, that if less than the entire Board of Directors is to be removed, no one of the directors may be removed if the votes cast against the removal of such director would be sufficient to elect such director if then cumulatively voted at an election of the class of directors of which such director is a part. No decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director. SECTION 12. ORDER OF BUSINESS. The Chairman of the Board shall preside at all meetings of the directors. In the absence of the Chairman, the officer or member of the Board designated by the Board of Directors shall preside. At meetings of the Board of Directors, business shall be 4

transacted in such order as the Board may determine. Minutes of all proceedings of the Board of Directors, or committees appointed by it, shall be prepared and maintained by the Corporate Secretary or an Assistant Corporate Secretary and the original shall be maintained in the principal office of the Corporation. SECTION 13. NOMINATION OF DIRECTORS. Subject to the provisions of paragraph (1) of subdivision (j) of Article THIRD of the Articles of Incorporation, nominations for the election of directors may be made by the Board of Directors, or a nominating committee appointed by the Board of Directors, or by any holder of shares of the capital stock of the Corporation entitled generally to vote in the election of directors (such stock being hereinafter in this Section called "Voting Stock"). However, any holder of shares of the Voting Stock may nominate one or more persons for election as directors at a meeting only if written notice of such shareholder's intent to make such nomination or nominations has been given, either by personal delivery or by United States mail, postage prepaid, to the Corporate Secretary not later than (i) with respect to an election to be held at an annual meeting of shareholders, ninety (90) days in advance of such meeting and (ii) with respect to an election to be held at a special meeting of shareholders for the election of directors, the close of business on the seventh day following the date on which notice of such meeting is first given to shareholders. Each such notice shall set forth: (a) the name and address of the shareholder who intends to make the nomination and of the person or persons to be nominated; (b) a representation that such shareholder is a holder of record of shares of the Voting Stock of the Corporation and intends to appear in person or by proxy at the meeting to nominate the person or persons identified in the notice; (c) a description of all arrangements or understandings between such shareholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by such shareholder; (d) such other information regarding each nominee proposed by such shareholder as would be required to be included in a proxy statement under the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder (or any subsequent revisions replacing such Act, rules or regulations) if the nominee(s) had been nominated, or were intended to be nominated, by the Board of Directors; and (e) the consent of each nominee to serve as a Director of the Corporation if so elected. The Chairman of the meeting may refuse to acknowledge the nomination of any person not made in compliance with the foregoing procedure. SECTION 14. PRESUMPTION OF ASSENT. A director of the Corporation who is present at a meeting of the Board of Directors, or of a committee thereof, at which action on any corporate matter is taken, shall be presumed to have assented to the action unless his dissent shall be entered in the minutes of the meeting or unless he shall file his written dissent to such action with the person acting as the Secretary of the meeting before the adjournment thereof or shall forward such dissent by registered mail to the Corporate Secretary of the Corporation immediately after the adjournment of the meeting. Such right to dissent shall not apply to a director who voted in favor of such action. SECTION 15. RETIREMENT OF DIRECTORS. Directors who are seventy (70) years of age or more shall retire from the Board effective at the conclusion of the Annual Meeting of Shareholders held in the year in which their term expires, and any such Director shall not be nominated for election at such Annual Meeting. The foregoing shall be effective in 1988 and 5

thereafter as to any Director who is seventy (70) years of age or more during the year in which his or her term expires. ARTICLE IV. EXECUTIVE COMMITTEE AND ADDITIONAL COMMITTEES SECTION 1. APPOINTMENT. The Board of Directors, by resolution adopted by a majority of the Board, may designate three or more of its members to constitute an Executive Committee. The designation of such committee and the delegation thereto of authority shall not operate to relieve the Board of Directors, or any member thereof, of any responsibility imposed by law. SECTION 2. AUTHORITY. The Executive Committee, when the Board of Directors is not in session, shall have and may exercise all of the authority of the Board of Directors including authority to authorize distributions or the issuance of shares of stock, except to the extent, if any, that such authority shall be limited by the resolution appointing the Executive Committee or by law. SECTION 3. TENURE. Each member of the Executive Committee shall hold office until the next regular annual meeting of the Board of Directors following his designation and until his successor is designated as a member of the Executive Committee. SECTION 4. MEETINGS. Regular meetings of the Executive Committee may be held without notice at such times and places as the Executive Committee may fix from time to time by resolution. Special meetings of the Executive Committee may be called by any member thereof upon not less than two (2) days notice stating the place, date and hour of the meeting, which notice may be written or oral. Any member of the Executive Committee may waive notice of any meeting and no notice of any meeting need be given to any member thereof who attends in person. SECTION 5. QUORUM. A majority of the members of the Executive Committee shall constitute a quorum for the transaction of business at any meeting thereof. Actions by the Executive Committee must be authorized by the affirmative vote of a majority of the appointed members of the Executive Committee. SECTION 6. ACTION WITHOUT A MEETING. Any action required or permitted to be taken by the Executive Committee at a meeting may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the members of the Executive Committee. SECTION 7. PROCEDURE. The Executive Committee shall select a presiding officer from its members and may fix its own rules of procedure which shall not be inconsistent with these Bylaws. It shall keep regular minutes of its proceedings and report the same to the Board of Directors for its information at a meeting thereof held next after the proceedings shall have been taken. 6

SECTION 8. COMMITTEES ADDITIONAL TO EXECUTIVE COMMITTEE. The Board of Directors may, by resolution, designate one or more other committees, each such committee to consist of two (2) or more of the directors of the Corporation. A majority of the members of any such committee may determine its action and fix the time and place of its meetings unless the Board of Directors shall otherwise provide. ARTICLE V. OFFICERS SECTION 1. NUMBER. The Board of Directors shall appoint one of its members Chairman of the Board. The Board of Directors shall also appoint a Chief Executive Officer and a President, one of whom may also serve as Chairman, one or more Vice Presidents, a Corporate Secretary, and a Treasurer. The Board of Directors may from time to time appoint such other officers as the Board deems appropriate. The same person may be appointed to more than one office. The Chief Executive Officer shall have the authority to appoint such assistant officers as might be deemed appropriate. SECTION 2. ELECTION AND TERM OF OFFICE. The officers of the Corporation shall be elected by the Board of Directors at the annual meeting of the Board. Each officer shall hold office until his successor shall have been duly elected and qualified. SECTION 3. REMOVAL. Any officer or agent may be removed by the Board of Directors whenever in its judgment the best interests of the Corporation will be served thereby, but such removal shall be without prejudice to contract rights, if any, of the person so removed. Election or appointment of an officer or agent shall not of itself create contract rights. SECTION 4. VACANCIES. A vacancy in any office because of death, resignation, removal, disqualification or otherwise may be filled by the Board of Directors for the unexpired portion of the term. SECTION 5. POWERS AND DUTIES. The officers shall have such powers and duties as usually pertain to their offices, except as modified by the Board of Directors, and shall have such other powers and duties as may from time to time be conferred upon them by the Board of Directors. ARTICLE VI. CONTRACTS, CHECKS AND DEPOSITS SECTION 1. CONTRACTS. The Board of Directors may authorize any officer or officers or agents, to enter into any contract or to execute and deliver any instrument in the name of and on behalf of the Corporation, and such authority may be general or confined to specific instances. SECTION 2. CHECKS/DRAFTS/NOTES. All checks, drafts or other orders for the payment of money, notes or other evidences of indebtedness issued in the name of the Corporation shall be signed by such officer or officers, agent or agents of the Corporation and in such manner as shall from time to time be determined by resolution of the Board of Directors. 7

SECTION 3. DEPOSITS. All funds of the Corporation not otherwise employed shall be deposited from time to time to the credit of the Corporation in such banks, trust companies or other depositories as the Board of Directors by resolution may select. ARTICLE VII. CERTIFICATES FOR SHARES AND THEIR TRANSFER SECTION 1. CERTIFICATES FOR SHARES. Certificates representing shares of the Corporation shall be in such form as shall be determined by the Board of Directors and shall contain such information as prescribed by law. Such certificates shall be signed by the President or a Vice President and by either the Corporate Secretary or an Assistant Corporate Secretary, and sealed with the corporate seal or a facsimile thereof. The signatures of such officers upon a certificate may be facsimiles. The name and address of the person to whom the shares represented thereby are issued, with the number of shares and date of issue, shall be entered on the stock transfer books of the Corporation. All certificates surrendered to the Corporation for transfer shall be cancelled and no new certificate shall be issued until the former certificate for a like number of shares shall have been surrendered and cancelled, except that in case of a lost, destroyed or mutilated certificate a new one may be issued therefor upon such terms and indemnity to the Corporation as the Board of Directors may prescribe. SECTION 2. TRANSFER OF SHARES. Transfer of shares of the Corporation shall be made only on the stock transfer books of the Corporation by the holder of record thereof or by his legal representative, who shall furnish proper evidence of authority to transfer, or by his attorney thereunto authorized by power of attorney duly executed and filed with the Corporate Secretary of the Corporation, and on surrender for cancellation of the certificate for such shares. The person in whose name shares stand on the books of the Corporation shall be deemed by the Corporation to be the owner thereof for all purposes. The Board of Directors shall have power to appoint one or more transfer agents and registrars for transfer and registration of certificates of stock. ARTICLE VIII. CORPORATE SEAL The seal of the Corporation shall be in such form as the Board of Directors shall prescribe. ARTICLE IX. INDEMNIFICATION SECTION 1. INDEMNIFICATION OF DIRECTORS AND OFFICERS. The Corporation shall indemnify and reimburse the expenses of any person who is or was a director, officer, agent or employee of the Corporation or is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee, or agent of another enterprise or employee benefit plan to the extent permitted by and in accordance with Article SEVENTH of the Company's Articles of Incorporation and as permitted by law. 8

SECTION 2. LIABILITY INSURANCE. The Corporation shall have the power to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee, or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, other enterprise, or employee benefit plan against any liability asserted against him and incurred by him in any such capacity or arising out of his status as such, whether or not the Corporation would have the power to indemnify him against such liability under the laws of the State of Washington. SECTION 3. RATIFICATION OF ACTS OF DIRECTOR, OFFICER OR SHAREHOLDER. Any transaction questioned in any shareholders' derivative suit on the ground of lack of authority, defective or irregular execution, adverse interest of director, officer or shareholder, nondisclosure, miscomputation, or the application of improper principles or practices of accounting may be ratified before or after judgment, by the Board of Directors or by the shareholders in case less than a quorum of directors are qualified; and, if so ratified, shall have the same force and effect as if the questioned transaction had been originally duly authorized, and said ratification shall be binding upon the Corporation and its shareholders and shall constitute a bar to any claim or execution of any judgment in respect of such questioned transaction. ARTICLE X. AMENDMENTS Except as to Section 6 of Article II of these Bylaws, the Board of Directors may alter or amend these Bylaws at any meeting duly held, the notice of which includes notice of the proposed amendment. Bylaws adopted by the Board of Directors shall be subject to change or repeal by the shareholders; provided, however, that Section 2 of Article II, (other than the provision thereof specifying the number of Directors of the Corporation), and Sections 9, 11 and 13 of Article III and this proviso shall not be altered, amended or repealed, and no provision inconsistent therewith or herewith shall be included in these Bylaws, without the affirmative votes of the holders of at least eighty percent (80%) of the voting power of all the shares of the Voting Stock voting together as a single class. 9

EXHIBIT 10(1) POWER PURCHASE AND SALE AGREEMENT BETWEEN AVISTA CORPORATION AND POTLATCH CORPORATION INDEX TO SECTIONS Section Page - ------- ---- 1. Definitions ................................................................................ 2 2. Representations............................................................................. 6 3. Term of Agreement .......................................................................... 7 4. Power Purchases (Power Deliveries to Avista) ............................................... 9 5. Power Sales (Power Deliveries to Potlatch).................................................. 12 6. Operation of Facility....................................................................... 13 7. Scheduling.................................................................................. 15 8. Billing and Payments........................................................................ 15 9. Metering.................................................................................... 18 10. Termination of Agreement.................................................................... 18 11. Forced Outage and Force Majeure............................................................. 19 12. Indemnity................................................................................... 20 13. Limitation of Liability .................................................................... 22 14. Insurance................................................................................... 23 15 Assignment ................................................................................. 25 16. No Unspecified Third Party Beneficiaries.................................................... 25 17. No Transmission Rights...................................................................... 25 18. Benefits for Renewable Fuels................................................................ 25 19. Default..................................................................................... 26 20. Release by Avista .......................................................................... 27 21. Release by Potlatch......................................................................... 27 22. Governmental Authority ..................................................................... 28 23. Several Obligations......................................................................... 28 24. Implementation ............................................................................. 28 25. Non-Waiver ................................................................................. 28 26. Entire Agreement and Amendment ............................................................. 29 27. Venue, Attorneys Fees and Choice of Law..................................................... 29 28. Compliance with Laws ....................................................................... 29 29. Confidentiality............................................................................. 30 30. Notices..................................................................................... 32 31. Settlement of Litigation.................................................................... 33 32. Exhibits.................................................................................... 33

This Power Purchase and Sale Agreement ("Agreement") is entered into as of this 22nd day of July, 2003, by and between POTLATCH CORPORATION ("Potlatch"), a corporation organized and existing under the laws of the State of Delaware, and AVISTA CORPORATION ("Avista") of Spokane, Washington, a corporation organized and existing under the laws of the State of Washington, hereinafter sometimes referred to collectively as "Parties" and individually as "Party." W I T N E S S E T H: WHEREAS, Potlatch owns and operates pulp, paperboard, tissue and wood products manufacturing plants in Nez Perce County, Idaho, herein collectively referred to as the "Lewiston Plant;" WHEREAS, Avista is presently supplying electric power to Potlatch at the Lewiston Plant; WHEREAS, Potlatch owns and operates four thermal electric generating units located at the Lewiston Plant; WHEREAS, there is pending before the United States District Court for the District of Idaho, Case No. CV02-543-C-EJL, a complaint by Potlatch against Avista; WHEREAS, there is pending before the Idaho Public Utilities Commission, Case No. AVU-E-02-08, a complaint by Potlatch against Avista; WHEREAS, the Parties desire to settle all litigation pending between them, pursuant to the terms of this Agreement; WHEREAS, Potlatch desires to sell, and Avista desires to purchase, the Net Facility Power pursuant to the terms of this Agreement; and WHEREAS, the Parties intend that, except for self generation by Potlatch to serve its own Load, Avista shall be the sole purchaser of Net Facility Power and the sole supplier for Potlatch Load. NOW, THEREFORE, in consideration of the mutual covenants and agreements hereinafter set forth, the Parties agree as follows: -1-

1. DEFINITIONS. In addition to words defined elsewhere in this Agreement as signified by initial capitalization, whenever used in this Agreement, exhibits and attachments hereto, the terms below shall have the following meanings: (a) "BANKRUPT" With respect to either Party, when such Party (i) files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it and such petition is not dismissed within sixty (60) days after it is filed, (ii) makes an assignment or any general arrangement for the benefit of creditors, (iii) otherwise becomes bankrupt or insolvent (however evidenced), (iv) has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets, or (v) is generally unable to pay its debts as they fall due. (b) "BASE GENERATION AMOUNT(S)" That amount of Net Facility Power, expressed in megawatt-hours, less any Incremental Generation Amount, for each hour and delivered by Potlatch to Avista. The maximum Base Generation Amount for any July 1st through June 30th period (any such period referred to as the "Operating Year") shall be 543,120 megawatt-hours during a normal year or 544,608 megawatt-hours during a leap year. (c) "BASE PERIOD DEMAND" The average kVa supplied during the 30-minute period of maximum electricity use during the portion of the billing period up to and including the point where the maximum Base Generation Amount is reached. Demand shall be calculated using a rolling 30-minute demand interval with 5-minute sub-intervals. (d) "BILLING PERIOD" That period which begins at 0000 hours on the first day of any month during the term of the Agreement and ends at 2400 hours on the last day of such month. (e) "EFFECTIVE DATE" The date this Agreement becomes effective pursuant to Section 3(a) of this Agreement. -2-

(f) "EXCESS GENERATION AMOUNT(S)" That amount of Net Facility Power, expressed in megawatt-hours, generated by the Facility, less any Incremental Generation Amount, for each hour that is in excess of the maximum Base Generation Amount of 543,120 megawatt-hours for any Operating Year during a normal year or 544,608 megawatt-hours during a leap year. (g) "EXCESS PERIOD DEMAND" The average kVa supplied during the 30-minute period of maximum electricity use during the portion of the billing period after the point where the maximum Base Generation Amount is reached. Demand shall be calculated using a rolling 30-minute demand interval with 5-minute sub-intervals. (h) "FACILITY" The electric generating facilities, including all equipment and structures necessary to generate and supply power, more particularly described at Exhibit C (Description of the Facility). (i) "FACILITY SERVICE POWER" Electric power used by the Facility during its operation for station service, including, but not necessarily limited to pumping, generator excitation and cooling, as further defined in Exhibit A. (j) "FORCED OUTAGE" Any outage that either fully or partially curtails the electrical output of the Facility caused by mechanical or electrical equipment failure, plant related structural failure, or unscheduled maintenance required to be performed to prevent equipment failure. (k) "GOOD INDUSTRY PRACTICE(S)" Good industry practice as defined in the Interconnection Agreement, which definition is adopted by reference for purposes of this Agreement as though set forth in full herein. (l) "GOVERNMENTAL AUTHORITY" Any federal, state or local government, political subdivision thereof or other governmental, regulatory, quasi-governmental, judicial, public or statutory instrumentality, authority, body, agency, department, bureau, or entity or any arbitrator with authority to bind a Party at law. -3-

(m) "GOVERNMENTAL RULE(S)" Any law, rule, regulation, ordinance, order, code, permit, judgment, or similar form of decision of any Governmental Authority having the effect of law or regulation. (n) "HEAVY LOAD HOURS" ("HLH") The hours ending 0700 through 2200 Pacific Prevailing Time, Monday through Saturday inclusive, excluding NERC holidays. (o) "INCREMENTAL GENERATION AMOUNT(S)" The amount of Net Facility Power expressed in megawatt-hours for each hour that is in excess of the Nominal Generation Amount. (p) "INDEX" The daily price expressed in dollars per megawatt-hour for firm energy as published by Dow Jones for the Mid-Columbia point of delivery for the applicable Heavy Load Hours or Light Load Hours. If prices for any hour are not published for the Mid-Columbia point of delivery, Avista may extrapolate such prices using reasonable commercial judgment; provided that Avista shall notify Potlatch in writing of any such extrapolation and the basis thereof. In the absence of this index, a comparable publication of firm energy prices at Mid-Columbia shall be used as mutually agreed to by the Parties. (q) "INTERCONNECTION AGREEMENT" The Generation Interconnection Agreement between Potlatch and Avista. (r) "LIGHT LOAD HOURS" ("LLH") All hours other than Heavy Load Hours. (s) "LOAD" The hourly energy, expressed in megawatt-hours, consumed at Potlatch's Lewiston Plant excluding Facility Service Power and Losses. (t) "LOSSES" Electric power used by the Facility during its operation to transform or transmit electric power to Points of Delivery. Losses shall be deemed to be 200 kW. (u) "NET FACILITY POWER" Electric power generated by the Facility and measured at the point of generation less Facility Service Power and less electric power used to compensate for Losses. -4-

If any adjustment to the meter readings is required hereunder to determine the Net Facility Power actually delivered to the Points of Delivery, the electric power which the Parties agree is used by the Facility in its operation and losses to the Points of Delivery is set forth in Exhibit A. (v) "NOMINAL GENERATION AMOUNT(S)" A calculation to be performed daily and shall be the same for each hour of that day, but only used when the Parties execute a Power Purchase of Incremental Generation Amounts, to be determined as follows: The amount of electric power generated by the Facility, expressed in megawatts per hour, determined by averaging the hourly Net Facility Power generation amounts less any Power Purchases of Incremental Generation Amounts for each hour for the immediate past period counting backwards beginning two (2) days prior to the current day and consisting of thirty (30) days, not necessarily contiguous, in which the average Net Facility Power was greater than 720 megawatt-hours for each of these days (30 aMW). The Nominal Generation Amount shall be not less than fifty-five (55) megawatts per hour. The Nominal Generation Amount shall be calculated as of the date of any transaction for a Power Purchase of Incremental Generation Amounts and shall be the same amount for each hour during the term of such transaction. If the Power Purchase transaction for an Incremental Generation Amount is a prescheduled transaction, then the Nominal Generation Amount calculation will serve to set the Base Generation Amount or Excess Generation Amount for the duration of the Incremental Generation Transaction Period, and any Net Facility Power above that amount shall be deemed the Incremental Generation Amount. The "Incremental Generation Transaction Period" shall be all hours of each of the days specified for delivery of Incremental Generation Amounts that are part of a single prescheduled transaction which is also the first such transaction executed by the Parties for Incremental Generation Amount deliveries during those same days. The Incremental Generation Amount shall be set equal to zero for the purpose of calculating Base Generation Amounts (as defined in Subsection 1(b)), Excess Generation Amounts (as defined in Subsection 1(f)), and Nominal Generation Amounts during those hours in which no Incremental Generation Amount is purchased by Avista, in accordance with Section 4. (w) "PACIFIC PREVAILING TIME" The Pacific Time, either standard time or daylight savings time, whichever is in effect at the relevant time. -5-

(x) "POINTS OF DELIVERY" The locations where the Facility is electrically interconnected with Avista's electrical system (y) "POWER PURCHASE(S)" Power transactions in which Avista purchases from Potlatch electric power generated by the Facility. (z) "POWER SALE(S)" Power transactions in which Potlatch purchases electric power from Avista. (aa) "TRUE-UP PROCESS" That process described in Section 3(f) for settling obligations incurred under this Agreement in the event of termination. (bb) "WEEK" The period of time beginning at 0000 hours on any Sunday during the term of this Agreement and ending at 2400 hours on the immediately subsequent Saturday. 2. REPRESENTATIONS. (a) Potlatch represents that it is the sole owner of the Facility, that all licenses or permits required for the operation thereof have been or will be obtained in the name of, or assigned to Potlatch, prior to the Effective Date and that the undersigned is authorized to execute this Agreement in Potlatch's behalf. Potlatch also represents that each generating unit described at Exhibit C (Description of the Facility) is a qualifying facility ("Qualifying Facility") pursuant to law and the rules of the Federal Energy Regulatory Commission. (b) Each Party represents and warrants to the other: (1) subject to the provisions of Subsections 3(b) and 3(c), it has all authorizations from Governmental Authority necessary for it to legally perform its obligations under this Agreement or will obtain such authorizations in a timely manner prior to the time at which any performance by it requiring such authorizations becomes due; (2) the execution, delivery and performance of this Agreement are within its statutory and corporate powers, have been duly authorized by all necessary action and do not violate any of -6-

the terms or conditions in its governing documents, any material contract to which it is a party or by which it or any of its properties may be affected or bound, or any Governmental Rule applicable to it; (3) this Agreement constitutes a legal, valid and binding obligation of the Party enforceable against it in accordance with its terms, and the Party has all rights such that it can and shall perform its obligations to the other Party in conformance with the terms and conditions of this Agreement, subject to bankruptcy, insolvency, reorganization and other laws affecting creditor's rights generally and general principles of equity; (4) no Bankruptcy is pending against it, being contemplated by it, or to its knowledge threatened against it; and (5) subject to the provisions of Subsections 3(b) and 3(c) there are no suits, proceedings, judgments, rulings or orders by or before any Governmental Authority that could reasonably be expected to have a material adverse effect on its ability to perform this Agreement. 3. TERM OF AGREEMENT. (a) Subject to the provisions of this Section 3, this Agreement shall be effective at 0000 hours on July 1, 2003. Power Purchases and Sales pursuant to this Agreement shall be deemed to have commenced upon the Effective Date. (b) Potlatch and Avista shall jointly petition the Idaho Public Utility Commission ("IPUC") for an order approving this Agreement. This Agreement is conditioned upon approval by the IPUC of the following provisions: (1) approval of the Agreement as a settlement of all known existing disputes between the Parties, without precedential value and without prejudice to the Parties' positions on similar issues in the future; (2) direct assignment of all Power Purchase costs paid by Avista to Potlatch under this Agreement to Avista's Idaho operations; and -7-

(3) deferral and recovery of 100% of all Power Purchase costs paid by Avista to Potlatch under this Agreement to Avista's Idaho Power Cost Adjustment ("PCA") or otherwise recovered by Avista through base rates. In the event that the IPUC does not approve the Agreement or approves it upon conditions that are unacceptable to Avista or Potlatch in their sole discretion, the Agreement shall terminate upon the date of such order, subject to the True-Up Process described below. After IPUC initial approval of this Agreement, should the IPUC revise regulatory treatment of the Agreement in a manner unacceptable to Avista or Potlatch in their sole discretion, the Agreement shall terminate upon the date of such order, without being subject to the True-Up Process described below. (c) This Agreement is conditioned upon the execution and filing with the Federal Energy Regulatory Commission ("FERC") of the Interconnection Agreement between Avista and Potlatch within sixty (60) days of the Effective Date of this Agreement. In the event that FERC does not approve the Interconnection Agreement or approves it upon conditions that are unacceptable to Avista or Potlatch in their sole discretion, this Agreement shall terminate upon the date of such order, subject to the True-Up Process described below. (d) In the event that any third person requests rehearing of an order of the IPUC that approves the Agreement or appeals an order of the IPUC that approves this Agreement to a court of competent jurisdiction, the Agreement shall terminate upon the date of an order on rehearing or order on appeal that disapproves the Agreement or approves it upon conditions that are unacceptable to Avista or Potlatch in their sole discretion, subject to the True-Up Process described below. (e) In the event this Agreement is not finally approved by December 31, 2003, neither Party shall have any further obligations hereunder, and this Agreement shall terminate, subject to the True-Up Process described below. -8-

(f) TRUE-UP PROCESS: In the event that this Agreement is terminated pursuant to Subsections 3(b) through 3(e) except as otherwise provided, the Parties agree to refund amounts paid and received hereunder that exceed amounts that would have been paid and received had this Agreement not taken effect from the Effective Date to the date of termination ("Interim Period"). Such refund amounts shall be calculated as the difference between the amounts paid and received hereunder and the amounts that would have been paid and received if Potlatch had utilized its Facility to generate electricity for its own Load at the Lewiston Plant during the Interim Period and purchased its remaining electricity requirements at Schedule 25 rates. If the amount of electricity generated by the Facility exceeds the Load at the Lewiston Plant during the Interim Period, Avista shall be deemed to have purchased the amount in excess of the Load, and such purchase shall be priced at the energy rates contained in Schedule 25, calculated for each month of the Interim Period. Incremental Generation Amounts and prices paid therefor during the Interim Period shall not be subject to this True-Up Process. (g) This Agreement shall terminate at 2400 hours on June 30, 2013. 4. POWER PURCHASES (POWER DELIVERIES TO AVISTA). (a) Potlatch shall sell and deliver and Avista shall purchase and accept delivery of Net Facility Power in accordance with the terms and conditions of this Agreement. Such purchase by Avista shall satisfy Avista's obligation to purchase power from the Facility pursuant to the Public Utility Regulatory Policies Act for the term of this Agreement. All prices for Power Purchases described in this Section 4 are all inclusive, and Avista shall not impose any charges or set-offs for transmission, losses, ancillary services or other similar costs. (b) Avista shall pay $42.92 per megawatt-hour for the Base Generation Amount generated by the Facility each hour and delivered by Potlatch to Avista. (c) Avista shall pay eighty-five percent (85%) of the applicable (HLH or LLH) Index price per megawatt-hour, up to a maximum price paid to Potlatch of $55 per megawatt-hour, for -9-

Excess Generation Amounts generated by the Facility each hour and delivered by Potlatch to Avista. Potlatch may choose to not schedule and deliver Excess Generation Amounts to Avista and instead supply electric power to the Load during any Week; provided, however, Potlatch shall notify Avista of its election in accordance with Subsection 7(a) and such election shall be binding for the Week. In the event Potlatch does not notify Avista of its election in accordance with Subsection 7(a), Potlatch shall be deemed to have elected to supply the power to its Load for the Week. Avista shall not pay Potlatch for such Excess Generation that is not scheduled and delivered to Avista. (d) The maximum Excess Generation Amount that Avista shall purchase for any Operating Year shall be 43,800 megawatt-hours. Excess Generation Amounts in excess of the maximum Excess Generation Amount shall be deemed used to serve Potlatch Load. (e) Avista shall pay for Incremental Generation Amounts as set forth herein. Avista shall make price offers for Incremental Generation Amounts to Potlatch, either upon its own initiative or upon Potlatch's request, subject to Subsection 4(f) below. Prices offered by Avista shall include all Avista costs, including but not limited to, unit contingency, transmission, losses, ancillary services and other costs, but excluding third party transmission costs. Potlatch may request a price offer from Avista on a prescheduled basis for Incremental Generation Amounts consistent with Section 7. Unless the Parties otherwise agree, Avista, using reasonable commercial efforts, shall provide a price offer which shall be eighty-five percent (85%) of a unit contingent sale price that Avista is able to execute with a third party for the Incremental Generation Amount that Potlatch will make available to Avista on a prescheduled basis. If Avista is unable, after using reasonable commercial efforts to execute a unit contingent sale, or is unwilling, using reasonable commercial judgement to execute a unit contingent sale, then Avista shall not be obligated to offer a prescheduled price to Potlatch. Any Avista purchases of firm, rather than unit contingent, Incremental Generation Amounts shall be subject to separate negotiation and mutual agreement at the time of such purchases. If the Parties are unable to mutually agree upon a prescheduled price for Incremental Generation Amounts and Potlatch desires to sell Incremental Generation Amounts to Avista, Potlatch may request a real-time price offer for the hour from Avista consistent with Section 7. -10-

Subject to Subsection 4(f) below, if the Parties are unable to mutually agree on a real-time price for such hour, then Potlatch may elect, consistent with Section 7, to receive a price based on eighty percent (80%) of the weighted average price of Avista's real-time hourly sales and purchases for the hour in which the Parties agree that Avista will purchase Incremental Generation Amounts. If Avista has no real-time hourly purchases or sales for the hour in which Potlatch elects to sell Incremental Generation Amounts to Avista, then eighty percent (80%) of the hourly real-time market price internally recorded by Avista based on information which Avista generally discovers through its participation in the market shall be used as the price for the Incremental Generation Amount for such hour. (f) Avista shall use the same degree of care and effort to purchase and, if necessary, to resell Incremental Generation Amounts as it uses in selling electric power from Avista owned generating resources. Notwithstanding anything in this Agreement, Avista reserves the right to refuse to purchase Incremental Generation Amounts due to commercially reasonable internal policy limitations prohibiting purchases for resale or Governmental Rules prohibiting purchases for resale. Avista shall make reasonable efforts to notify Potlatch in advance of such internal policy limitations or Governmental Rules. (g) With regard to a prescheduled purchase of an Incremental Generation Amount, at the time of execution of the transaction, Avista shall provide Potlatch with a facsimile copy of the transaction confirmation that shall include the mutually agreed upon price and estimated Incremental Generation Amount as provided by Potlatch. With regard to a real-time purchase of an Incremental Generation Amount, at the time of execution of the transaction, Avista shall provide Potlatch with a voice confirmation of either the price or Potlatch's election to take the calculated price, in accordance with Subsection 4(e). Potlatch shall provide a voice confirmation of the estimated Incremental Generation Amount. Potlatch may call Avista's real-time scheduler in the hour following the hour of delivery of the Incremental Generation Amount and Avista shall provide the real-time market price internally recorded in accordance with Subsection 4(e) for Potlatch's information purposes only. -11-

(h) MULTIPLE INCREMENTAL GENERATION AMOUNT TRANSACTIONS WITHIN A SINGLE HOUR: Should the Parties enter into more than one transaction for delivery in any hour of Incremental Generation Amounts, then the actual Incremental Generation Amounts produced by Potlatch's Facility will be first committed to the transaction entered into on the earliest date and time and the remaining actual Incremental Generation Amounts will be committed to the remaining transactions in the order in which the Parties entered into those transactions. 5. POWER SALES (POWER DELIVERIES TO POTLATCH). (a) Avista shall sell and deliver and Potlatch shall purchase and accept delivery of electric power and energy required for Potlatch's Load at the Lewiston Plant for the duration of the Agreement in accordance with the terms and conditions of this Agreement, Avista's Rules and Regulations in effect with the IPUC, applicable tariff schedules and orders of the IPUC in effect at the time electric power is delivered hereunder, as they may be changed from time to time, and any other requirements imposed by law, provided: (1) Avista shall not be obligated to provide to Potlatch Facility Service Power or Losses; and (2) Any demand charge assessed to Potlatch for periods in which Power Purchases are made shall be based on either: (i) The coincident hourly sum of (1) Net Facility Power produced by the Facility (expressed in kilowatts) and (2) electric power (expressed in kilowatts) that flows from Avista's electric system to the Potlatch Load added vectorily to only the reactive power ("kVARs") that flows from Avista's electric system to the Potlatch Load during periods when Avista purchases from Potlatch either Base Generation Amounts or Excess Generation Amounts, or; (ii) The coincident hourly sum of (1) Incremental Generation Amounts produced by the Facility (expressed in kilowatts) and (2) electric power (expressed in kilowatts) that flows from Avista's electric system to the Potlatch Load added vectorily to only the reactive power ("kVARs") that flows from Avista's electric system to the Potlatch Load during periods when Potlatch elects to use Excess Generation Amounts to serve its Load. -12-

Reactive power produced by the Facility as described in either of the cases under Subsection 5(a)(2)(i) or 5(a)(2)(ii) above shall not be included in the demand calculation. (3) Any demand charge assessed to Potlatch for periods in which no Power Purchases are made shall be based only on kilowatts that flow from Avista's electric system to the Potlatch Load added vectorily to only the reactive power that flows from Avista's electric system to the Potlatch Load. (b) Avista shall bill for all electric power delivered by Avista for Potlatch's Load at the rates set forth in Avista's Extra Large General Service Schedule 25, including all adjustments thereto, unless and until such time as the IPUC issues an order authorizing Avista to bill at a different rate. Nothing shall prejudice any Party's right to propose, or the Commission to order, in future proceedings that Potlatch's service should be priced at rates other than Schedule 25 rates. This Agreement shall not be construed as restricting the right of either Party to petition the IPUC to establish, disestablish, amend or alter Avista's Rules and Regulations in effect with the IPUC, applicable tariff schedules and orders of the IPUC, including but not limited to Schedule 25. 6. OPERATION OF FACILITY. (a) Potlatch shall construct, operate and maintain the Facility and associated electrical equipment in compliance with Qualifying Facility status and in accordance with applicable laws and regulations and in accordance with Good Industry Practice. Potlatch shall construct, operate and maintain the Facility and other equipment associated with the Lewiston Plant at its own risk and expense. Avista shall construct, operate and maintain its interconnection facilities, that portion of its system that is interconnected to the Facility, and all equipment needed to receive and transmit electric power in accordance with applicable laws and regulations and in accordance with the Interconnection Agreement and Good Industry Practice. (b) Interconnection of electrical systems under this Agreement shall be governed by the Interconnection Agreement. Nothing herein is intended to amend or alter the Interconnection Agreement as it may be amended or superceded. In the event that the Interconnection Agreement -13-

is superceded or amended as a consequence of a lawful order of the Federal Energy Regulatory Commission, or other agency or court having jurisdiction thereof, the Parties agree to negotiate in good faith such amendments to this Agreement as are necessary to preserve the intent of this Agreement. Subject to Governmental Rules, in the event of a conflict between the terms of this Agreement and the Interconnection Agreement, the terms of this Agreement shall take precedence. (c) Exhibit B (Communications), attached hereto, shall govern communications between Potlatch and Avista for purposes of this Agreement. (d) Potlatch shall provide Avista as much notice as is reasonably practicable under the circumstances in the event of any planned increase to or reduction in its Load of more than 10,000 kilowatts. Potlatch shall also provide as much notice as is reasonably practicable under the circumstances of any planned outages of the Facility and any planned increase or reduction of generation from the Facility of more than 10,000 kilowatts. The notices shall specify the amount and the expected duration of such outages, increases and reductions. (e) Potlatch shall use its best efforts to maintain its Load on Avista's electric system (at the Points of Delivery) at a power factor of 95% or higher throughout the term of this Agreement. Avista shall not be liable for any loss or damage incurred by Potlatch resulting solely from Potlatch's failure to maintain a power factor of 95% or higher. (f) The Parties acknowledge that Avista's electric power system and delivery facilities, under certain circumstances, may constrain power deliveries to Potlatch's Lewiston Plant. Potlatch shall notify Avista of any intention to increase its energy and demand requirements at the Lewiston Plant beyond the capacity of Avista's facilities. The Parties shall negotiate in good faith the terms and conditions of a mutually acceptable separate agreement to install additional facilities required to accommodate additional energy and demand requirements, subject to approval by the IPUC and consistent with FERC rules and regulations. (g) Potlatch agrees to adhere to IEEE 519 guidelines for power quality. -14-

7. SCHEDULING. (a) GENERAL SCHEDULING: Potlatch shall submit to Avista pre-schedulers its estimated hourly schedules for Base Generation Amounts, Excess Generation Amounts, and Load for each Week, and shall make commercially reasonable efforts to deliver electric power as scheduled. Potlatch shall also indicate, pursuant to Subsection 4(c), whether it will sell Excess Generation Amounts to Avista or elects to instead supply Excess Generation Amounts to its Load for the Week. Potlatch shall insure that such submission is received by Avista no later than 1700 hours Pacific Prevailing Time of the second-to-the-last business day observed by both Parties of the Week preceding the Week to be pre-scheduled by facsimile or other similar written form. Potlatch shall also call Avista's real-time scheduler as soon as practical if there are material changes to expected generation amounts or Load. (b) DAY-AHEAD INCREMENTAL GENERATION AMOUNT SCHEDULING ESTIMATES: Potlatch shall submit to Avista's pre-schedulers its best estimates of hourly Incremental Generation Amounts by 0600 hours Pacific Prevailing Time on the business day observed by both Parties immediately preceding the day or days on which electric power is to be delivered, unless otherwise mutually agreed by the Parties. (c) REAL-TIME INCREMENTAL GENERATION AMOUNT SCHEDULES: Potlatch shall contact Avista real-time schedulers no earlier than two hours and not later than one hour prior to the hour in which power is to be delivered to communicate its best estimate of hourly Incremental Generation Amounts and any material change in expected electric power deliveries or changes in Load. 8. BILLING AND PAYMENTS. (a) So long as there are Power Sales made and/or payments due hereunder, Avista shall prepare monthly an itemized billing of the payment due, including the amounts of Power Purchases, Power Sales, the appropriate rates, and any adjustments to the payment consistent -15-

with the provisions herein. Payments for amounts billed shall be received by the Party to be paid on the due date, which shall be either the 20th day of the month following the Billing Period or ten (10) days after receipt of the bill, whichever is later ("Due Date"). Payment shall be made at the location designated by the Party to which payment is due. If the Due Date falls on a non-business day of either Party, then the payment shall be due on the next following business day. (b) Subject to Subsection (c) below, any payments by Avista to Potlatch or by Potlatch to Avista, if not paid in full within the limitations set forth in Subsection (a), shall be late. In addition to the other remedies for such an Event of Default pursuant to this Agreement, the late-paying Party shall be assessed a charge for late payment equal to the lesser of one percent (1%) per whole or partial month, or the maximum rate allowed by the laws of the State of Idaho per whole or partial month multiplied by the overdue amount. Each Party shall have the right to offset any amounts due it against any present payments owed to the other Party. (c) If a Party in good faith disputes a bill prepared by the other Party, the disputing Party may pay or withhold the amount in dispute. If a disputing Party elects to pay or withhold the amount in dispute, it shall provide a written notice to the other Party at the same time that payment would be normally due, which notice shall specifically set forth the basis of the dispute. The Parties agree as soon as practicable to negotiate the dispute and failing negotiation, to otherwise resolve the dispute in the most expeditious manner practicable. If the disputing Party elects to withhold the disputed amount, and if the billing dispute is resolved in favor of the Party that prepared the bill, the disputing Party shall pay to the billing Party the amount withheld with interest accrued at the rate set forth in Subsection (b) above, multiplied by the withheld amount, prorated by months and partial months from the original date that the amount should have been paid to the actual date of payment. If the disputing Party elects to pay the disputed amount, and the billing dispute is resolved in favor of the disputing Party, the Party that prepared the bill shall refund the disputed amount to the disputing Party, with interest accrued at the rate set forth in Subsection (b) above multiplied by the disputed amount, prorated by months and partial months from the date that the amount was paid to the date of refund. -16-

(d) Potlatch may verify information used in preparing invoices by examining Avista documents in its Spokane office for a period up to ninety (90) days after the billing date. All information, records and reports related to Power Purchases or Power Sales under the terms of this Agreement, and the calculation of prices therefor, will be open to inspection by Potlatch upon reasonable notice and provided that Potlatch shall keep all such information confidential and use it only for purposes of this Agreement, and further provided that in any enforcement proceedings, Potlatch shall avail itself of procedures to protect the confidentiality of such information under the applicable Governmental Rules. (e) Avista shall prorate amounts billed to Potlatch for demand and other charges, in accordance with the provisions of this Section, during the initial month of Power Purchases and Power Sales under this Agreement if such purchases and sales commence on any day other than the first day of the month, and during any Billing Period in which Potlatch elects to use Excess Generation Amounts to serve the Load as permitted in Section 4(c). The Power Sales demand quantities, expressed in kilovolt-amperes ("kVa") shall be prorated for the purposes of calculating the demand charge for the applicable Billing Periods. For the applicable Billing Periods, the prorated demand quantity components shall be calculated as follows: (1) Base Period Demand, expressed in kVa, during that portion of the Billing Period in which Avista made Power Purchases of Base Generation Amounts from Potlatch multiplied by the number of days (rounded to the nearest whole day) in the Billing Period in which Avista made Power Purchases of Base Generation Amounts from Potlatch and then divided by the total number of days in the Billing Period; (2) Excess Period Demand, expressed in kVa, during that portion of the billing period in which Avista made no Power Purchases other than Incremental Generation Amounts from Potlatch multiplied by the number of days (rounded to the nearest whole day) in the Billing Period in which Avista made no Power Purchases other than Incremental Generation Amounts from Potlatch and then divided by the total number of days in the Billing Period; (3) Excess Period Demand, expressed in kVa, during that portion of the Billing Period in which Avista purchased Excess Generation Amounts from Potlatch multiplied by the number of days (rounded to the nearest whole day) in the Billing Period in which Avista made Power Purchases of Excess Generation Amounts from Potlatch and then divided by the total number of days in the Billing Period. Prorated total demand quantity, expressed in kVa, is calculated from the -17-

arithmetic sum of (1), (2) and (3) above. The resultant total demand quantity shall be used for calculation of the demand charge. (f) Adjustments shall be made in billings for errors in a meter reading or in a billing discovered within thirty-six (36) months of the error. 9. METERING. (a) Metering shall be governed by the provisions of Exhibit A. (b) Avista shall be responsible for any meter readings required by this Agreement. 10. TERMINATION OF AGREEMENT. Subject to the Force Majeure provision of this Agreement, the Agreement may be terminated at Avista's sole option, if any of the following conditions occur. (a) Potlatch abandons the Facility or otherwise renders the Facility incapable of generating electric power; or (b) There have been no electric power deliveries to Avista from the Facility for a period of twelve (12) consecutive months; or (c) The electric power deliveries from the Facility to Avista fail to exceed 175,200 megawatt-hours during any rolling period of twenty-four (24) consecutive months, which rolling period commences any time after the first twelve (12) consecutive months following the Effective Date. -18-

11. FORCED OUTAGE AND FORCE MAJEURE. (a) Neither Party shall be liable to the other Party for, or be considered to be in breach of or default under this Agreement, on account of any delay in performance due to any of the following events, which event or circumstance was not anticipated as of the Effective Date ("Force Majeure"): (1) Any cause or condition beyond such Party's reasonable control that such Party is unable to overcome by the exercise of reasonable diligence, including but not limited to: fire, flood, earthquake, volcanic activity, wind, drought and other acts of the elements; court order and act of civil, military or governmental authority; strike, lockout and other labor dispute; riot, insurrection, terrorism, sabotage or war; Governmental Rules; Forced Outage; breakdown of or damage to facilities or equipment; electrical disturbance originating in or transmitted through such Party's electric system or any electric system with which such Party's system is interconnected; any interruption of transmission service required for the performance of this Agreement that is excused by reason of force majeure or uncontrollable forces under a Party's contract with a transmission service provider; and, any act or omission of any person or entity other than such Party, and Party's contractors or suppliers of any tier or anyone acting on behalf of such Party; or (2) Any action taken by such Party which is, in the sole judgment of such Party, necessary or prudent to protect the operation, performance, integrity, reliability or stability of such Party's electric system or any electric system with which such Party's electric system is interconnected, whether such actions occur automatically or manually. (b) In the event of any Force Majeure occurrence, the time for performance thereby delayed shall be extended by a period of time reasonably necessary to compensate for such delay. Nothing contained in this paragraph shall require any Party to settle any strike, lockout or other labor dispute. In the event of a Force Majeure occurrence, which will affect performance under this Agreement, the nonperforming Party shall provide the other Party written notice as soon as practicable after the occurrence of the Force Majeure event. Such notice shall include the particulars of the occurrence, assurances that suspension of performance is of no greater scope and of no longer duration than is required by the Force Majeure and that best efforts are being -19-

used to remedy its inability to perform. The nonperforming Party shall remedy the Force Majeure occurrence with all reasonable dispatch. The performing Party shall not be required to perform or resume performance of its obligations to the nonperforming Party corresponding to the obligations of the performing Party excused by the Force Majeure occurrence. (c) Force Majeure does not include changes in the ownership, occupancy, or operation of the Facility or Avista if such changes occur because of normal business occurrences which include but are not limited to: changes in business economic cycles; recessions; bankruptcies; tax law changes; sales of businesses; closure of businesses; changes in production levels; and, changes in system operations. (d) Force Majeure does not excuse any Party from making payments of money due under this Agreement for power purchased prior to the Force Majeure event. 12. INDEMNITY. (a) POTLATCH'S DUTY TO INDEMNIFY. Potlatch shall indemnify, hold harmless and defend Avista, and its officers, directors, employees, affiliates, managers, members, trustees, shareholders, agents, contractors, subcontractors, affiliates' employees, invitees and successors, from and against any and all third party claims, demands, suits, obligations, payments, liabilities, costs, losses, judgments, damages and expenses (including the reasonable costs and expenses of any and all actions, suits, proceedings, assessments, judgments, settlements, and compromises relating thereto, reasonable attorneys' and expert fees and reasonable disbursements in connection therewith) for damage to property, injury to any person or entity, or death of any individual, including Avista's employees and affiliates' employees, Potlatch's employees, or any other third parties, to the extent caused wholly or in part by any act or omission, negligent or otherwise, by Potlatch or its officers, directors, employees, agents, contractors, subcontractors and invitees arising out of or connected with Potlatch's performance or breach of this Agreement, or the exercise by Potlatch of its rights hereunder; provided, however, that the provisions of this Section shall not apply if any such injury, death or damage is held to have been caused by the sole -20-

negligence or intentional wrongdoing of Avista, its agents or employees. The foregoing indemnification obligation shall not be limited in any way by workers' compensation laws or by any limitation on the amount or type of damages, compensation or benefits payable by Potlatch under applicable workers' compensation laws. (b) AVISTA'S DUTY TO INDEMNIFY. Avista shall indemnify, hold harmless and defend Potlatch, and its officers, directors, employees, affiliates, managers, members, trustees, shareholders, agents, contractors, subcontractors, invitees and successors, from and against any and all third party claims, demands, suits, obligations, payments, liabilities, costs, losses, judgments, damages and expenses (including the reasonable costs and expenses of any and all actions, suits, proceedings, assessments, judgments, settlements, and compromises relating thereto, reasonable attorneys' and expert fees and reasonable disbursements in connection therewith) for damage to property, injury to any entity or person, or death of any individual, including Potlatch's employees and affiliates' employees, Avista's employees, or any other third parties, to the extent caused wholly or in part by any act or omission, negligent or otherwise, by Avista or its officers, directors, employees, agents, contractors, subcontractors and invitees arising out of or connected with Avista's performance or breach of this Agreement, or the exercise by Avista of its rights hereunder; provided, however, that the provisions of this Section shall not apply if any such injury, death or damage is held to have been caused by the sole negligence or intentional wrongdoing of Potlatch, its agents or employees. The foregoing indemnification obligation shall not be limited in any way by workers' compensation laws or by any limitation on the amount or type of damages, compensation or benefits payable by Avista under applicable workers' compensation laws. (c) NOTICE. A Party seeking indemnification under this Agreement ("First Party") shall give the other Party ("Second Party") notice of the claim or action giving rise to a right of indemnification as soon as practicable, but in any event on or before the thirtieth (30th) day after the First Party's actual knowledge of such claim or action. The notice shall describe the claim or action in reasonable detail, and shall indicate the amount (estimated if necessary) of the claim or action. Any failure of the First Party to provide the notice required by this Section shall not affect the First Party's rights to indemnification except to the extent the Second Party is actually -21-

and materially prejudiced as a result of such failure. Neither Party may settle or compromise any claim for which indemnification is sought under this Agreement without the prior consent of the other Party; provided, however, said consent shall not be unreasonably withheld or delayed. Each Party's indemnification obligation shall survive expiration, cancellation or early termination of this Agreement. (d) ACKNOWLEDGMENT TO NEGOTIATION. POTLATCH AND AVISTA SPECIFICALLY WARRANT THAT THE TERMS AND CONDITIONS OF THE FOREGOING INDEMNITY PROVISIONS ARE THE SUBJECT OF MUTUAL NEGOTIATION BY THE PARTIES, AND ARE SPECIFICALLY AND EXPRESSLY AGREED TO IN CONSIDERATION OF THE MUTUAL BENEFITS DERIVED UNDER THE TERMS OF THE AGREEMENT. 13. LIMITATION OF LIABILITY. (a) LIMITATION OF LIABILITY. With respect to claims by and between the Parties under this Agreement, the measure of damages at law or in equity in any action or proceeding shall be limited to direct actual damages only. Such direct actual damages shall be the sole and exclusive remedy and all other remedies or damages at law or in equity are waived and neither Party shall be liable in statute, contract, in tort (including negligence), strict liability, warranty or under any other legal theory or otherwise to the other Party, its agents, representatives, and/or assigns, for any special, incidental, punitive, exemplary or consequential loss or damage whatsoever, including, but not limited to, loss of profits or revenue for work not performed, for loss of use of or under-utilization of the other Party's facilities, loss of use of revenues, attorneys' fees, litigation costs, or loss of anticipated profits, resulting from either Party's performance or non-performance of an obligation imposed on it by this Agreement, without regard to the cause or causes related thereto, including the negligence of any Party. The Parties expressly acknowledge and agree that this limitation shall not apply to any claims for indemnification under Section 12 of this Agreement. The provisions of this Section shall survive the termination or expiration of this Agreement. -22-

(b) LIMITATION OF LIABILITY FOR WIS PARTIES. Notwithstanding the provisions of Subsection (a) above, if both Avista and Potlatch are parties to the Western Interconnected Systems Limitation of Liability ("WIS") Agreement, then the WIS Agreement shall control their liabilities with respect to damages to the Facility, the interconnection facilities, or Avista's electric system. 14. INSURANCE. (a) GENERAL LIABILITY. The Parties agree to maintain, at their own cost and expense, general liability, workers' compensation, and other forms of insurance relating to their operations for the life of this Agreement in the manner, and amounts, at a minimum, as set forth below. (1) Workers' compensation insurance in accordance with all applicable state and federal law, including Employer's Liability Insurance in the amount of $1,000,000 per occurrence; (2) Commercial General Liability Insurance, including Contractual Liability Coverage for liabilities assumed under this Agreement, and Personal Injury Coverage in the minimum amount of $5,000,000 per occurrence for bodily injury and property damage. Potlatch's policy shall include Avista as an additional insured. (3) Where a Party has more than $100 million in assets it may, at its option, self-insure all or part of the insurance required in this Section 14; provided, however, the self-insuring Party agrees that all other provisions of this Section 14, including, but not limited to, waiver of subrogation, waiver of rights of recourse, and additional insured status, which provide or are intended to provide protection for the other Party and its affiliated and associated companies under this Agreement, shall remain enforceable. A Party's election to self-insure shall not impair, limit, or in any manner result in a reduction of rights and/or benefits otherwise available to the other Party and its affiliated and associated companies through formal insurance policies and endorsements as specified in the above parts of this Section 14. The self-insuring Party agrees that all amounts of self-insurance, retentions and/or deductibles are the responsibility of and shall be borne by the self-insuring Party. -23-

(b) CERTIFICATES. Within fifteen (15) days of the Effective Date, and each anniversary of the Effective Date, during the term of this Agreement, (including any extensions), each Party shall provide to the other Party, properly executed and current certificates of insurance with respect to all insurance policies required to be maintained by such Party under this Agreement. Certificates of insurance shall provide the following information: (1) Name of insurance company, policy number and expiration date; (2) The coverage required and the limits on each, including the amount of deductibles or self-insured retentions, which shall be for the account of the Party maintaining such policy; (3) A statement indicating that the other Party shall receive at least thirty (30) days prior written notice of cancellation or expiration of a policy, or reduction of liability limits with respect to a policy; and (4) A statement identifying and indicating that additional insureds have been named as required by this Agreement. (c) POLICY REQUEST. At a Party's request, in addition to the foregoing certifications, the other Party shall deliver to the first Party a copy of applicable sections of each insurance policy. (d) INSPECTION. Each Party shall have the right to inspect the original policies of insurance applicable to this Agreement at the other Party's place of business during regular business hours. (e) "CLAIMS MADE" INSURANCE. If any insurance is written on a "claims made" basis, the respective Party shall maintain the coverage for a minimum of seven years after the termination of this Agreement. (f) WAIVER OF SUBROGATION. To the extent permitted by the insurer and commercially reasonable, each Party shall obtain waivers of subrogation in favor of the other Party from any insurer providing coverage that is required to be maintained under this Section 14. A Party shall not be required to obtain a waiver of subrogation if the other Party is not able to obtain a waiver of subrogation from its insurance carrier. -24-

15. ASSIGNMENT. Neither Party shall voluntarily assign its rights or delegate its duties under this Agreement, or any part of such rights or duties without the written consent of the other Party. Such consent shall not unreasonably be withheld. Further, no assignment by either Party shall relieve or release it to the extent of any of its obligations hereunder. Subject to the foregoing restrictions on assignments, this Agreement shall be fully binding upon, inure to the benefit of and be enforceable by the Parties and their respective successors, heirs and assigns. 16. NO UNSPECIFIED THIRD PARTY BENEFICIARIES. Except as specifically provided in this Agreement, there are no third party beneficiaries of this Agreement. Nothing contained in this Agreement is intended to confer any right or interest on anyone other than the Parties, and their respective successors, heirs and assigns permitted under Section 15. 17. NO TRANSMISSION RIGHTS. Nothing in this Agreement shall be construed as granting Potlatch any right of access, or any other rights, to Avista's transmission system. 18. BENEFITS FOR RENEWABLE FUELS. Nothing in this Agreement shall affect Potlatch's rights to benefits attributable to Potlatch's use of renewable fuels for generation. The Parties further agree to negotiate in good faith should it be necessary at a later date, to develop a separate agreement in order to provide Potlatch with those benefits. -25-

19. DEFAULT. (a) An "Event of Default" shall mean, with respect to a Party (a "Defaulting Party"), the occurrence of any of the following: (1) the failure to make, when due, any payment required pursuant to this Agreement if such failure is not remedied within three (3) business days after delivery of written notice; (2) any representation or warranty made by such Party herein is false or misleading in any material respects when made or when deemed made or repeated; (3) the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default) if such failure is not remedied within thirty (30) business days after delivery of written notice; (4) such Party becomes Bankrupt; or (5) such Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another entity and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee entity fails to assume all the obligations of such Party under this Agreement to which it or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party. (b) In the Event of Default, the following shall apply: (1) The non-defaulting Party shall give written notice to the Defaulting Party of the Event of Default in accordance with this Agreement. (2) Except for an Event of Default that arises from failure to make money payments or from a Party becoming bankrupt, if, after 30 days following receipt of such notice, the Defaulting Party has not taken the steps necessary to cure the event of default, the non-defaulting Party may, at its option, terminate this Agreement; provided, however, that except for the failure to pay sums which are due and payable, if the defaulting Party, within such 30-day period, commences and thereafter proceeds with all due diligence to cure such default, such 30-day period shall be extended up to six (6) months after written notice to the defaulting Party, as may be necessary to cure the event of default with all due diligence. For an Event of Default that arises from the failure to make money payments, the non-defaulting Party may, at its option, terminate this Agreement if the Defaulting Party shall have failed to cure the failure to pay within -26-

three (3) business days following receipt of notice of such failure. For an Event of Default that arises from a Party becoming bankrupt, the non-defaulting Party may, at its option, immediately terminate this Agreement upon notice to the Defaulting Party. (3) Upon the Event of Default and an expiration of any period to cure granted herein, the non-defaulting Party may, but has no obligation, to terminate this Agreement effective upon notice to the Defaulting Party and may exercise all other rights and remedies available to the non-defaulting Party under applicable law. Whether or not the non-defaulting Party elects to terminate this Agreement, it may, in addition to other remedies provided for herein, pursue such remedies as are available at law or in equity including suspension of its performance so long as the Event of Default is continuing and has not been cured. (c) Any right or remedy afforded to either Party under any provision of this Agreement on account of the breach or default by the other Party is in addition to, and not in lieu of, all other rights or remedies afforded to such Party under any other provisions of this Agreement, by law or otherwise on account of the breach or default. 20. RELEASE BY AVISTA. Avista releases Potlatch from any and all claims, losses, harm, liabilities, damages, costs and expenses to the extent resulting from any disconnection, interruption, suspension or curtailment by Potlatch pursuant to terms of this Agreement. 21. RELEASE BY POTLATCH. Potlatch releases Avista from any and all claims, losses, harm, liabilities, damages, costs and expenses to the extent resulting from any disconnection, interruption, suspension or curtailment by Avista pursuant to terms of this Agreement. -27-

22. GOVERNMENTAL AUTHORITY. This Agreement is subject to the Governmental Rules now or hereafter in effect, of all Governmental Authorities having jurisdiction over the Facility, this Agreement, the Parties or either of them. All Governmental Rules that are required to be incorporated in agreements of this character are by this reference incorporated in this Agreement. 23. SEVERAL OBLIGATIONS. Except where specifically stated in this Agreement to be otherwise, the duties, obligations and liabilities of the Parties are intended to be several not joint or collective. This Agreement shall not be interpreted or construed to create an association, joint venture or partnership between the Parties or to impose any partnership obligations or liability upon either Party. Each Party shall be individually and severally liable for its own obligations under this Agreement. Further, neither Party shall have any rights, power or authority to enter into any agreement or undertaking for or on behalf of, to act as or to be an agent or representative of, or to otherwise bind the other Party. 24. IMPLEMENTATION. Each Party shall take such action (including, but not limited to, the execution, acknowledgement and delivery of documents) as may reasonably be requested by the other Party for the implementation or continuing performance of this Agreement. 25. NON-WAIVER. The failure of either Party to insist upon or enforce strict performance by the other Party of any provision of this Agreement or to exercise any right under this Agreement shall not be -28-

construed as a waiver or relinquishment to any extent of such Party's right to assert or rely upon any such provision or right in that or any other instance; rather, the same shall be and remain in full force and effect. 26. ENTIRE AGREEMENT AND AMENDMENT. This Agreement together with its exhibits constitutes the entire agreement of the Parties hereto and supersedes and replaces any prior agreements or understandings between said Parties, entered into for the same or similar purposes, with the exception the Interconnection Agreement. No change, amendment or modification of any provision of this Agreement shall be valid unless set forth in a written amendment to this Agreement signed by both Parties. 27. VENUE, ATTORNEYS FEES AND CHOICE OF LAW. Venue of any action filed to enforce or interpret the provisions of this Agreement shall be exclusively in the United States District Court for the District of Idaho or the District Court of the State of Idaho encompassing Nez Perce County and the Parties irrevocably submit to the jurisdiction of any such court. In the event of litigation to enforce the provisions of this Agreement, the prevailing Party shall be entitled to reasonable costs and attorney's fees in addition to any other relief allowed. Notwithstanding conflict of law rules, the laws of the State of Idaho shall apply to disputes arising under this Agreement. 28. COMPLIANCE WITH LAWS. Both Parties shall comply with all applicable laws and regulations of Governmental Authorities having jurisdiction over the Facility and the operations of the Parties. -29-

29. CONFIDENTIALITY. (a) DEFINITION. "Confidential Information" shall mean any confidential, proprietary or trade secret information or a plan, specification, pattern, procedure, design, device, list concept, policy or compilation relating to the present or planned business of a Party, which is designated in good faith as confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection or otherwise, except that the real-time in-plant data, shall be considered Confidential Information without the need for designation. (b) GENERAL OBLIGATIONS. (1) Each Party shall hold in confidence any and all Confidential Information unless: (i) compelled to disclose such information by Governmental Rules or as otherwise provided for in this Agreement; or (ii) to meet obligations imposed by Governmental Authority or by membership in NERC or WECC (including other transmission providers). Information required to be disclosed under (i) or (ii) above, does not, by itself, cause any information provided by Potlatch to Avista to lose its confidentiality. To the extent it is necessary for either Party to release or disclose such information to a third party in order to perform that Party's obligations herein, such Party shall advise said third party of the confidentiality provisions of this Agreement and use its best efforts to require said third party to agree in writing to comply with such provisions. (2) During the term of this Agreement, and for a period of three (3) years after the expiration or termination of this Agreement, except as otherwise provided in this Section 29, each Party shall hold in confidence and shall not disclose to any person Confidential Information. (3) Each Party shall use at least the same standard of care to protect Confidential Information it receives as it uses to protect its own Confidential Information from unauthorized disclosure, publication or dissemination. (c) EXCLUDED INFORMATION. Confidential Information shall not include information that the receiving Party can demonstrate: (i) is generally available to the public other than as a result of disclosure by the receiving Party; (ii) was in the lawful possession of the receiving Party on a non-confidential basis prior to receiving it from the disclosing Party; (iii) was supplied to the -30-

receiving Party without restriction by a third party, who, to the knowledge of the receiving party, after due inquiry was under no obligation to the disclosing party to keep such information confidential; (iv) was independently developed by the receiving party without reference to Confidential Information of the disclosing party; (v) is, or becomes, publicly known, through no wrongful act or omission of the receiving Party or Breach of this Agreement; or (vi) is required, in accordance with Subsection 29(d) of this Agreement, to be disclosed by any Governmental Authority or is otherwise required to be disclosed by law or subpoena, or is necessary in any legal proceeding establishing rights and obligations under this Agreement. Information designated as Confidential Information will no longer be deemed confidential if the Party that designated the information as confidential notifies the other Party that it no longer is confidential. (d) SUBPOENA. If a Governmental Authority or entity with the right, power, and apparent authority to do so requests or requires either Party, by subpoena, oral deposition, interrogatories, requests for production of documents, administrative order, or otherwise, to disclose Confidential Information, that Party shall provide the other Party with prompt notice of such request(s) or requirement(s) so that the other Party may seek an appropriate protective order or waive compliance with the terms of this Agreement. The notifying Party shall have no obligation to oppose or object to any attempt to obtain such production except to the extent requested to do so by the disclosing Party and at the disclosing Party's expense. If either Party desires to object or oppose such production, it must do so at its own expense. The disclosing Party may request a protective order to prevent any Confidential Information from being made public. Notwithstanding the absence of a protective order or waiver, the Party may disclose such Confidential Information which, in the opinion of its counsel, the Party is legally compelled to disclose. Each Party shall use reasonable efforts to obtain reliable assurance that confidential treatment will be accorded any Confidential Information so furnished. (e) USE IN ARBITRATION. Each Party may utilize information or documentation furnished by the disclosing Party in any dispute resolution proceeding or in an administrative agency or court of competent jurisdiction addressing any dispute arising under this Agreement, subject to a confidentiality agreement with all participants (including, if applicable, any arbitrator) or a protective order. -31-

(f) BREACH. The Parties agree that monetary damages by themselves will be inadequate to compensate a Party for the other Party's Breach of its obligations under this Section 29. Each Party accordingly agrees that the other Party is entitled to equitable relief, by way of injunction or otherwise, if it breaches or threatens to breach its obligations under this Section 29. 30. NOTICES. All written legal notices required by this Agreement shall be mailed or delivered as follows: To Avista: Avista Corporation Attention: Vice President, Energy Resources and Optimization 1411 East Mission Spokane, WA 99202-2600 Mailing Address: P.O. Box 3727 Spokane, WA 99220-3727 To Potlatch: Vice President, Pulp & Paperboard Division Potlatch Corporation 805 Mill Road P. O. Box 1016 Lewiston, ID 83501 Fax: 208-799-1586 Vice President and General Counsel Potlatch Corporation 601 West Riverside Ave., Suite 1100 Spokane, WA 99201 Fax: 509-835-1561 Changes in persons or addresses for submittal of written notices by a Party to this Agreement shall be made in writing to the other Party and delivered in accordance with this Section 30. Any verbal notice required hereby which affects the payments to be made hereunder shall be confirmed in writing as promptly as practicable after the verbal notice is given. -32-

31. SETTLEMENT OF LITIGATION. Potlatch shall dismiss with prejudice its complaint in the United States District Court for the District of Idaho, Case No. CV02-543-C-EJL, and its complaint before the Idaho Public Utilities Commission, Docket No. AVU-E-02-08, upon entry of a final order of the IPUC or court of competent jurisdiction approving the Agreement. 32. EXHIBITS. This Power Purchase Agreement includes the following exhibits, which are attached and incorporated by reference herein: Exhibit A - Metering Exhibit B - Communications Exhibit C - Description of the Facility IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed by their duly authorized representatives as of the first date herein-above set forth: POTLATCH CORPORATION AVISTA CORPORATION By: __________________________ By:________________________ Name: Frank Radle Name: Gary G. Ely Title: Plant Manager, Idaho Pulp & Title: Chairman, President and Chief Paperboard Division Executive Officer -33-

EXHIBIT A [METERING SPECIFICATIONS, POINTS AND LOCATIONS GRAPHIC] [SIMPLIFIED METERING DIAGRAM] 1.0 DEFINITIONS Whenever used in this Exhibit the following terms shall have the following meanings: 1.1 "NET FACILITY POWER" (G(n)). Expressed kW. 1.1.1 For the purposes of this Agreement, the Parties have agreed that Facility Service Power is 125 kW per operating generating unit. Potlatch shall notify Avista when substantial changes are made to the Facility that affect the amount of Facility Service Power. Within a reasonable time the Parties shall select a mutually agreed upon third party auditor and shall share equally the costs of such an audit of Facility Service Power. Unless otherwise agreed, the value determined by such audit shall become the new amount for Facility Service Power for the balance of the term of this Agreement. 1.1.2 For the purposes of this Agreement, the Parties have agreed that Losses are 200 kW. 1.2 "POWER GENERATED" (G(1), G(2), G(3), & G(4)). The electric power measured at each operating unit expressed in kW. A-1

1.3 "ENERGY PURCHASED" (E(p)). The amount of energy that Avista purchases from Potlatch generated by the Facility in kWh in each hour. 1.4 "ENERGY SOLD" (E(s)). The amount of energy that Potlatch purchases from Avista, in kWh in each hour. 1.5 "UTILITY TIE ACTIVE POWER" (P(ut)). The total active power delivered to Potlatch, measured at each of the two (2) Pointsof Delivery expressed in kW. 1.6 "UTILITY TIE REACTIVE POWER" (Q(ut)). The total reactive power delivered to Potlatch, measured at each of the two (2) Points of Delivery expressed in kVAR. 1.7 "BASE GENERATION AMOUNT" (G(b)). Expressed in kW. 1.8 "BASE PERIOD DEMAND" (D(kVa-base)). Expressed in kVa. 1.9 "EXCESS GENERATION AMOUNT" (G(e)). Expressed in kW. 1.10 "EXCESS PERIOD DEMAND" (D(kVa-excess)). Expressed in kVa. 1.11 "INCREMENTAL GENERATION AMOUNT" (G(i)). Expressed in kW. 1.12 "NOMINAL GENERATION AMOUNT" (G(nom)). Expressed in kW. 2.0 GENERAL METERING FORMULAS: 2.1 P(ut) = P(ut1) + P(ut2)(kW) 2.2 Q(ut) = Q(ut1) + Q(ut2) (kVAR) Delivered to Potlatch 2.3 G(n) = G(1) + G(2) + G(3) + G(4) - (125kW*(the number of operating generating units)) - (Losses) 2.4 G(i) = G(n) - G(nom), where G(i) > 0 Otherwise G(i) = 0 A-2

3.0 BASE PERIOD POWER SALES FORMULA (TIME PERIOD IN WHICH BASE GENERATION AMOUNT HAS NOT BEEN EXCEEDED) 3.1 Energy Sold (E[s]) = (P[ut] + G[n]) * Time (kWh) 3.2 Base Period Demand (kVa) D[kVa-base] = (square root of)(P[ut]+G[n])(2) + (Q[ut](2) 4.0 EXCESS PERIOD POWER SALES FORMULA (TIME PERIOD AFTER THE BASE GENERATION AMOUNT IS EXCEEDED) WHEN THE MAXIMUM EXCESS GENERATION AMOUNT IS EXCEEDED OR WHEN POTLATCH USES EXCESS GENERATION AMOUNTS TO SERVE LOAD AND AVISTA DOES NOT PURCHASE INCREMENTAL GENERATION AMOUNTS 4.1 Energy Sold (E(s)) = (P(ut))* Time (kWh) 4.2 Excess Period Demand (kVa) D[kVa-base] = (square root of)(P[ut](2)+G[n]) + (Q[ut](2) 5.0 EXCESS PERIOD POWER SALES FORMULA (TIME PERIOD AFTER THE BASE GENERATION AMOUNT IS EXCEEDED) WHEN THE MAXIMUM EXCESS GENERATION AMOUNT IS EXCEEDED OR WHEN POTLATCH USES EXCESS GENERATION AMOUNTS TO SERVE LOAD AND AVISTA PURCHASES INCREMENTAL GENERATION AMOUNTS 5.1 Energy Sold (E(s)) = (P(ut)+G(i))* Time (kWh) 5.2 Excess Period Demand (kVa) D[kVa-base] = (square root of)(P[ut]+G(i)(2) + (Q[ut](2) 6.0 EXCESS PERIOD POWER SALES FORMULA (TIME PERIOD AFTER THE BASE GENERATION AMOUNT IS EXCEEDED) WHEN AVISTA PURCHASES EXCESS GENERATION AMOUNTS FROM POTLATCH AND AVISTA DOES NOT PURCHASE INCREMENTAL GENERATION AMOUNTS 6.1 Energy Sold (E(s)) = (P(ut)+ G(n)* Time (kWh) A-3

6.2 Excess Period Demand (kVa) D[kVa-base] = (square root of)(P[ut]+G[n])(2) + (Q[ut](2) D[kVa-base] = (square root of)(P[ut]+G[n])(2) + (Q[ut](2) 7.0 EXCESS PERIOD POWER SALES FORMULA (TIME PERIOD AFTER THE BASE GENERATION AMOUNT IS EXCEEDED) WHEN AVISTA PURCHASES EXCESS GENERATION AMOUNTS FROM POTLATCH AND AVISTA PURCHASES INCREMENTAL GENERATION AMOUNTS 7.1 Energy Sold (E(s)) = (P(ut)+ G(n))* Time (kWh) 7.2 Excess Period Demand (kVa) D[kVa-base] = (square root of)(P[ut]+G[n])(2) + (Q[ut](2) 8.0 BASE PERIOD POWER PURCHASE FORMULA 8.1 Base Generation Purchased (G(b)) = G(n) * Time (kWh) where G(i) = 0 or G(b) = G(nom)* Time (kWh) where G(i) > 0 8.2 Incremental Generation Purchased (G(i)) = G(n) - G(nom) * Time (kWh) where G(i) > 0 otherwise G(i) = 0 9.0 EXCESS PERIOD POWER PURCHASE FORMULA 9.1 Excess Generation Purchased (G(e)) = G(n)* Time (kWh) where G(i) = 0 or G(e) = G(nom) where G(i) > 0 or G(e) = 0 where Potlatch uses Excess Generation Amounts to serve Load 9.2 Incremental Generation Purchased (G(i)) = G(n) - G(nom) * Time (kWh) where G(i) > 0 otherwise G(i) = 0 A-4

EXHIBIT B COMMUNICATIONS 1. Verbal Communications (a) Verbal communications relating to electric power scheduling, generation or load level changes between Potlatch and Avista shall be between the following personnel: (1) Pre-Schedule (5:30 a.m. to approximately 1:30 p.m. on normal business days): Avista Pre-Scheduler (509) 495-4911 Alternate Phone Number: (509) 495-4073 Potlatch Utility Supervisor (208) 799-1923 Alternate Phone Number: (208) 799-1298 (2) Real-Time Schedule (available 24 hours per day): Avista Real-Time Scheduler (509) 495-8534 Potlatch Utility Supervisor (208) 799-1923 Alternate Phone Number: (208) 799-1298 (b) During normal business hours, all verbal communications relating to interruptions and outages: Avista System Operator (509) 495-4105 Alternate Phone Number: (509) 495-4934 Potlatch Utility Operator (208) 799-1923 Alternate Phone Number: (208) 799-1298 (c) Outside of normal business hours (nights, weekends, and holidays), all verbal communications relating to interruptions and outages shall take place between the following personnel: Avista System Operator (509) 495-4105 Alternate Phone Number: (509) 495-4934 Potlatch Utility Operator (208) 799-1298 Alternate Phone Number (208) 799-1258 Either Party may provide written notice to the other Party setting forth different contact numbers. B-1

EXHIBIT C DESCRIPTION OF THE FACILITY 1. Unit Number One Description (a) The unit number one turbine, General Electric serial number 197741, is a nine stage, 3600 RPM, 600 PSIG steam turbine. (b) The unit number one generator, General Electric serial number 316X188, is nameplate rated at 12,500 kVA. 2. Unit Number Two Description (a) The unit number two turbine, General Electric serial number 83530, is a six stage, 3600 RPM, 600 PSIG steam turbine. (b) The unit number two generator, General Electric serial number 6784689, is nameplate rated at 11,188 kVA. 3. Unit Number Three Description (a) The unit number three turbine, General Electric serial number 197836, is a twelve stage, 3600 RPM, 1250 PSIG steam turbine. (b) The unit number three generator, General Electric serial number 316X374, is nameplate rated at 41,600 kVA @ 30 PSIG H2. 4. Unit Number Four Description (a) The unit number four turbine, from ABB order number MB275226, is a 3600 RPM steam turbine. (b) The unit number four generator, ABB serial number HM300516, is nameplate rated at 66,916 kVA C-1



                                                                      EXHIBIT 12

                               AVISTA CORPORATION

    Computation of Ratio of Earnings to Fixed Charges and Preferred Dividend
                            Requirements Consolidated
                             (Thousands of Dollars)



                                                                             Years Ended December 31
                                                          --------------------------------------------------------------
                                                             2003         2002         2001         2000         1999
                                                          ----------   ----------   ----------   ----------   ----------
                                                                                               
Fixed charges, as defined:
       Interest expense                                   $   85,013   $   96,005   $  100,180   $   64,765   $   61,666
       Amortization of debt expense
         and premium - net                                     7,972        8,861        5,639        3,409        3,044
       Interest portion of rentals                             4,452        6,140        5,140        4,324        4,645
                                                          ----------   ----------   ----------   ----------   ----------
           Total fixed charges                            $   97,437   $  111,006   $  110,959   $   72,498   $   69,355
                                                          ==========   ==========   ==========   ==========   ==========
Earnings, as defined:
       Income from continuing operations                  $   50,643   $   42,174   $   68,241   $  109,065   $   31,223
       Add (deduct):
         Income tax expense                                   35,340       34,849       40,585       81,143       18,276
         Total fixed charges above                            97,437      111,006      110,959       72,498       69,355
                                                          ----------   ----------   ----------   ----------   ----------
           Total earnings                                 $  183,420   $  188,029   $  219,785   $  262,706   $  118,854
                                                          ==========   ==========   ==========   ==========   ==========
Ratio of earnings to fixed charges                              1.88         1.69         1.98         3.62         1.71

Fixed charges and preferred
  dividend requirements:
       Fixed charges above                                $   97,437   $  111,006   $  110,959   $   72,498   $   69,355
       Preferred dividend requirements (1)                     1,910        4,387        3,878       41,394       33,914
                                                          ----------   ----------   ----------   ----------   ----------
           Total                                          $   99,347   $  115,393   $  114,837   $  113,892   $  103,269
                                                          ==========   ==========   ==========   ==========   ==========
Ratio of earnings to fixed charges
  and preferred dividend requirements                           1.85         1.63         1.91         2.31         1.15


(1) Preferred dividend requirements have been grossed up to their pre-tax level.

. . . Exhibit 21 Avista Corporation SUBSIDIARIES OF REGISTRANT State or Country Subsidiary of Incorporation ---------- ---------------- Avista Capital, Inc. Washington Avista Advantage, Inc. Washington Avista Communications, Inc. Washington Avista Development, Inc. Washington Avista Energy, Inc. Washington Avista Energy Canada LTD Canada Copac Management, Inc. Canada Avista Power, LLC Washington Avista Services, Inc. (1) Washington Avista Turbine Power, Inc. Washington Avista Rathdrum, LLC Washington Coyote Springs 2, LLC Delaware Rathdrum Power, LLC Idaho Avista Ventures, Inc. Washington Pentzer Corporation Washington Pentzer Venture Holdings II, Inc. Washington Bay Area Manufacturing, Inc. Washington Advanced Manufacturing and Development, Inc. California Avista Receivables Corporation Washington WP Funding LP Delaware Spokane Energy, LLC Delaware (1) Not currently active. Avista Corporation is planning to dissolve this subsidiary.

Exhibit 31(a) CERTIFICATION I, Gary G. Ely, certify that: 1. I have reviewed this report on Form 10-K of Avista Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 8, 2004 /s/ Gary G. Ely ------------------------------------ Gary G. Ely Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)

Exhibit 31(b) CERTIFICATION I, Malyn K. Malquist, certify that: 1. I have reviewed this report on Form 10-K of Avista Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 8, 2004 /s/ Malyn K. Malquist ------------------------------- Malyn K. Malquist Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

Exhibit 32 AVISTA CORPORATION CERTIFICATION OF CORPORATE OFFICERS (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) Each of the undersigned, Gary G. Ely, Chairman of the Board, President and Chief Executive Officer of Avista Corporation (the "Company"), and Malyn K. Malquist, Senior Vice President, Chief Financial Officer and Treasurer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company's Annual Report on Form 10-K for the year ended December 31, 2003 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company. March 8, 2004 /s/ Gary G. Ely ------------------------------------ Gary G. Ely Chairman of the Board, President and Chief Executive Officer /s/ Malyn K. Malquist ------------------------------------ Malyn K. Malquist Senior Vice President, Chief Financial Officer and Treasurer