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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


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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  

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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

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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

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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

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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

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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.

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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

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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.

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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.

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

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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

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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.

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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  

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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).

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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-

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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.

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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.

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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.

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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.

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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.”

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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.

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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;

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  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

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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

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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 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 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.

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.

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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. The IPUC has also directed Avista Utilities to work with the IPUC staff and interested customers to address concerns with respect to risk management policies as it pertains to long-term fuel supply contracts. As directed by the IPUC, Avista Utilities addressed this issue in its February 2004 electric general rate case filing.

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

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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.

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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

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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

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.

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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

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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

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(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.

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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.

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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

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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).

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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.

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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.

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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)   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).

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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.

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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.

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.

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 “Business Risk” for further information.

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

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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.

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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

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     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 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

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

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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 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 such, these operations are reported as a discontinued operation. 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.

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.

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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

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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

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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.

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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.

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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.

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. This eliminates Avista Corp.’s future funding requirements for this business while preserving the opportunity, but not the obligation, for future investment.

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

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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.

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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

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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   BB
Avista Capital I*
                       
Preferred Trust Securities
  BB-   Ba2   BB+
Avista Capital II*
                       
Preferred Trust Securities
  BB-   Ba2   BB
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.

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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.

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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.

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(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

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

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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.”

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.

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.

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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.

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

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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

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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

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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

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 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.

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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

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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.

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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.

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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.

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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.

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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