FORM 10-K AVISTA CORP
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)

     
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR
     
  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
incorporation or organization)
  (I.R.S. Employer
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:

     
Title of Class   Name of Each Exchange
on Which Registered

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

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 $696,099,691, based on the last reported sale price thereof on the consolidated tape on February 28, 2002.

As of February 28, 2002, 47,678,061 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

Documents Incorporated By Reference

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

 
Proxy Statement to be filed in
connection with the annual meeting
of shareholders to be held May 9, 2002
  Part III, Items 10, 11,
12 and 13

 


TABLE OF CONTENTS

ACRONYMS AND TERMS
PART I
Item 1. Business
Item 2. Properties
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 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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
Item 13. Certain Relationships and Related Transactions
PART IV
Item 14. Financial Statements, Financial Statement Schedules, Exhibits and Reports on Form 8-K
SIGNATURES
EXHIBIT INDEX
Exhibit 3 (a)
Exhibit 4 (a) 29
Exhibit 12
Exhibit 21


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INDEX

                   
Item           Page
No.           No.

         
    Acronyms and Terms   iv
    Part I        
1.   Business     1  
    Company Overview     1  
    Avista Utilities     4  
    General     4  
    Electric Operations     4  
    Electric Requirements     5  
    Electric Resources     5  
    Future Resource Needs     6  
    Forecasted Electric Energy Requirements and Resources     7  
    Hydroelectric Relicensing     7  
    Natural Gas Operations     8  
    Natural Gas Resources     9  
    Regulatory Issues     9  
    Industry Restructuring     12  
    Federal Level     12  
    State Level     13  
    Environmental Issues     13  
    Avista Utilities Operating Statistics     14  
    Western Power Market Issues     16  
    Energy Trading and Marketing Line of Business     17  
    Avista Energy     17  
    Avista Power     18  
    Information and Technology Line of Business     18  
    Avista Advantage     18  
    Avista Labs     19  
    Other Line of Business     19  
    Discontinued Operations - Avista Communications     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     21  
6.   Selected Financial Data     22  
7.   Management's Discussion and Analysis of Financial Condition and Results of Operations     23  
    Avista Corp. Lines of Business     23  
    Avista Utilities - Regulatory Matters     24  
    Enron Exposure     27  
    Western Power Market Issues     28  
    Results of Operations     29  
    Overall Operations     29  
    Avista Utilities     31  
    Energy Trading and Marketing     33  
    Information and Technology     36  
    Other     36  
    Discontinued Operations     37  
    Critical Accounting Policies     37  
    Liquidity and Capital Resources     39  
    Review of Cash Flow Statement     39  
    Overall Liquidity     40  

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Item           Page
No.           No.

         
    Capital Resources     40  
    Off-Balance Sheet Arrangements     42  
    Total Company Capitalization     42  
    Credit Ratings     42  
    Avista Utilities Operations     43  
    Energy Trading and Marketing Operations     43  
    Information and Technology Operations     44  
    Other Operations     44  
    Contractual Obligations     44  
    Other Commercial Commitments     45  
    Additional Financial Data     45  
    Future Outlook     45  
    Business Strategy     45  
    Competition     45  
    Business Risk     46  
    Risk Management     48  
    Economic and Load Growth     49  
    Environmental Issues     49  
    Other     50  
    Safe Harbor for Forward-Looking Statements     50  
7A.   Quantitative and Qualitative Disclosure about Market Risk     51  
8.   Financial Statements and Supplementary Data     51  
    Independent Auditors' Report     52  
    Financial Statements     53  
    Notes to Consolidated Financial Statements     60  
9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     *  
    Part III        
10.   Directors and Executive Officers of the Registrant     89  
11.   Executive Compensation     90  
12.   Security Ownership of Certain Beneficial Owners and Management     90  
13.   Certain Relationships and Related Transactions     90  
    Part IV        
14.   Financial Statements, Financial Statement Schedules, Exhibits and Reports on Form 8-K     91  
    Signatures     92  
    Independent Auditors' Consent     93  
    Exhibit Index     94  

* = not an applicable item in the 2001 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 electrical energy over time
AFUCE   - -   Allowance for Funds Used to Conserve Energy; a carrying charge similar to AFUDC (see below) for conservation-related capital expenditures
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
Avista Capital   - -   Parent company to the Company’s non-regulated businesses
Avista Corp.   - -   Avista Corporation, the Company
BPA   - -   Bonneville Power Administration
Capacity   - -   a measure of the rate at which a particular generating source produces electricity
Centralia   - -   the coal-fired Centralia Power Plant in western Washington State
Colstrip   - -   the coal-fired Colstrip Generating Project in southeastern Montana
CPUC   - -   California Public Utilities Commission
CT   - -   combustion turbine; a natural gas-fired unit
Energy   - -   a measure of the amount of electricity produced from a particular generating source over time
FERC   - -   Federal Energy Regulatory Commission
IPUC   - -   Idaho Public Utilities Commission
KV   - -   Kilovolt — a measure of capacity on transmission lines
KW, KWH   - -   Kilowatt, kilowatthour, 1000 watts or 1000 watt hours
MW, MWH   - -   Megawatt, megawatthour, 1000 KW or 1000 KWH
OPUC   - -   Public Utility Commission of Oregon
Therm   - -   Unit of measurement for natural gas; a therm is equal to one hundred cubic feet (volume) or 100,000 BTUs (energy)
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
WSCC   - -   Western Systems 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.

Item 1. Business

Company Overview

Avista Corporation (Avista Corp. or the Company) was incorporated in the State of Washington in 1889. Avista Corp. is an energy company involved in the generation, transmission and distribution of energy as well as other energy-related businesses. As of December 31, 2001, the Company’s employees included approximately 1,435 people in its utility operations and approximately 740 people in its subsidiary businesses. The Company’s corporate headquarters are in Spokane, Washington, which serves as the Inland Northwest center for manufacturing, transportation, health care, education, communication, agricultural and service businesses.

The Company is currently organized into four lines of business — Avista Utilities, Energy Trading and Marketing, Information and Technology, and Other. Avista Utilities, an operating division of Avista Corp. and not a separate entity, represents the regulated utility operations. Avista Utilities is responsible for electric generation and transmission, and electric and natural gas distribution services. Avista Utilities also engages in wholesale purchases and sales of electric capacity and energy. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies engaged in the other non-regulated lines of business. The Energy Trading and Marketing line of business includes Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). The Information and Technology line of business includes Avista Advantage, Inc. (Avista Advantage) and Avista Labs, Inc. (Avista Labs). The Other line of business includes Avista Ventures, Inc. (Avista Ventures), Avista Capital (parent company only amounts) and several other minor subsidiaries. In September 2001, the Company made a decision to discontinue the operations of Avista Communications, Inc. (Avista Communications), previously included in the Information and Technology line of business. As of December 31, 2001, the Company had common equity investments of $368.7 million and $351.4 million in Avista Utilities and Avista Capital, respectively.

Avista Utilities seeks to maintain a strong, low-cost and efficient electric and natural gas utility business focused on providing reliable, high quality service to its customers. The utility business is expected to grow modestly, consistent with historical trends. Expansion will primarily result from economic growth in its service territory. It is Avista Utilities’ strategy to own or control a sufficient amount of resources to meet its retail and wholesale electric requirements on an average annual basis. During 2000, Avista Energy scaled back its operations regionally to work primarily within the Western Systems Coordinating Council (WSCC) and has focused on reducing the size and the risk associated with its energy trading and marketing activities. Avista Energy’s marketing efforts are expected to be driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WSCC, as well as its relationship-focused approach to its customers. During 2001, the Company decided that Avista Power would no longer pursue the development of additional non-regulated generation plants. The Company intends to find equity partners to assist in financing the continued growth of the Information and Technology businesses, Avista Advantage and Avista Labs. The Company plans to dispose or phase out of assets and operations that are not related to its energy operations.

The Company’s operations are exposed to risks including, but not limited to, legislative and governmental regulations; the price and supply of purchased power, fuel and natural gas; recovery of purchased power and purchased natural gas costs; weather conditions; availability of generation facilities; competition; technology and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale purchases and sales.

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Following is a list of the major subsidiaries of Avista Capital:

     
Avista Energy -   An electricity and natural gas trading and marketing company, operating primarily in the WSCC.
Avista Power -   Originally formed to develop and own generating assets. In 2001, the Company decided that Avista Power would no longer pursue the development of additional non-regulated generating plants. Avista Power continues to manage the generation assets it currently owns.
Avista Advantage -   Provider of internet-based facility intelligence and cost management services to commercial and industrial customers in North America.
Avista Labs -   Developed a unique modular proton exchange membrane (PEM) fuel cell that delivers reliable, affordable and clean distributed power solutions. In addition to its PEM fuel cell, Avista Labs seeks to commercialize selected components to complement its fuel cell in order to deliver system solutions to industrial, commercial and residential markets.

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

subsidiaries of Avista Capital Flow Chart

— denotes a business entity.
¡ — denotes an operating division or line of business.

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For the years ended December 31, 2001, 2000 and 1999, respectively, the four business segments of the Company contributed the following percentages of consolidated operating revenues, gross margins and income from operations (pre-tax):

                                                                         
                                                    Income from
    Operating Revenues   Gross Margins   Operations (pre-tax)
   
 
 
    2001   2000   1999   2001   2000   1999   2001   2000   1999
   
 
 
 
 
 
 
 
 
Avista Utilities
    21 %     19 %     14 %     74 %     46 %     105 %     68 %     1 %     402 %
Energy Trading and Marketing
    83 %     83 %     84 %     26 %     54 %     (5 )%     56 %     115 %     (276 )%
Information and Technology
                      n/a       n/a       n/a       (18 )%     (12 )%     (25 )%
Other
                2 %     n/a       n/a       n/a       (6 )%     (4 )%     (1 )%
Intersegment eliminations
    (4 )%     (2 )%                                          

n/a — not applicable

The table above only includes results from continuing operations.

Gross margin is calculated as operating revenues less resource costs and is only calculated for Avista Utilities and Energy Trading and Marketing. (See “Schedule of Information by Business Segments in the Consolidated Financial Statements” for further information).

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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 its resource management and load-serving obligations.

Avista Utilities provides electric and natural gas distribution and transmission services in a 26,000 square mile area in eastern Washington and northern Idaho with a population of approximately 830,000. It also provides natural gas distribution service in a 4,000 square mile area in northeast and southwest Oregon and in the South Lake Tahoe region of California, with the population in these areas approximating 525,000. At the end of 2001, Avista Utilities supplied retail electric service to approximately 317,000 customers in eastern Washington and northern Idaho and retail natural gas service to approximately 284,000 customers in parts of Washington, Idaho, Oregon and California.

Avista Utilities anticipates residential and commercial electric load growth to average between 2.0 and 3.0 percent annually for the next five years, primarily due to expected increases in both population and the number of businesses in its service territory. The number of electric customers is expected to increase; however, the average annual usage by residential customers is not expected to change significantly. For the next five years, Avista Utilities expects natural gas load growth, including transportation volumes, to average between 1.5 and 2.0 percent annually in Washington and Idaho and between 2.0 and 3.0 percent annually in the Oregon and South Lake Tahoe service areas. The natural gas load growth is primarily due to expected conversions from electric space and water heating to natural gas, and increases in both population and the number of businesses in Avista Utilities’ service territories. These 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 — Future Outlook” for additional information.

Electric Operations

In addition to providing electric transmission and distribution services, Avista Utilities generates electricity for sales to retail customers. Avista Utilities owns and operates eight hydroelectric projects, a wood-waste fueled generating station and a two-unit natural gas-fired combustion turbine (CT) generating facility. 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. In addition, 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 plans to add new generation assets in 2002 with the planned completion of the Coyote Springs 2 project and the addition of two small generation facilities.

Historically, Avista Utilities’ electric rates to retail customers have been among the lowest of investor-owned utilities in the United States, due primarily to its large proportion of hydroelectric resources as compared to other investor-owned utilities. Retail electric rates remain low, relative to other investor-owned utilities in the United States, even after the enactment of recent temporary surcharges and rate increases. See “Regulatory Issues-Power Cost Deferrals” for further information.

Avista Utilities sells and purchases electric capacity and energy to and from utilities and other entities in the wholesale market under long-term contracts having terms of more than one year. In addition, Avista Utilities engages in an ongoing process of resource optimization which involves short-term purchases and sales in the wholesale market in pursuit of an economic selection of resources to serve retail and wholesale loads. 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 a quarterly, monthly, daily and hourly basis to match actual resources to actual energy requirements and to sell any surplus at the best available price. This process includes hedging transactions.

Avista Utilities competes in the electric wholesale market with other utilities, federal marketing agencies and power marketers. The electric wholesale market has changed significantly over the last few years with respect to market participants involved, level of activity, variability of prices, FERC-imposed price caps and counterparty credit issues. These changes contributed to the increased volatility of the wholesale market during 2000 and the first half of 2001. During the second half of 2001 wholesale market prices and volatility both decreased to levels similar to those

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experienced before 2000. See “Western Power Market Issues” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations -Western Power Market Issues” for more information.

Challenges facing Avista Utilities’ electric operations include, among other things, the ability to recover deferred power supply costs and the timing of such recovery, changes in the availability of and volatility in the prices of power and fuel, generating unit availability, legislative and governmental regulations, and weather conditions. Avista Utilities believes it faces minimal risk for stranded utility assets resulting from deregulation due to its relatively low-cost generation portfolio. In a deregulated environment, however, evolving technologies that provide alternate energy supplies could affect the market price of power, and certain generating assets could have capital and operating costs above the adjusted market price. Avista Utilities may also be exposed to refunds for wholesale power sales depending on the outcome of the FERC’s retroactive price cap proceeding for the Pacific Northwest; however, Avista Utilities would have the opportunity to establish offsetting claims. See “Industry Restructuring,” “Western Power Market Issues,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Western Power Market Issues” and “Note 1 of Notes to Consolidated Financial Statements” for additional information.

Electric Requirements

Annual peak requirements for 2001 were 3,234 MW (including long-term wholesale obligations of 937 MW and short-term wholesale obligations of 797 MW). This peak occurred on January 16, 2001 at which time the maximum resource capacity available from Avista Utilities was 3,553 MW. The maximum resource capacity included 1,418 MW of company-owned electric generation, 144 MW from long-term hydroelectric contracts, 548 MW of other long-term wholesale purchases and 1,443 MW of short-term wholesale purchases. Variations in energy usage by Avista Utilities’ customers occur from year to year, from season to season and from month to month within a season, primarily as a result of weather conditions. 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’ diverse electric resource mix of hydroelectric projects, thermal generating facilities, and power purchases and exchanges, combined with strategic access to regional electric transmission systems, enables it to remain a low-cost producer of electric energy. As of December 31, 2001, Avista Utilities’ total owned and leased resource capability was approximately 1,480 MW, of which 65 percent was hydroelectric and 35 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 MWh of electricity and the availability of hydroelectric generation has a significant effect on its total power supply costs. Under average operating conditions, Avista Utilities projects that it would be able to meet approximately one-half of its total electric requirements (both retail and long-term wholesale) with its own hydroelectric generation and fixed long-term hydroelectric contracts with certain Public Utility Districts in Washington state. Total hydroelectric resource generation (both company-owned and purchased under long-term hydroelectric contracts) was 3.2 million MWhs in 2001, a decrease from 4.7 million MWhs in 2000 and 5.4 million MWhs in 1999.

Total hydroelectric resources (including resources purchased under long-term hydroelectric contracts) provide 550 aMW (or 4.8 million MWhs) annually under normal streamflow conditions. The streamflows to company-owned hydroelectric projects were 56 percent, 86 percent and 112 percent of normal in 2001, 2000 and 1999, respectively. In a “critical water” year (defined by the Northwest Power Pool as the worst water conditions on record), Avista Utilities would expect hydroelectric production of 400 aMW, 150 aMW below normal. Average hydroelectric production for the year 2001 was 369 aMW, which is 181 aMW below normal and 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 the year 2001 significantly in excess of the amount of power supply costs recovered through retail rates in effect at the time. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Avista Utilities-Regulatory Matters” for more information.

Thermal Resources Avista Utilities has a 15 percent interest in a twin-unit, coal-fired generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana. Avista Utilities also 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). In addition, Avista Utilities also leases and operates a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT).

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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. Avista Utilities is purchasing energy from TransAlta to replace the output from Centralia for the period from July 1, 2000 through December 31, 2003. Avista Utilities receives approximately 200 megawatts per hour during the term of the contract beginning each July and continuing through March of the following year.

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

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 the plant.

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

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

                         
    2001   2000   1999
   
 
 
Centralia
          493       1,224  
Colstrip
    1,617       1,473       1,622  
Kettle Falls
    361       370       273  
Northeast CT and Rathdrum CT
    1,023       817       234  
 
   
     
     
 
Total thermal generation
    3,001       3,153       3,353  
 
   
     
     
 

Purchases, Exchanges and Sales Avista Utilities purchases power under various long-term purchase 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 Energy Resources” for more detailed information with respect to purchased power and power from exchanges in 2001, 2000 and 1999.

Future Resource Needs

In August 2000, the WUTC approved Avista Utilities’ plan to increase its power resources to serve long-term electric requirements. The Company evaluated 32 third-party supply-side and demand-side proposals submitted through the request-for-proposal process in 2000. In December 2000, Avista Utilities selected the Coyote Springs 2 project, located near Boardman, Oregon, as the supply-side option.

The Coyote Springs 2 project is a combined-cycle, natural gas-fired combustion turbine with generation output of approximately 280 MW. Engineering and procurement of required major equipment began in January 2001. In December 2001, the Company completed the sale of 50 percent of its interest in the Coyote Springs 2 project to an affiliate of Mirant Americas Development, Inc. (Mirant). The Company and Mirant are sharing equally in the costs of construction, operation and output from the plant. The total cost of the plant is expected to be approximately $190 million. Upon completion of construction, expected to be in the third quarter of 2002, the Company’s 50 percent ownership interest in the Coyote Springs 2 project will be transferred from Avista Power to Avista Corp. to be operated as an asset of Avista Utilities.

Due to the shortage of hydroelectric generation and high wholesale market prices during the first half of 2001, Avista Utilities initiated the process of placing several small diesel and natural gas-fired generators into operation at sites in its

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service territory. Due to the reduction in wholesale market prices during the second half of 2001, Avista Utilities reevaluated the cost of the small generation units and will not operate as many of the units as originally planned. The Boulder Park generation facility (Boulder Park) located in Spokane County and a small combustion generation unit in Kettle Falls, Washington (Kettle Falls CT) will be in operation by mid-2002. These projects have a combined generation capability of 32 MW.

As part of the strategy to mitigate the decrease in electric resources caused by the low hydroelectric availability and volatile energy markets, Avista Utilities implemented several buy-back and rebate programs for retail customers during 2001. The programs were designed to encourage conservation and decrease average customer usage.

Avista Utilities has operational strategies to ensure that it has available resources sufficient to meet the increased demand for energy. Under normal water conditions and loads, Avista Utilities’ hydroelectric and thermal generation and long-term contracts would have been able to provide 100 percent of its forecasted native retail load and wholesale energy requirements during 2001. Avista Utilities has made purchases to enable it to cover its electric energy requirements for 2002 and believes that it will be in a surplus power position in 2003 and 2004 under normal water conditions.

Forecasted Electric Energy Requirements and Resources
(aMW)

                               
          2002   2003   2004
         
 
 
Requirements:
                       
 
System load
    1,001       1,021       1,055  
 
Contracts for power sales
    48       24       7  
 
   
     
     
 
   
Total Requirements
    1,049       1,045       1,062  
 
   
     
     
 
Resources:
                       
 
System and contract hydro (1)
    550       550       550  
 
Company owned thermal generation (2)
    299       361       366  
 
Contracts for purchased power
    275       264       244  
 
   
     
     
 
   
Total Resources
    1,124       1,175       1,160  
 
   
     
     
 
     
Surplus Resources
    75       130       98  

(1)   Assumes normal water conditions, which is the mean of the 60 years between 1928 and 1988. Preliminary forecasts indicate streamflows are expected to be 87 percent of normal in 2002 based on current snow pack conditions. Avista Utilities currently estimates that hydroelectric generation will be 534 aMW in 2002.
(2)   Includes new generation available in 2002 from the Company’s 50 percent ownership in the Coyote Springs 2 project. Forecast assumes no generation from the Northeast CT and the Rathdrum CT, which are generally only used to meet peaking electric load requirements, and/or when operating costs are lower than short-term wholesale market prices.

Significant Customer A contract with Avista Utilities’ largest customer, Potlatch Corporation (Potlatch), expired on December 31, 2001. Since 1992 Potlatch had received service under a special contract under the PURPA. Potlatch’s Lewiston, Idaho facility includes about 100 aMW of electric requirements and approximately 60 aMW of self-generation that is currently economic to operate. Avista Utilities and Potlatch are currently negotiating a new agreement. As part of the new agreement, the parties have agreed that Potlatch will receive electric service from Avista at large industrial tariff (Schedule 25) rates. Potlatch is currently using its generation for its own electric requirements, which results in a net electric requirement on Avista Utilities’ system of approximately 40 aMW. Although Potlatch would like to sell its generation output, the current market price for wholesale electricity is below the Schedule 25 rates, therefore Potlatch uses its generation to meet its electric requirements. The ultimate resolution of this contract could have an impact on Avista Utilities’ resource planning, that Avista Utilities is working to minimize through continued negotiations of the terms and conditions associated with service to Potlatch under Schedule 25 rates. Any changes in the revenue and expense associated with serving Potlatch would be reflected in the Idaho power cost adjustment mechanism (PCA).

Hydroelectric Relicensing

Avista Corp. is a licensee under the Federal Power Act, which regulates certain of its hydroelectric generation resources, and is administered by the FERC. Avista Corp.’s licensed projects are subject to the provisions of Part I of that 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

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investment” or “fair value” of the project, in either case, plus severance damages. All but one of the Company’s hydroelectric plants are regulated by the FERC through project licenses issued for 30-50 year periods.

In February 2000, Avista Utilities received a 45-year operating license from the FERC for the Cabinet Gorge and Noxon Rapids Hydroelectric Generating Developments. The Clark Fork Settlement Agreement, included as part of the FERC license procedures, preserved the projects’ economic peaking and load following operations. 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 will 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 Settlement Agreement, were addressed by both the WUTC and IPUC and received favorable treatment. 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. The ongoing Clark Fork Settlement Agreement costs are recorded as operating expenses. See “Item 2. Properties — Avista Utilities” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Future Outlook” for additional information.

The issue of high levels of dissolved gas which exceed Idaho water quality standards downstream of Cabinet Gorge during spill periods 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 minimal biological effects of high dissolved gas levels on free ranging fish. An engineering feasibility study identified several possible structural alternatives at Cabinet Gorge that may reduce dissolved gas levels. Under the terms of the Clark Fork Settlement Agreement, the Company will develop an abatement and/or mitigation strategy in 2002 in conjunction with the other signatories to the agreement.

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. The sixth, Little Falls, is not licensed by the FERC. The license for the Spokane River Projects expires in August 2007; the Company will file a notice of intent to relicense before August 2002. Planning, discussions with stakeholder groups and information gathering activities are ongoing.

Natural Gas Operations

Natural gas commodity prices increased dramatically during 2000 and remained high during the first half of 2001 before declining during the second half of the year. 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 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 based on the levels of existing reserves and potential natural gas development in the future. Growth has occurred in the natural gas business due to increased demand for natural gas in new construction, as well as conversions from electric space and water heating to natural gas.

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 its pipeline interconnection to the customer’s premises. Seven of Avista Utilities’ largest natural gas customers are provided natural gas transportation service under individual contracts. These negotiated contracts were entered into to retain these customers who can either by-pass Avista Utilities’ distribution system or have competitive alternative fuel capability. All individual contracts are subject to regulatory review and approval. The competitive nature of the natural gas spot market results in savings in the cost of purchased natural gas, which encourages large customers with fuel-switching capabilities to continue to utilize natural gas for their energy needs when economic. The total volume transported on behalf of transportation customers for 2001, 2000 and 1999 was 180.9, 224.8 and 232.4 million therms, which represented approximately 33 percent, 38 percent and 35 percent of Avista Utilities’ total system deliveries, respectively.

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, conservation and the ability to recover natural gas costs.

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Natural Gas Resources

Natural Gas Supply Natural gas supplies are available from domestic and Canadian sources through both long- and short-term, or spot market, purchases. Avista Utilities has capacity delivery rights on six 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 trading and marketing subsidiary, Avista Energy, is 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 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 important resources. The utility commissions have approved Benchmark Incentive Mechanisms that allow Avista Utilities and its customers to share the benefits of Avista Energy’s resource optimization activities. See “Regulatory Issues: Natural Gas Benchmark Mechanism” and “Note 1 of Notes to Consolidated Financial Statements” for additional information.

Firm natural gas supplies are available through negotiated agreements for terms ranging between one month and seven years. Approximately 25 percent of the natural gas supplies are obtained from domestic sources, with the remaining 75 percent from Canadian sources. Nearly all natural gas purchased from Canadian sources is contracted in U.S. dollar denominations, limiting any foreign currency exchange exposure. Canadian natural gas supplies are not considered to be at greater risk of non-delivery than supplies from the United States.

Jackson Prairie Natural Gas Storage Project (Jackson Prairie Storage Project) Avista Utilities owns a one-third interest in the Jackson Prairie Storage Project, an underground natural gas storage field located near Chehalis, Washington. The role of the Jackson Prairie Storage Project 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 withdraw natural gas from storage when spot prices are high or as needed to meet high demand periods. During 1999, the process of increasing the capacity at the Jackson Prairie Storage Project was completed. This increased capacity is being operated and managed by Avista Energy for a ten-year period. Avista Utilities has contracted to release a total of approximately 43 percent of its Jackson Prairie Storage Project 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 Utility Commission (OPUC) and the California Public Utilities Commission (CPUC). The Company is also subject to the jurisdiction of the FERC for its wholesale natural gas rates charged for the release of capacity from the Jackson Prairie Storage Project, and for electric transmission service and wholesale electric sales. The FERC also issued orders with respect to a price mitigation plan applicable to certain wholesale power transactions throughout the western United States during the period June 2001 through September 2002. See “Western Power Market Issues” for additional information.

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 currently 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 of utility plant. As the energy business is restructured, traditional “cost of service” ratemaking may evolve into some other form of ratemaking. Rates for 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.

Power Cost Deferrals In August 2000, the WUTC approved Avista Utilities’ request for deferred accounting treatment for certain power costs related to, among other things, increases in short-term wholesale electric prices from July 1, 2000 through June 30, 2001. Avista Utilities is permitted to defer the recognition in the income statement of the portion of power supply costs that is in excess of the level currently recovered from retail customers. Deferred power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through retail

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rates. The specific power costs deferred include the changes in power costs to Avista Utilities from the costs included in base retail rates, related to changes in short-term wholesale market prices, changes in the level of hydroelectric generation and changes in the level of thermal generation (including changes in fuel prices). In January 2001, the WUTC approved a modification to the deferral mechanism to recover power supply costs associated with meeting increased retail and wholesale system load requirements, effective December 1, 2000.

In May 2001, the WUTC approved a settlement agreement reached among Avista Corp., the staff of the WUTC and other parties with respect to deferred power costs. The agreement, among other things, provided for the extension of Avista Corp.’s deferred accounting mechanism through February 2003. During June and the first part of July of 2001, Avista Utilities evaluated the effect of several significant developments that changed its plans for the recovery of deferred power costs. These developments included a decline in hydroelectric availability, the increased cost of energy and capacity to meet retail and wholesale demand for 2001 and a decline in wholesale market prices. As such, Avista Utilities determined that its plan for recovery of deferred cost balances, as contemplated in the May 2001 settlement agreement with the WUTC and the existing PCA with the IPUC, was not feasible.

Accordingly, in July 2001 Avista Utilities filed requests with the WUTC and IPUC for the approval of an electric energy surcharge of 36.9 percent in Washington and a PCA surcharge of 14.7 percent in Idaho for a 27-month period beginning in September 2001.

In September 2001, the WUTC ordered a 25 percent temporary electric rate surcharge for the 15-month period from October 1, 2001 to December 31, 2002 applied uniformly across all Washington electric customer classes. As part of the surcharge order, the WUTC ordered Avista Utilities to file a general rate case by December 2001. The order by the WUTC also provided for the termination of the accounting mechanism for the deferral of power costs effective December 31, 2001. The WUTC subsequently approved the continuation of the accounting mechanism for deferred power costs for the period from January 1, 2002 through the conclusion of the general rate case.

In November 2001, Avista Utilities filed a request with the WUTC for an expedited procedural schedule to address the prudence and recoverability of deferred power costs incurred as of September 30, 2001. In March 2002, the WUTC issued an order approving the prudence and recoverability of 90 percent of deferred power supply costs incurred during the period from July 1, 2000 through December 31, 2001. This resulted in the Company expensing $21.8 million of power supply costs previously deferred.

In October 2001, the IPUC issued an order approving a 14.7 percent PCA surcharge for Idaho electric customers and granted an extension of a 4.7 percent PCA surcharge implemented earlier in 2001 that was to expire January 31, 2002. Both PCA surcharges will remain in effect until October 11, 2002. The IPUC directed Avista Utilities to file a status report 60 days before the PCA surcharge expires. If review of the status report and the actual balance of deferred power costs support continuation of the PCA surcharge, the IPUC has indicated that it anticipates the PCA surcharge would be extended for an additional period. The current PCA mechanism allows for the deferral of 90 percent of the difference between actual net power supply expenses and the authorized level of net power supply expense approved in the last Idaho general rate case.

As of December 31, 2001, total deferred power costs were $213.3 million, including $140.2 million in Washington and $73.1 million in Idaho. In 2001, revenue collected under the Washington and Idaho surcharges totaled $14.4 million and deferred power costs were further reduced $60.7 million through the amortization of a deferred non-cash credit. Based on current projections, total deferred power costs balances are expected to be approximately $150 million at the end of 2002 and fully recovered by 2007.

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 In October 1999, Avista Utilities filed with the WUTC a request for a general electric rate increase of $26.2 million, or 10.4 percent, subsequently revised to $18.2 million, and a general natural gas rate increase of $4.9 million, or 6.5 percent. In September 2000, the WUTC ordered a $3.4 million, or 1.4 percent, reduction in electric rates and a $1.7 million, or 2.1 percent, increase in natural gas rates. The WUTC also ordered that Avista Utilities’ overall rate of return for both electricity and natural gas be reduced from 10.7 percent to 9.03 percent. Avista Utilities had requested a 9.9 percent overall rate of return. Avista Utilities filed a Petition for Reconsideration with the WUTC requesting that the commission reconsider certain portions of its order. In November 2000, the Commission slightly modified the original order, reducing the electric reduction from $3.4 million to $2.9 million and increasing the natural gas increase from $1.7 million to $1.8 million.

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On December 3, 2001, the Company filed a general electric rate case with the WUTC, as ordered by the WUTC in September 2001. Issues to be addressed include, among other things, the recovery of cash outlays for increased power supply costs and expenses related to building additional generation. The rate case requested by Avista Corp. proposes a 10.39 percent overall rate of return. The WUTC may take up to 11 months to review the general rate case filing.

In the rate case filing with the WUTC, Avista Corp. requested an interim rate increase of 10 percent (or $29.3 million in annual revenues) above current rates (including the 25 percent temporary surcharge approved by the WUTC in September 2001 discussed above). In March 2002, the WUTC ordered an increase to base retail rates of 6.2 percent (or $14.7 million in annual revenues). The order also modified the temporary electric surcharge such that one-fifth of the existing 25 percent surcharge will be applied to offset the Company’s general operating costs and the remainder will continue to be applied as a recovery of deferred power costs. In the general rate case filing, the Company requested that a number of adjustments be made that would result in no net change to rates above the interim rate increase. The Company requested that once the interim rate increase ends, base electric rates would increase by 22.5 percent (or $53.2 million in annual revenues) and the electric surcharge would be reduced from 25 percent to 14.9 percent. These rate increases are necessary in order to continue the recovery of deferred power costs. The proposed rate increases also reflect, among other things, the recovery of costs associated with the addition of the Company’s 50 percent ownership in the Coyote Springs 2 power plant and the construction of two small generation projects built to serve retail customer needs.

In the general rate case, Avista Corp. requested the implementation of a temporary accounting mechanism for the deferral of power supply costs incurred in excess of the amount recovered through rates effective January 1, 2002 until the conclusion of the general rate case. The WUTC approved this request on December 21, 2001. In the general rate case, Avista Corp. requested the establishment of a permanent PCA mechanism to increase or decrease future electric rates based on actual power supply costs, similar to the Idaho PCA mechanism that allows for the deferral of 90 percent of the difference between actual net power supply costs and the authorized level of net power supply costs.

In Avista Utilities’ last general electric rate case in Idaho, the IPUC granted a rate increase of $9.3 million, or 7.6 percent, with an authorized rate of return of 8.98 percent, effective August 1999.

Purchased Gas Adjustment (PGA or Natural Gas Trackers) Natural gas trackers are supplemental tariffs filed with state regulatory commissions designed to pass through changes in purchased natural gas costs, and do not normally result in any changes in net income. In July 2001, Avista Utilities filed requests for PGAs with the WUTC and the IPUC. Both the Washington PGA increase of 12.2 percent approved by the WUTC and the Idaho PGA increase of 11.5 percent approved by the IPUC became effective in August 2001. Avista Utilities estimates these PGA rate changes will increase revenues by $24.6 million for approximately one year. Total deferred natural gas costs were $52.7 million as of December 31, 2001. Based on current PGAs in place and current natural gas prices, Avista Utilities expects that the deferred natural gas cost balance will be fully recovered by December 2002.

Natural Gas Benchmark Mechanism Avista Utilities received regulatory approval of its Natural Gas Benchmark Mechanism in 1999 from the IPUC, WUTC and OPUC. The mechanism eliminated natural gas procurement operations within Avista Utilities for these jurisdictions and consolidated gas procurement operations under Avista Energy, the Company’s non-regulated affiliate. The ownership of the natural gas assets remains with Avista Utilities; however, Avista Energy through an Agency Agreement with Avista Utilities manages the assets. Avista Utilities maintains a natural gas staff to prepare load forecasts and analyses related to long-term resource acquisitions, to manage the Agency Agreement with Avista Energy and to support state and federal regulatory activities.

Consolidation of natural gas procurement operations under Avista Energy allows the Company to gain synergies and better manage its risk by combining and operating the two portfolios as a single portfolio and to gain efficiencies by eliminating duplicate functions. Effective January 1, 2001, the WUTC and IPUC approved Avista Utilities’ modifications to the Natural Gas Benchmark Mechanism, incorporating the use of financial products (fixed-price transactions or hedging). Due to the unprecedented increase in and volatility of natural gas commodity costs, it was determined that such additional flexibility was needed in the Natural Gas Benchmark Mechanism to properly manage costs. The Natural Gas Benchmark Mechanism provides certain guaranteed benefits to retail customers and provides the Company with the opportunity to improve earnings (a performance-based mechanism).

Avista Utilities provided notice of its intent to continue the Natural Gas Benchmark Mechanism and related Agency Agreement with Avista Energy to the applicable state regulatory agencies in 2001. In early 2002, the WUTC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2003 and the IPUC approved the continuation through March 31, 2005. The OPUC is expected to make its ruling in late March 2002.

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Demand Side Management (DSM) and Low-Income Assistance Programs DSM programs are designed to encourage conservation of energy. In February 2001, the WUTC and the IPUC approved Avista Utilities’ implementation of a natural gas revenue surcharge of 0.5 percent to provide funding for natural gas energy-efficiency programs. Avista Utilities currently has electric revenue surcharges, or tariff riders, of approximately 1.5 percent in Washington and Idaho to fund its electric DSM programs. The tariff rider has been in place since 1995 and was the first “system benefit charge” for energy efficiency in the United States.

Effective May 2001, the WUTC approved an increase in electric and natural gas surcharges, or tariff rider, of 0.79 percent to supplement the Community Action Agency’s existing federal and state low-income heating energy assistance program and Project Share funds. The annual revenue of approximately $2.7 million funds eastern Washington agencies assistance to help in-need customers pay their energy bills.

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 capacity for the purpose of providing these services. It also created “exempt wholesale generators”, a new 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.

Avista Corp. and three other Western utilities have taken steps toward the formation of a for-profit Independent Transmission Company (ITC), TransConnect, which would serve portions of six states. TransConnect would be a member of the planned regional transmission organization, RTO West, a non-profit entity, and it would own or lease the high voltage transmission facilities currently held by Avista Corp., Portland General Electric Co., Nevada Power Co. and Sierra Pacific Power Co. A proposal was filed in October 2000 in response to the FERC’s Order No. 2000, which requires 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. In April 2001, the FERC issued the RTO West/TransConnect order granting, with modifications, the participating companies’ petition. Avista Corp. is actively evaluating this order to determine the effects of the modifications and the impact to the potential development of TransConnect. TransConnect filed its proposal with FERC in November 2001. Avista Corp. only joined in the planning protocol modified governance for this filing. The final proposal must be approved by the FERC, the boards of directors of the filing companies and regulators in various states. The companies’ decision to move forward with the formation of TransConnect or RTO West will ultimately depend on the conditions related to the formation of the entities, as well as the economics and conditions imposed in the regulatory approval process. If TransConnect were formed, it could result in Avista Utilities divesting $174 million of electric transmission assets.

The North American Electric Reliability Council and the WSCC 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.

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State Level

Further competition may be introduced by state action. Competition 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 the lowest electric rates in the country. Although there is currently no action surrounding deregulation in Washington or Idaho, activities related to California’s deregulation have affected wholesale power prices in the western United States, including the Company’s service territory. See “Western Power Market Issues” for information about the California energy situation.

An initiative was presented in November 2001 in Montana to create a public agency to own and operate all hydroelectric generating facilities within the state. Avista Utilities’ largest generation plant, Noxon Rapids, is located in Montana on the Clark Fork River. If this proposed initiative obtains the required signatures by June 21, 2002 and is passed into law in the November 2002 General Election, Noxon Rapids could be acquired from the Company either through a negotiated sale or at fair market value through a condemnation proceeding. This could have significant negative ramifications for the Company. As such, the Company intends to vigorously oppose this initiative and intends to legally defend itself against the acquisition of Noxon Rapids. See “Note 24 of Notes to Consolidated Financial Statements” for additional information.

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 anticipate emerging environmental issues. The Company’s Board of Directors has an Environmental Committee to deal specifically with these issues.

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. Colstrip is not expected 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 project 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 issued in December 2000. During 2001, the Company applied to renew the operating permit for the Kettle Falls plant and applied for an upgrade to a Title V permit for the natural gas-fired CTs located in Spokane. The Company anticipates the receipt of these operating permits during the second quarter of 2002. Additionally, the Company received operating permits for several small generation projects during 2001. Due to the decline in wholesale market prices during the second half of 2001, Avista Utilities reevaluated the cost of the small generation units and will not operate as many of the units as originally planned.

During 2001, Avista Corp. extended the operating hours of the Northeast CT with an agreement with the Spokane County Air Pollution Control Authority (SCAPCA) under a special operating order called an Assurance of Discontinuance (AOD). The SCAPCA has allowed for continued operation of the Northeast CT upon the condition of a payment of $150 for each hour of operation paid into a mitigation fund for assistance to low-income customers and the payment of $10,000 for each day of operation to fund an environmental offset project. The AOD allows Avista Utilities to use the Northeast CT to temporarily bring on added generating capacity for the benefit of its customers and the region during a time of increased energy demand and limited energy resources. Extended operation of the Northeast CT was approved after the SCAPCA determined, through air emission modeling and projections, that extended operation of the turbine would not adversely impact air quality. The funding of the environmental offset project will be paid until such time as a new operating permit is issued by the SCAPCA. The Company submitted its permit application for permanent operation of the Northeast CT in November 2001.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Future Outlook” and “Note 24 of the Notes to Consolidated Financial Statements” for additional information.

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AVISTA UTILITIES OPERATING STATISTICS

                                 
            Years Ended December 31,
           
            2001   2000   1999
           
 
 
ELECTRIC OPERATIONS
                       
 
ELECTRIC OPERATING REVENUES (Thousands of Dollars):
                       
   
Residential
  $ 158,847     $ 158,065     $ 158,658  
   
Commercial
    155,371       149,770       152,107  
   
Industrial
    80,433       82,992       69,559  
   
Public street and highway lighting
    3,790       3,612       3,517  
 
   
     
     
 
     
Total retail revenues
    398,441       394,439       383,841  
   
Wholesale revenues
    480,903       864,754       522,499  
   
Other revenues
    42,861       28,062       21,824  
 
   
     
     
 
     
Total electric operating revenues
  $ 922,205     $ 1,287,255     $ 928,164  
 
   
     
     
 
 
ELECTRIC ENERGY SALES (Thousands of MWhs):
                       
   
Residential
    3,219       3,279       3,237  
   
Commercial
    2,882       2,886       2,848  
   
Industrial
    1,892       2,048       2,032  
   
Public street and highway lighting
    25       25       25  
 
   
     
     
 
     
Total retail energy sales
    8,018       8,238       8,142  
   
Wholesale energy sales
    6,262       15,807       19,778  
 
   
     
     
 
     
Total electric energy sales
    14,280       24,045       27,920  
 
   
     
     
 
 
ELECTRIC ENERGY RESOURCES (Thousands of MWhs):
                       
   
Hydro generation (from Company facilities)
    2,564       3,819       4,287  
   
Thermal generation (from Company facilities)
    3,001       3,153       3,353  
   
Purchased power — long-term hydro
    631       929       1,093  
   
Purchased power — long-term wholesale
    4,196       5,500       4,791  
   
Purchased power — short-term wholesale
    3,869       10,611       14,308  
   
PURPA contracts
    559       595       598  
   
Power exchanges
    (104 )     67       16  
 
   
     
     
 
     
Total power resources
    14,716       24,674       28,446  
   
Energy losses and Company use
    (436 )     (629 )     (526 )
 
   
     
     
 
     
Total energy resources (net of losses)
    14,280       24,045       27,920  
 
   
     
     
 
 
NUMBER OF ELECTRIC CUSTOMERS (Average for Period):
                       
   
Residential
    276,845       273,219       270,013  
   
Commercial
    35,454       35,060       34,877  
   
Industrial
    1,434       1,254       1,189  
   
Public street and highway lighting
    402       392       389  
 
   
     
     
 
     
Total electric retail customers
    314,135       309,925       306,468  
   
Wholesale
    44       58       68  
 
   
     
     
 
     
Total electric customers
    314,179       309,983       306,536  
 
   
     
     
 
 
ELECTRIC RESIDENTIAL SERVICE AVERAGES:
                       
   
Annual use per customer (KWh)
    11,629       12,003       11,990  
   
Revenue per KWh (in cents)
    4.93       4.82       4.90  
   
Annual revenue per customer
  $ 573.77     $ 578.53     $ 587.59  
 
ELECTRIC AVERAGE HOURLY LOAD (aMW)
    975       1,012       990  
 
   
     
     
 
 
RESOURCE AVAILABILITY at time of system peak (MW):
                       
   
Total requirements (winter):
                       
     
Retail native load
    1,500       1,491       1,351  
     
Wholesale obligations
    1,734       2,338       3,281  
 
   
     
     
 
       
Total requirements (winter)
    3,234       3,829       4,632  
   
Total resource availability (winter)
    3,553       4,194       4,831  
   
Total requirements (summer):
                       
     
Retail native load
    1,379       1,473       1,418  
     
Wholesale obligations
    1,332       2,756       4,590  
 
   
     
     
 
       
Total requirements (summer)
    2,711       4,229       6,008  
   
Total resource availability (summer)
    2,927       4,656       6,633  

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          Years Ended December 31,
         
          2001   2000   1999
         
 
 
NATURAL GAS OPERATIONS
                       
 
NATURAL GAS OPERATING REVENUES (Thousands of Dollars):
                       
   
Residential
  $ 179,584     $ 128,240     $ 99,879  
   
Commercial
    104,012       69,982       51,952  
   
Industrial
    11,130       7,680       5,047  
 
   
     
     
 
     
Total retail natural gas revenues
    294,726       205,902       156,878  
   
Wholesale revenues
    1,762       5,691       15,189  
   
Transportation revenues
    8,576       10,242       10,777  
   
Other revenues
    3,579       3,011       4,640  
 
   
     
     
 
     
Total natural gas operating revenues
  $ 308,643     $ 224,846     $ 187,484  
 
   
     
     
 
 
THERMS DELIVERED (Thousands of Therms):
                       
   
Residential
    198,413       212,198       200,184  
   
Commercial
    126,869       135,126       125,611  
   
Industrial
    15,523       18,350       16,450  
 
   
     
     
 
     
Total retail sales
    340,805       365,674       342,245  
   
Wholesale sales
    4,831       4,034       74,117  
   
Transportation sales
    180,918       224,803       232,388  
   
Interdepartmental sales and Company use
    15,430       1,391       10,152  
 
   
     
     
 
     
Total therms delivered
    541,984       595,902       658,902  
 
   
     
     
 
 
SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):
                       
   
Purchases
    348,620       372,795       430,698  
   
Storage — injections
    (62 )     (467 )     (30,508 )
   
Storage — withdrawals
    54       403       23,972  
   
Natural gas for transportation
    180,918       224,803       232,388  
   
Interdepartmental transportation
    14,662       589       351  
   
Distribution system gains (losses)
    (2,208 )     (2,221 )     2,001  
 
   
     
     
 
     
Total supply
    541,984       595,902       658,902  
 
   
     
     
 
 
NUMBER OF NATURAL GAS CUSTOMERS (Average for Period):
                       
   
Residential
    249,650       242,983       234,844  
   
Commercial
    30,355       29,739       29,032  
   
Industrial
    328       334       338  
 
   
     
     
 
     
Total retail customers
    280,333       273,056       264,214  
   
Wholesale customers
    2       2       9  
   
Transportation customers
    86       96       107  
 
   
     
     
 
     
Total natural gas customers
    280,421       273,154       264,330  
 
   
     
     
 
 
NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
                       
   
Washington and Idaho
 
     
Annual use per customer (therms)
    852       950       887  
     
Revenue per therm (in cents)
    89.24       57.82       45.74  
     
Annual revenue per customer
  $ 760.02     $ 549.07     $ 405.51  
   
Oregon and California
 
     
Annual use per customer (therms)
    688       730       789  
     
Revenue per therm (in cents)
    93.44       66.83       58.59  
     
Annual revenue per customer
  $ 643.31     $ 487.80     $ 462.21  
 
NET SYSTEM MAXIMUM CAPABILITY (Thousands of Therms):
                       
   
Net system maximum demand (winter)
    2,236       2,347       2,077  
   
Net system maximum firm contractual capacity (winter)
    4,320       4,320       4,320  
 
HEATING DEGREE DAYS:(1)
                   
   
Spokane, WA
 
     
Actual
    6,800       7,176       6,408  
     
30 year average
    6,842       6,842       6,842  
     
% of average
    99 %     105 %     94 %
   
Medford, OR
 
     
Actual
    4,143       4,388       4,401  
     
30 year average
    4,611       4,611       4,611  
     
% of average
    90 %     95 %     95 %

(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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Western Power Market Issues

Avista Utilities and Avista Energy are directly and indirectly involved with issues surrounding Western power markets, including the California market. In early 2001, California’s two largest utilities, Southern California Edison (SCE) and Pacific Gas & Electric Company (PG&E), defaulted on payment obligations owed to various energy sellers, including the California Power Exchange (CalPX), California Independent System Operator (CalISO), and Automated Power Exchange (APX). CalPX, CalISO and APX defaulted on their payment obligations to Avista Energy. PG&E and CalPX filed voluntary petitions under chapter 11 of the bankruptcy code for protection from creditors. SCE has remained outside of bankruptcy.

The FERC issued an order in August 2000 initiating hearing proceedings under section 206 of the Federal Power Act to address matters affecting bulk power markets and wholesale energy prices (including volatile price fluctuations) in California. In November 2000 the FERC proposed specific remedies to address dysfunctions in California’s wholesale bulk markets and to ensure just and reasonable wholesale power rates by public utility sellers in California. The FERC denied requested refunds from sellers of electric power for sales prior to October 2, 2000 and held that sales made after October 2, 2000 are subject to refund, with the level and extent of any refund to be determined in future orders. In April 2001, the FERC issued a price mitigation order that affected the CalISO spot market. In June 2001, the FERC expanded its price mitigation plan for the California spot market to 24 hours a day, seven days a week and broadened the price curbs to the eleven state Western region through September 2002. Since June 2001, spot market prices have remained below the FERC-imposed caps.

Earlier in 2001, the Governor of California invoked emergency executive powers to seize certain power contracts (called “block forward contracts”) between the CalPX and, respectively, PG&E and SCE after PG&E’s and SCE’s defaults. The block forward contracts would have been significant assets of the CalPX bankruptcy estate if they had not been so removed by the Governor. PG&E, SCE, the CalPX Creditors Committee, and certain individual creditors filed suits separately against the State of California for compensation related to the seized block forward contracts. In September 2001, the U.S. Court of Appeals for the Ninth Circuit ruled that wholesale energy suppliers are entitled to injunctive relief from the State of California. At this time, it is not possible to predict the timing or outcome of this claim against the State of California.

In July 2001, the FERC issued an order to commence a fact-finding hearing to determine amounts to be refunded for sales during the period from October 2, 2000 to June 20, 2001 in the California spot market operated by the CalISO and the CalPX. The order provides that any refunds owed could be offset against unpaid energy debts due to the same party. The FERC schedule for this proceeding has been postponed repeatedly and is not expected to be continued until August 2002 or later. Avista Energy is participating in this proceeding pursuant to the FERC order and cannot predict its outcome at this time.

The July 2001 FERC order also directed a separate evidentiary proceeding to explore wholesale power market issues in the Pacific Northwest. The FERC’s Pacific Northwest proceeding seeks to determine whether there were excessive charges for spot market sales in the Pacific Northwest in the period December 25, 2000 to June 20, 2001, and whether there is sufficient factual basis for the FERC to take further action. Based on their application of selected retroactive pricing methods, certain parties have asserted claims for significant refunds from Avista Energy and lesser refunds from Avista Utilities. Avista Energy and Avista Utilities joined with numerous other wholesale market participants to vigorously oppose proposals for retroactive price caps and refund claims. In September 2001, the FERC’s administrative law judge for this proceeding issued a recommendation that the FERC should not order refunds for the Pacific Northwest for the period in question and that the FERC should take no further action on these matters. The FERC has not yet issued a decision in the Pacific Northwest refund proceeding.

In September 2001, PG&E filed a plan of reorganization that provides for payment to all creditors on or around January 1, 2003. The PG&E plan requires various approvals, including procedural and content matters, by the Federal Bankruptcy Court, Securities and Exchange Commission, Nuclear Regulatory Commission, and the FERC. Various parties, including consumer groups and the CPUC, have announced opposition to the plan of reorganization. The CPUC filed a term sheet in February 2002 outlining an alternative plan of reorganization. On February 27, 2002, the Federal Bankruptcy Court ruled that the CPUC would be permitted to file its full plan, which it must do by April 15, 2002. The CPUC term sheet estimates that creditors would be paid in or around January 2003.

In October 2001, SCE and the CPUC announced a settlement of SCE’s filed rate doctrine lawsuit. By entering into a settlement agreement and obtaining additional financing, SCE made substantially full payment on its past due obligations on March 1, 2002. The defaulted payments due to Avista Energy remain entangled with the CalPX, which was the intermediary between many energy sellers and SCE as energy purchaser.

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As of December 31, 2001, Avista Energy’s accounts receivable related to defaulting parties in California — net of reserves for uncollected amounts, cost of collection, and refunds — were approximately $6.5 million. Avista Energy is currently pursuing recovery for the defaulted obligations.

Energy Trading and Marketing Line of Business

The Energy Trading and Marketing line of business includes Avista Energy and Avista Power, both wholly owned subsidiaries of Avista Capital.

Avista Energy

Avista Energy is an electricity and natural gas trading and marketing business focused on marketing energy in the western United States. In 1997, Avista Energy began conducting business on a national basis and expanded operations with its acquisition of Vitol Gas & Electric, LLC in 1999. However, in November 1999, the Company decided to reduce Avista Energy’s size and risk by redirecting its focus away from national energy trading and marketing toward a more regionally-based energy trading and marketing effort in the western United States. Avista Energy’s trading and marketing efforts are backed by contracts for energy commodities and by the output of specific facilities available under contract. Avista Energy’s headquarters are in Spokane, Washington, and it also has an office in Vancouver, British Columbia, Canada.

Avista Energy is in the business of buying and selling electricity and natural gas. Avista Energy’s customers include commercial and industrial end-users, electric utilities, natural gas distribution companies and other trading companies. Avista Energy also trades electricity and natural gas derivative commodity instruments, including futures, options, swaps and other contractual arrangements. Most transactions are conducted on a largely unregulated “over-the-counter” basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges). During 1999, Avista Energy also sold and traded coal and SO2 allowances, but eliminated these activities in 2000 as contracts expired. The following table provides operating statistics for Avista Energy for the years ended December 31:

                             
        2001   2000   1999
       
 
 
Revenues (dollars in thousands):
                       
 
Electric
  $ 3,380,058     $ 4,721,291     $ 4,745,615  
 
Natural Gas
    1,619,285       1,751,264       1,900,487  
 
Coal and other
    1,612       58,996       49,569  
 
   
     
     
 
   
Total revenues
  $ 5,000,955     $ 6,531,551     $ 6,695,671  
 
   
     
     
 
Sales Volumes:
                       
 
Electricity (thousands of MWhs)
    47,927       105,548       135,099  
 
Natural gas (thousands of dekatherms)
    248,193       273,448       775,822  
 
Coal (thousands of tons)
          3,514       1,638  

Although Avista Energy scaled back operations to focus primarily in the western United States during 2000, its trading operations continue to be affected by, among other things, volatility of prices within the electric energy and natural gas markets, the demand for and availability of energy, lower unit margins on new sales contracts, FERC- ordered price caps, financial condition of counterparties and deregulation of the electric utility industry.

In April 1997, Avista Energy entered into a marketing agreement with Chelan County Public Utility District (PUD), located in Washington State. The agreement allows Avista Energy to market, on a “real-time” basis, a portion of the output from Chelan County PUD’s hydroelectric resources (557 MWhs) and to jointly market energy products and services to other utilities in the region.

Effective September 1, 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. A benchmark incentive 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. Approvals for continuation of the agreement and the benchmark incentive mechanism were received from the state regulatory agencies in Washington and Idaho in

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early 2002. The current benchmark incentive mechanism and related Agency Agreement expires in March 2003 in Washington and March 2005 in Idaho. The OPUC is expected to issue its ruling in late March 2002.

Avista Energy is subject to the various risks inherent in commodity trading including, particularly, market risk, liquidity risk, commodity risk and credit risk. See “Western Power Market Issues”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Future Outlook,” and “Notes 1, 5 and 7 of Notes to Consolidated Financial Statements” for additional information regarding the market and credit risks inherent in the energy trading business, fourth quarter 1999 restructuring costs, Avista Energy’s risk management policies and procedures, accounting practices, and positions held by Avista Energy as of December 31, 2001.

Avista Capital provides guarantees for Avista Energy’s line of credit agreement and, in the course of business, may provide guarantees to other parties with whom Avista Energy may be doing business. Avista Capital had $91.6 million of such guarantees outstanding as of December 31, 2001.

Avista Power

Avista Power was formed to develop and own generation assets. During 2001, the Company decided that Avista Power would no longer pursue the development of additional non-regulated generation projects due to changing market conditions and as part of Avista Corp.’s overall business strategy. Avista Power continues to manage the generation assets it currently owns.

Avista Power is a 49 percent owner of a 270 MW natural gas-fired combustion turbine plant in Rathdrum, Idaho, which commenced commercial operation in September 2001. The output from this plant is contracted to Avista Energy for 25 years. Avista Power is also in the process of constructing the Coyote Springs 2 power plant and completed the sale of 50 percent of its interest in the plant to Mirant in December 2001. Upon the planned completion of the plant in the third quarter of 2002, Avista Power’s 50 percent ownership interest will be transferred to Avista Corp. to be operated as an asset of Avista Utilities.

Information and Technology Line of Business

The Information and Technology line of business includes Avista Advantage and Avista Labs. Avista Advantage and Avista Labs are majority-owned and wholly owned subsidiaries of Avista Capital, respectively.

Avista Advantage

Avista Advantage is a provider of internet-based facility intelligence and cost management billing and information services to 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, 2001, Avista Advantage serviced 203 customers, having 79,749 billed sites throughout North America. This is an increase from 135 customers and 46,127 billed sites as of December 31, 2000. As of December 31, 1999, Avista Advantage serviced 75 customers and 21,186 billed sites. During 2001, Avista Advantage processed $4.3 billion of bills, an increase from $1.1 billion in 2000 and $0.2 billion in 1999.

Two venture capital firms invested a total of $3.4 million in Avista Advantage during the fourth quarter of 2000.

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Avista Labs

Avista Labs developed a unique modular PEM fuel cell that delivers reliable, affordable and clean distributed power solutions. The modular design allows fuel cell cartridges to be easily removed and replaced without interrupting power. The company believes this exclusive “hot swap” feature makes Avista Labs’ technology more scalable, configurable, reliable and durable than other fuel cell technologies. In addition to its PEM fuel cell, Avista Labs seeks to commercialize selected components to complement its fuel cell in order to deliver system solutions to industrial, commercial and residential markets.

Avista Labs was granted three patents, with more than 260 issued claims recognizing and protecting the unique attributes of its fuel cell system. Avista Labs received notice of allowance of two additional patents, including a patent with 301 claims protecting its modular approach to the design of fuel cell systems. Avista Labs has 21 more patent applications pending or in process directed to its unique approach in fuel cells, power conversion and other components.

Key alliances in bringing Avista Labs’ product to market include a joint marketing agreement with Black & Veatch, a leading engineering, procurement and construction company, and an agreement with Logan Industries, Inc., which has been assembling Avista Labs fuel cell units for field testing and sales since early in 1999. In June 2001, Avista Labs entered into an agreement with Maxwell Technologies to provide PowerCache ultracapacitors to optimize performance and reduce the cost of its unique, modular fuel cells systems and components. Avista Labs and Maxwell Technologies entered a multi-year agreement and are exploring areas of mutual interest for a broader strategic relationship.

In January 2001, Avista Labs formed a new company, H2fuel, LLC, to develop and commercialize technology for manufacturing hydrogen for fuel cells and other hydrogen applications. Avista Labs owns a 70 percent interest in H2fuel. The remaining interest is owned by Unitel Fuels Technologies, LLC. Avista Labs transferred its ongoing fuel processor development work to H2fuel. H2fuel has two patent applications pending directed to the use of certain catalysts for autothermal reforming.

During 2001, Avista Labs also introduced a hydrogen sensor product for fuel cell developers and other hydrogen users. This hydrogen sensor can be a component of any fuel cell system and is currently commercially available. It is the first hydrogen sensor to receive Underwriters Laboratories, Inc., recognition under UL standard 2075.

During 2001, Avista Labs achieved a key milestone by initiating commercial sales of its hydrogen-only fuel cell systems for various applications, primarily back-up power for the commercial market. Avista Labs completed commercial transactions for the sale or lease of 50 units during 2001. As of December 31, 2001, 76 fuel cell units were installed in 21 locations in North and South America. As of December 31, 2000, 29 fuel cell units were installed.

Other Line of Business

The Other line of business includes several minor subsidiaries, including Avista Ventures, Pentzer Corporation (Pentzer), Avista Development and Avista Services. The operations of Avista Capital that are not included through its subsidiaries are included in this line of business. Prior to 1999, Pentzer was the parent company to the majority of Avista Corp.’s other subsidiary business, controlling interests in a broad range of middle market companies. Beginning in 2000, the focus of this line of business was changed to invest in business opportunities that have potential value to the Company’s energy-related businesses. Currently, activities in this line of business are not significant and the Company intends to limit its future investment in this line of business.

Discontinued Operations — 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, the Company made a decision to discontinue the operations of Avista Communications, previously included in the Information and Technology line of business. As such, Avista Communications is reported as a discontinued operation. The divestiture of Avista Communications is expected to be completed during the first half 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  
   
Northeast (Spokane) CT
    2       61.8       66.8  
 
Idaho:
                       
   
Rathdrum CT (1)
    2       166.5       176.0  
 
Montana:
                       
   
Colstrip (Units 3 and 4) (4)
    2       233.4       222.0  
 
           
     
 
     
Total Thermal
            512.4       514.8  
 
Total Generation Properties
            1,391.7       1,479.5  
 
           
     
 

(1)   All generation properties are owned by the Company with the exception of the Rathdrum CT, which is leased.
(2)   Nameplate Rating, also referred to as “installed capacity”, is the manufacturer’s assigned power rating under specified conditions.
(3)   Capability is the maximum generation of the plant without exceeding approved limits of temperature, stress and environmental conditions.
(4)   Jointly owned; data above refers to Avista Utilities’ 15 percent interest.

Electric Distribution and Transmission Plant

Avista Utilities operates approximately 12,200 miles of primary and secondary electric distribution lines and an electric transmission system of approximately 595 miles of 230 kV line and 1,520 miles of 115 kV line. Avista Utilities also owns a 10 percent interest in 495 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana.

The 230 kV lines are used to transmit power from Avista Utilities’ Noxon Rapids and Cabinet Gorge hydroelectric generating stations to major load centers in its service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect with BPA at five locations and at one location each with PacifiCorp, Montana Power 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 outside the Pacific Northwest. The interconnection with PacifiCorp is used to integrate Mid-Columbia

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hydroelectric generating facilities to Avista Utilities’ loads, as well as for the interchange of power with entities within 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 Montana Power.

Natural Gas Plant

Avista Utilities has natural gas distribution mains of approximately 2,542 miles in Washington, 1,436 miles in Idaho and 1,895 miles in Oregon and California combined, as of December 31, 2001.

Avista Utilities, Northwest Pipeline and Puget Sound Energy each own a one-third undivided interest in the Jackson Prairie Storage Project, which has a total peak day deliverability of 8.8 million therms, with a total working natural gas inventory of 190.3 million therms.

Item 3. Legal Proceedings

See “Note 24 of Notes to Consolidated Financial Statements” for additional information.

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

None.

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 February 28, 2002, there were approximately 18,120 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 continuing basis, taking into account numerous factors including, without limitation, the Company’s results of operations and financial condition, as well as general economic and competitive conditions. The Company’s net income available for dividends is derived primarily from Avista Utilities’ operations.

For additional information, refer to “Notes 1, 20 and 23 of Notes to Consolidated Financial Statements.” For high and low stock price information, refer to “Note 26 of Notes to Consolidated Financial Statements.”

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Item 6. Selected Financial Data

                                           
      Years Ended December 31,
     
      2001   2000   1999   1998   1997
     
 
 
 
 
      (In thousands, except per share data and ratios)
Operating Revenues:
                                       
 
Avista Utilities
  $ 1,230,847     $ 1,512,101     $ 1,115,647     $ 1,049,212     $ 891,665  
 
Energy Trading and Marketing
    5,000,955       6,531,551       6,695,671       2,408,734       247,028  
 
Information and Technology
    13,815       5,732       2,266       1,318       792  
 
Other
    16,385       32,937       122,303       231,483       163,598  
 
Intersegment eliminations
    (252,155 )     (176,744 )     (33,488 )     (7,440 )     (1,149 )
 
   
     
     
     
     
 
 
Total
  $ 6,009,847     $ 7,905,577     $ 7,902,399     $ 3,683,307     $ 1,301,934  
Income (Loss) from Operations (pre-tax):
                                       
 
Avista Utilities
  $ 114,927     $ 3,177     $ 142,567     $ 143,153     $ 178,289  
 
Energy Trading and Marketing
    94,669       250,196       (97,785 )     22,826       6,577  
 
Information and Technology
    (29,872 )     (26,424 )     (8,966 )     (4,979 )     (5,391 )
 
Other
    (10,432 )     (9,861 )     (423 )     12,033       9,962  
 
   
     
     
     
     
 
 
Total
  $ 169,292     $ 217,088     $ 35,393     $ 173,033     $ 189,437  
Income (Loss) from Continuing Operations:
                                       
 
Avista Utilities
  $ 24,164     $ (38,781 )   $ 59,573     $ 56,297     $ 100,777  
 
Energy Trading and Marketing
    70,087       161,753       (60,739 )     14,116       5,346  
 
Information and Technology
    (19,384 )     (19,032 )     (5,989 )     (3,221 )     (3,455 )
 
Other
    (15,262 )     (2,885 )     35,817       11,124       12,099  
 
   
     
     
     
     
 
 
Total
  $ 59,605     $ 101,055     $ 28,662     $ 78,316     $ 114,767  
Income (Loss) from Discontinued Operations
  $ (47,449 )   $ (9,376 )   $ (2,631 )   $ (177 )   $ 30  
Net Income
  $ 12,156     $ 91,679     $ 26,031     $ 78,139     $ 114,797  
Preferred Stock Dividend Requirements
  $ 2,432     $ 23,735     $ 21,392     $ 8,399     $ 5,392  
Income Available for Common Stock
  $ 9,724     $ 67,944     $ 4,639     $ 69,740     $ 109,405  
Average Common Shares Outstanding, Basic
    47,417       45,690       38,213       54,604       55,960  
Average Common Shares Outstanding, Diluted
    47,435       46,103       38,325       54,658       55,960  
Common Shares Outstanding at Year-End
    47,633       47,209       35,648       40,454       55,960  
Earnings per Common Share:
                                       
 
Avista Utilities
  $ 0.46     $ (1.37 )   $ 1.00     $ 0.88     $ 1.70  
 
Energy Trading and Marketing
    1.47       3.51       (1.59 )     0.26       0.10  
 
Information and Technology
    (0.41 )     (0.41 )     (0.16 )     (0.06 )     (0.06 )
 
Other
    (0.32 )     (0.06 )     0.94       0.20       0.22  
 
   
     
     
     
     
 
 
Total Earnings per Common Share from Continuing Operations, Diluted
  $ 1.20     $ 1.67     $ 0.19     $ 1.28     $ 1.96  
 
Loss per Common Share from Discontinued Operations, Diluted
  $ (1.00 )   $ (0.20 )   $ (0.07 )   $     $  
 
Total Earnings per Common Share, Diluted
  $ 0.20     $ 1.47     $ 0.12     $ 1.28     $ 1.96  
 
Total Earnings per Common Share, Basic
  $ 0.21     $ 1.49     $ 0.12     $ 1.28     $ 1.96  
 
Dividends Paid per Common Share
  $ 0.48     $ 0.48     $ 0.48     $ 1.05     $ 1.24  
 
Book Value per Common Share at Year-End
  $ 15.12     $ 15.34     $ 11.04     $ 12.07     $ 13.38  
Total Assets at Year-End:
                                       
 
Avista Utilities
  $ 2,396,317     $ 2,143,791     $ 1,976,716     $ 2,004,935     $ 1,926,739  
 
Energy Trading and Marketing
    1,506,185       10,271,834       1,595,470       955,615       212,868  
 
Information and Technology
    26,891       14,429       6,312       2,492       2,221  
 
Other
    86,514       96,362       114,929       285,625       268,703  
 
Discontinued Operations
    21,316       50,665       20,067       4,969       1,254  
 
   
     
     
     
     
 
 
Total
  $ 4,037,223     $ 12,577,081     $ 3,713,494     $ 3,253,636     $ 2,411,785  
Long-Term Debt at Year-End
  $ 1,175,715     $ 679,806     $ 714,904     $ 730,022     $ 762,185  
Company-Obligated Mandatorily Redeemable Preferred Trust Securities
  $ 100,000     $ 100,000     $ 110,000     $ 110,000     $ 110,000  
Preferred Stock Subject to Mandatory Redemption
  $ 35,000     $ 35,000     $ 35,000     $ 35,000     $ 45,000  
Convertible Preferred Stock
  $     $     $ 263,309     $ 269,227     $  
Common Equity
  $ 720,063     $ 724,224     $ 393,499     $ 488,034     $ 748,812  
Ratio of Earnings to Fixed Charges
    1.84       3.45       1.66       2.66       3.49  
Ratio of Earnings to Fixed Charges and Preferred Dividend Requirements
    1.78       2.19       1.11       2.26       3.12  

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

The following discussion and analysis is provided for the consolidated financial condition and results of operations of Avista Corporation (Avista Corp. or the Company) which includes 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. Lines of Business

Avista Corp. is an energy company involved in the generation, transmission and distribution of energy as well as other energy-related businesses. The Company is currently organized into four lines of business — Avista Utilities, Energy Trading and Marketing, Information and Technology, and Other. Avista Utilities, an operating division of Avista Corp. and not a separate entity, represents the regulated utility operations. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies engaged in the other non-regulated lines of business. As of December 31, 2001, the Company had common equity investments of $368.7 million and $351.4 million in Avista Utilities and Avista Capital, respectively.

Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Utilities owns and operates eight hydroelectric projects, a wood-waste fueled generating station and a two-unit natural gas-fired combustion turbine (CT) generating facility. 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. These facilities have a total net capability of approximately 1,480 megawatts, of which 65 percent is hydroelectric and 35 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 sells and purchases electric capacity and energy to and from utilities and other entities in the wholesale market under long-term contracts having terms of more than one year. In addition, Avista Utilities engages in an ongoing process of resource optimization which involves short-term purchases and sales in the wholesale market in pursuit of an economic selection of resources to serve retail and wholesale loads. 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 a quarterly, monthly, daily and hourly basis to match actual resources to actual energy requirements and to sell any surplus at the best available price. This process includes hedging transactions.

During a year having normal water conditions, Avista Utilities would expect to have generation from its hydroelectric resources (both owned and purchased under long-term hydroelectric contracts) of approximately 550 average megawatts (aMW). In a “critical water” year (defined by the Northwest Power Pool as the worst water conditions on record), Avista Utilities would expect hydroelectric production of 400 aMW, 150 aMW below normal. Average hydroelectric production for the year 2001 was 369 aMW (67 percent of normal), which is 181 aMW below normal and the lowest level in the 73 years in which records have been kept. Preliminary forecasts indicate streamflow conditions are expected to be 87 percent of normal in 2002 based on current snow pack conditions. Avista Utilities currently estimates that hydroelectric generation will be 534 aMW (97 percent of normal) in 2002.

Developments in wholesale energy markets, compounded by the record low availability of hydroelectric resources in 2001, have had an adverse effect on Avista Corp.’s financial condition, results of operations, cash flows and liquidity. See “Avista Utilities — Regulatory Matters”, “Results of Operations” and “Liquidity and Capital Resources.”

The Energy Trading and Marketing line of business is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy is an electricity and natural gas marketing and trading business, operating primarily in the Western Systems Coordinating Council (WSCC), which is comprised of the eleven Western states. Avista Power was originally formed to develop and own generation assets. During 2001, the Company decided that Avista Power would no longer pursue the development of additional non-regulated generation projects.

The Information and Technology line of business is comprised of Avista Advantage, Inc. (Avista Advantage) and Avista Laboratories, Inc. (Avista Labs). Avista Advantage is a provider of internet-based facility intelligence, cost management billing and information services to retail customers throughout North America. Its primary product

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lines include consolidated billing, resource accounting, energy analysis, load profiling and maintenance and repair billing services. Avista Labs developed a unique modular Proton Exchange Membrane (PEM) fuel cell that delivers reliable, affordable and clean distributed power solutions. In addition to its PEM fuel cell, Avista Labs seeks to commercialize selected components to complement its fuel cell in order to deliver system solutions to industrial, commercial and residential markets.

The Other line of business includes Avista Ventures, Inc. (Avista Ventures), Avista Capital (parent company only amounts), Pentzer Corporation (Pentzer) and several other minor subsidiaries. During 2000, the focus of this line of business was changed from investing in a broad range of middle market companies to investing in business opportunities that have potential value to the Company’s energy-related businesses. Currently, activities in this line of business are not significant and the Company intends to limit its future investment in this line of business.

Avista Communications, Inc. (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. As such, these operations are reported as a discontinued operation. Avista Corp. began its divestiture of this business during the fourth quarter of 2001, and the divestiture is expected to be completed during the first half of 2002.

Avista Utilities — Regulatory Matters

Beginning in the second quarter of 2000, the price of power in the wholesale markets of the western United States increased considerably and became much more volatile. While prices and volatility decreased during the second half of 2001, the effects of contracts entered during the period of high wholesale prices continue to have a significant impact on Avista Corp.’s financial condition and results of operations. In the second half of 2000 and continuing through 2001, Avista Utilities was required to purchase above-normal amounts of power in the wholesale market to meet its retail demand. This was primarily due to the reduced availability of hydroelectric resources as a result of low streamflow conditions. The combination of high wholesale market prices and increased amounts required to be purchased increased power supply costs to amounts far in excess of the amounts recovered from retail customers under current rates.

Under current orders and approvals from the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC), Avista Utilities is permitted to defer the recognition in the income statement of 90 percent of power supply costs that are in excess of the level currently recovered from retail customers. Deferred 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 specific power costs deferred include the changes in power costs to Avista Utilities from the costs included in base retail rates, related to changes in short-term wholesale market prices, changes in the level of hydroelectric generation and changes in the level of thermal generation (including changes in fuel prices). The power costs deferred relate solely to the operation of Avista Utilities’ system resources to serve its retail and wholesale load obligations.

In December 2001, the Company filed a general rate case with the WUTC to address, among other things, the recovery of cash outlays for increased power supply costs and expenses related to building additional generation. The WUTC may take up to 11 months to review the general rate case filing. Avista Corp. requested an interim rate increase of 10 percent (or $29.3 million in annual revenues) above current rates (including the 25 percent temporary surcharge approved by the WUTC in September 2001). At the conclusion of the general rate case, Avista Corp. requested that a number of adjustments be made that would result in no net change to rates above the interim rate increase. The interim rate increase would end, base electric rates would increase by 22.5 percent (or $53.2 million in annual revenues) and the electric surcharge would be reduced from 25 percent to 14.9 percent. These rate increases are necessary in order to continue the recovery of deferred power costs. The proposed rate increases also reflect, among other things, the recovery of costs associated with the addition of the Company’s 50 percent ownership in the Coyote Springs 2 power plant and the addition of several small generation projects built to serve retail customer needs. The general rate case proposed by Avista Corp. requests a 12.75 percent rate of return on common equity and a 10.39 percent overall rate of return.

In the December 2001 general rate case filing, Avista Corp. requested the implementation of a temporary accounting mechanism for the deferral of power costs incurred in excess of the amount recovered through rates effective January 1, 2002 until the conclusion of the general rate case. The WUTC approved this request in December 2001. In the general rate case, Avista Corp. requested the establishment of a permanent power cost adjustment (PCA) mechanism to increase or decrease future electric rates based on actual power supply costs, similar to the existing Idaho PCA

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mechanism. This provides for the deferral of 90 percent of the difference between actual net power supply costs and the amount of power supply costs authorized in current rates.

In March 2002, the WUTC issued an order approving a settlement agreement reached among Avista Corp., the staff of the WUTC and other parties. This order approves the prudence and recoverability of 90 percent (or $196 million) of deferred power supply costs incurred by the Company during the period from July 1, 2000 through December 31, 2001. This resulted in the Company recording as an expense an additional $21.8 million in power supply costs for the year ended December 31, 2001.

Additionally, the WUTC order provides that the collection of the 25 percent temporary electric surcharge, approved by the WUTC in September 2001, will no longer be subject to refund. The order also modified the temporary electric surcharge such that one-fifth (or approximately $12 million in annual revenues) of the existing 25 percent surcharge will be applied to offset the Company’s general operating costs and the remainder (approximately $47 million in annual revenues) will continue to be applied as a recovery of deferred power costs. The WUTC also ordered a 6.2 percent (or $14.7 million in annual revenues) increase in base electric rates for Washington customers. Both the 6.2 percent increase in base electric rates and one-fifth of the temporary surcharge will increase net income.

As of December 31, 2001, total deferred power costs were $213.3 million, including $140.2 million in Washington and $73.1 million in Idaho. Based on current projections, total deferred power costs balances are expected to be approximately $150 million at the end of 2002 and fully recovered by 2007. The following table shows activity in deferred power costs for Washington and Idaho during 2001 (dollars in thousands):

                           
      Washington   Idaho   Total
     
 
 
Deferred power costs as of December 31, 2000
  $ 34,580     $ 2,693     $ 37,273  
Activity from January 1 - September 30, 2001:
                       
 
Power costs deferred
    155,241       67,086       222,327  
 
Interest and other net additions
    9,838       3,606       13,444  
 
Recovery of deferred power costs
          (1,866 )     (1,866 )
 
   
     
     
 
Deferred power costs as of September 30, 2001
    199,659       71,519       271,178  
Activity from October 1 - December 31, 2001:
                       
 
Power costs deferred
    11,955       6,591       18,546  
 
Mark-to-market loss
    8,232       4,077       12,309  
 
Interest and other net additions
    6,189       2,037       8,226  
 
Amortization of deferred credit
    (53,794 )     (6,927 )     (60,721 )
 
Recovery of deferred power costs
    (10,223 )     (4,210 )     (14,433 )
 
Write-off deferred power costs
    (21,780 )           (21,780 )
 
   
     
     
 
Deferred power costs as of December 31, 2001
  $ 140,238     $ 73,087     $ 213,325  
 
   
     
     
 

The following discussion details significant developments during the second half of 2000 and the year 2001 leading to the March 2002 WUTC orders and the December 2001 general electric rate case filing.

In August 2000, the WUTC approved Avista Utilities’ request for deferred accounting treatment for certain power costs related to, among other things, increases in short-term wholesale electric prices beginning July 1, 2000 through June 30, 2001. In January 2001, the WUTC approved a modification to the deferral mechanism to recover power supply costs associated with meeting increased retail and wholesale system load requirements, effective December 1, 2000. The approval of the modification was conditioned on Avista Utilities filing by March 2001 a proposal addressing the prudence of the incurred power costs, the optimization of Company-owned resources to the benefit of retail customers and the appropriateness of recovery of power costs through a deferral mechanism. This proposal was also to address cost of capital offsets to recognize the shift in risk from shareholders to ratepayers and Avista Utilities’ plan to mitigate the deferred power costs.

In May 2001, the WUTC approved a settlement agreement reached among Avista Corp., the staff of the WUTC and other parties with respect to deferred power costs. The agreement, among other things, provided for the extension of Avista Corp.’s deferral accounting mechanism through February 2003. Due to the planned addition of generating resources as well as the expiration of certain long-term power sale agreements, Avista Utilities, at the time of the settlement agreement, expected to be in a power surplus position by the middle of 2002. The agreement was based, in part, on the expectation that Avista Utilities’ profits from surplus power sales would offset the deferred power cost balance, reducing the balance to zero by the end of February 2003 without any rate increase to retail customers. These expectations were based on assumptions as to a number of variables including, but not limited to, streamflow conditions, thermal plant performance, level of retail loads, wholesale market prices and the amount of additional generating resources. Avista Utilities reserved the right to alter, amend, or terminate the settlement agreement as

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well as the right to seek interim rate relief. As discussed below, subsequent events and conditions changed Avista Utilities’ original expectations and plans.

In response to the dramatically reduced generation from hydroelectric facilities commencing in the second quarter of 2001, Avista Utilities was required to make additional fixed price purchases of energy to meet its retail and wholesale electric requirements for 2001 on the higher cost short-term wholesale market.

In June 2001, the Federal Energy Regulatory Commission (FERC) issued an order adopting a price mitigation plan applicable to certain wholesale power sales in California and throughout the western United States during the period June 20, 2001 through September 30, 2002. The order applies to pre-schedule (day-ahead) and real-time (hour-ahead) transactions in the western United States. Wholesale market prices in the western United States decreased considerably after the price caps were imposed and prices remained well below the price cap levels through the end of 2001. The decrease in wholesale market prices affected Avista Utilities’ plan for recovery of deferred power costs through future surplus power sales.

During June and the first part of July 2001, Avista Utilities evaluated the effect of the recent decline in wholesale market prices and the FERC price mitigation plan on its ability to recover deferred power cost balances under the settlement agreement approved by the WUTC in May 2001 and the continuing PCA mechanism for Idaho customers approved by the IPUC. The decline in forward wholesale prices and the FERC price mitigation plan reduced the expected value from future surplus sales of energy. In addition, low hydroelectric availability combined with the high cost of energy and capacity under forward contracts entered to meet customer demand for 2001 increased current and estimated future deferred power costs to levels significantly higher than originally anticipated. As such, Avista Utilities determined that the plan for recovery of deferred power cost balances, as contemplated in the May 23, 2001 settlement agreement with the WUTC and the existing PCA with the IPUC, was not feasible.

Accordingly, in July 2001 Avista Utilities filed requests with the WUTC and IPUC for the approval of an electric energy surcharge of 36.9 percent in Washington and a PCA surcharge of 14.7 percent in Idaho for a 27-month period beginning in September 2001.

In September 2001, the WUTC ordered a 25 percent temporary electric rate surcharge for the 15-month period from October 1, 2001 to December 31, 2002 applied uniformly to energy charges across all Washington electric customer classes. The March 2002 WUTC order amended the surcharge such that one-fifth will be applied to offset the Company’s general operating costs and the remainder will continue to be applied as a recovery of deferred power costs. It was originally estimated the order would allow Avista Utilities to reduce the deferred power cost balance by $125 million. This included the receipt of $71 million in additional revenue from the surcharge ($10.2 million was received during 2001) and the accelerated amortization of $54 million of a deferred non-cash credit on the Company’s balance sheet in October 2001. The deferred non-cash credit related to funds received in December 1998 for the monetization of a contract in which the Company assigned and transferred certain rights under a long-term power sales contract with Portland General Electric (PGE) to a funding trust. The deferred non-cash credit balance was originally to be amortized into revenues over the 16-year period of the long-term sales contract. There is no direct impact on net income from either the surcharge or accelerated amortization of the deferred non-cash credit; however, the surcharge revenue increases cash flows.

As part of the surcharge order, the WUTC ordered Avista Utilities to file a general rate case by December 2001 as discussed above. The order by the WUTC also provided for the termination of the accounting mechanism for the deferral of power costs effective December 31, 2001. The WUTC subsequently approved the continuation of the accounting mechanism for deferred power costs for the period from January 1, 2002 through the conclusion of the general rate case. As requested by Avista Utilities, the deferred power cost accounting mechanism was modified to reflect the deferral of 90 percent of the difference between actual power supply costs and the amount of power supply costs allowed to be recovered in current retail rates.

In October 2001, the IPUC issued an order approving a 14.7 percent PCA surcharge for Idaho electric customers and granted an extension of a 4.7 percent PCA surcharge implemented earlier in 2001 that was to expire January 2002. Both PCA surcharges will remain in effect until October 2002. The IPUC directed Avista Utilities to file a status report 60 days before the PCA surcharge expires. If review of the status report and the actual balance of deferred power costs support continuation of the PCA surcharge, the IPUC has indicated that it anticipates the PCA surcharge will be extended for an additional period. It is currently estimated the IPUC order will allow Avista Utilities to reduce the deferred power cost balance by approximately $58.2 million. This includes the receipt of $23.6 million in additional revenue from the PCA surcharges ($4.2 million was received during the fourth quarter of 2001) and the accelerated amortization of $34.6 million of a deferred non-cash credit on the Company’s balance sheet for the

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monetization of the power sales contract with PGE ($6.9 million was amortized in 2001). There is no direct impact on net income from either the PCA surcharges or accelerated amortization of the deferred non-cash credit; however, the PCA surcharges increase cash flows.

In November 2001, Avista Utilities filed a request with the WUTC for an expedited procedural schedule to address the prudence and recoverability of deferred power costs incurred as of September 30, 2001. The Company made this request due to the fact that uncertainty involving the recovery of deferred power costs would present financing challenges for the Company during the first half of 2002. The Company’s $220 million committed line of credit as well as a $90 million accounts receivable financing facility expire in May 2002. The Company may also decide to issue equity securities during 2002. In March 2002, the WUTC approved the prudence and recoverability of 90 percent of deferred power costs incurred as of December 31, 2001 as discussed above.

Enron Exposure

On December 2, 2001, Enron Corporation (Enron) and certain of its affiliates filed for protection under chapter 11 of the United States Bankruptcy Code. The bankruptcy filing constituted an event of default under contracts between Avista Corp. and Avista Energy, respectively, and certain Enron affiliates, Enron Power Marketing, Inc. (EPMI), Enron North America Company (ENA) and Enron Canada Corp. (ECC), that are guaranteed by Enron. As a result, Avista Corp. and Avista Energy terminated all but one of these contracts and suspended trading activities with most Enron affiliates; short-term, balance of the month deals with EPMI are still being transacted through Avista Energy on a prepaid basis.

Both Avista Corp. and Avista Energy engage in physical and financial transactions for the purchase and sale of electric energy and capacity and natural gas. Both companies had done considerable business and had short-term and long-term contracts with Enron affiliates. Avista Corp. has one three-year purchase with remaining deliveries scheduled from 2004 to 2006 with EPMI. Avista Energy’s long-term contracts with Enron affiliates were terminated entirely.

As of December 31, 2001, Avista Corp. and Avista Energy had net accounts receivable of $3.1 million and $14.1 million, respectively, from Enron affiliates. The contracts of Avista Corp. and Avista Energy with each Enron affiliate provide that, upon termination, the net settlement of accounts receivable and accounts payable with such entity will be netted against the net mark-to-market value of the terminated forward contracts with such entity. It is estimated that, for each of Avista Corp. and Avista Energy, netting the mark-to-market liability against the defaulted net accounts receivable will result in no significant loss due to non-collection from the Enron affiliates. It is further estimated that the net mark-to-market liability to Enron affiliates in respect of terminated forward contracts of Avista Corp. and Avista Energy, taken together, exceeds total net accounts receivable from these entities by less than $30 million. Any claims by the Enron entities for amounts that Avista Corp. and Avista Energy might owe in respect of the terminated forward contracts would be subject to any defenses and counterclaims which Avista Corp. and Avista Energy may have. Any residual obligation by Avista Corp. or Avista Energy for termination payments is not expected to have a material impact on the Company’s financial condition or results of operations.

The estimates of the mark-to-market values of terminated forward contracts are based on available broker quotes, for the respective periods, and on assumptions as to future market prices and other information. While Avista Corp. and Avista Energy believe these assumptions are reasonable, they are subject to change and ultimately could be challenged by the Enron entities or their bankruptcy trustees. The mark-to-market value of terminated contracts has not been firmly established and could result in undercollection that is not expected to be material to the financial condition or results of operations of either Avista Corp. or Avista Energy.

National Energy Production Corporation (NEPCO), a wholly owned subsidiary of Enron, is the contractor responsible for the engineering, procurement and construction of the Coyote Springs 2 project. Avista Corp. owns 50 percent of the Coyote Springs 2 project, which is expected to commence commercial operation in the third quarter of 2002. NEPCO was not included in the bankruptcy filings made by Enron and its affiliates. However, Enron guaranteed NEPCO’s obligations, and the bankruptcy filing by Enron was an event of default under the Coyote Springs 2 construction contract. NEPCO and Coyote Springs 2, LLC, an entity formed for the purpose of constructing the Coyote Spring 2 plant, amended the construction contract to, among other things, authorize Coyote Springs 2, LLC to make immediate draws under a letter of credit posted to secure NEPCO’s performance and to permit Coyote Springs 2, LLC to pay third-party subcontractors of NEPCO directly. Coyote Springs 2, LLC is continuing to assess the ability of NEPCO to perform its obligations under the construction contract and may need to exercise additional remedies in the event the impact of the Enron bankruptcy prevents NEPCO from performing its obligations under the construction contract.

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Avista Corp. is party to a power exchange arrangement which expires in 2016. Under this power exchange arrangement, EPMI 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 monetizing the long-term capacity contract between PGE and Avista Corp. Spokane Energy sells the related capacity to PGE, a subsidiary of Enron that has not been included in the bankruptcy filing to date and is in the process of being sold to another company. This power exchange arrangement was originally established for the purpose of monetizing a $145 million long-term capacity contract between Avista Corp. and PGE. EPMI assisted in setting up the monetization structure and acts as an intermediary to abide by certain regulatory restrictions that currently prevent 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 monetization loan (balance of $131.1 million as of December 31, 2001) that matures in January 2015 with no recourse to Avista Corp. related to the loan. EPMI is obligated to pay approximately $150,000 per month to Avista Corp. for its capacity purchase and servicing functions related to this power exchange arrangement. EPMI defaulted on two payments to Avista Corp. prior to filing for bankruptcy. As a result, in December 2001, Avista Corp. and EPMI entered an agreement that allows Avista Corp. to continue receiving the monthly payments from EPMI while Avista Corp. evaluates alternatives with respect to EPMI’s involvement in the transaction going forward.

Western Power Market Issues

Avista Utilities and Avista Energy are directly and indirectly involved in the power markets in the western United States. Developments in these markets have impacted both Avista Utilities and Avista Energy. Federal and state officials, including the FERC and the California Public Utility Commission (CPUC), commenced reviews in 2000 to determine the causes of the changes in the wholesale energy markets to develop legal and regulatory remedies to address alleged market failures or abuses and large defaults by certain parties in the wholesale markets. The ultimate outcome of these reviews and the resulting impact on the Company cannot be predicted at this time.

In early 2001, California’s two largest utilities, Southern California Edison (SCE) and Pacific Gas & Electric Company (PG&E), defaulted on payment obligations owed to various energy sellers, including the California Power Exchange (CalPX), California Independent System Operator (CalISO), and Automated Power Exchange (APX). CalPX, CalISO and APX defaulted on their payment obligations to Avista Energy. PG&E and CalPX filed voluntary petitions under chapter 11 of the bankruptcy code for protection from creditors. SCE has not filed for bankruptcy protection. As of December 31, 2001, Avista Energy’s accounts receivable related to defaulting parties in California — net of reserves for uncollected amounts, cost of collection, and refunds — were approximately $6.5 million. Avista Energy is currently pursuing recovery for the defaulted obligations. Reserves for defaulted payments established in 2000 and 2001 accounted for the majority of the Company’s increase in the total allowance for doubtful accounts to $50.2 million as of December 31, 2001 from $14.4 million as of December 31, 2000 and $4.3 million as of December 31, 1999.

In April 2001, the FERC issued a price mitigation order that affected the CalISO spot market. In June 2001, the FERC expanded its price mitigation plan for the California spot market to 24 hours a day, seven days a week and broadened the price caps to the eleven state Western region. Since June 2001, spot market prices have remained below the FERC-imposed caps.

In July 2001, the FERC issued an order to commence a fact-finding hearing to determine amounts to be refunded for sales during the period from October 2, 2000 to June 20, 2001 in the California spot market. The order provides that any refunds owed could be offset against unpaid energy debts due to the same party. The FERC schedule for this proceeding has been postponed repeatedly and is not expected to be continued until August 2002 or later. Avista Energy is participating in this proceeding pursuant to the FERC order and cannot predict its outcome at this time. If retroactive price caps or refunds were imposed, Avista Energy could develop offsetting claims.

The July 2001 FERC order also directed an evidentiary proceeding to explore wholesale power market issues in the Pacific Northwest to determine whether there were excessive charges for spot market sales in the Pacific Northwest during the period from December 25, 2000 to June 20, 2001. Based on their application of selected retroactive pricing methods, certain parties asserted claims for significant refunds from Avista Energy and lesser refunds from Avista Utilities. Avista Energy and Avista Utilities joined with numerous other wholesale market participants to vigorously oppose proposals for retroactive price caps and refund claims. In September 2001, the FERC’s administrative law judge for this proceeding issued a recommendation that the FERC should not order refunds for the Pacific Northwest for the period in question and that the FERC should take no further action on these matters. The FERC has not yet issued a decision in the Pacific Northwest refund proceeding. If retroactive price caps or refunds were imposed, Avista Utilities and Avista Energy could develop offsetting claims.

Avista Corp. is participating with other utilities in the Pacific Northwest in the possible formation of a Regional Transmission Organization (RTO), RTO West, a non-profit organization. The potential formation of RTO West is in response to a FERC order requiring all utilities subject to FERC regulation to file a proposal to form a RTO, or a description of efforts to participate in a RTO, and any existing obstacles to RTO participation. Avista Corp. and three other Western utilities have also taken steps toward the formation of a for-profit Independent Transmission Company, TransConnect, which would be a member of RTO West, serve portions of six states and own or lease the high voltage transmission facilities of the participating utilities. TransConnect filed its proposal with FERC in November 2001. The final proposal must be approved by the FERC, the boards of directors of the filing companies and regulators in various states. The companies’ decision to move forward with the formation of TransConnect or RTO West will ultimately depend on the conditions related to the formation of the entities, as well as the economics and conditions imposed in the regulatory approval process. If TransConnect were formed, it could result in Avista Utilities divesting $174 million of electric transmission assets.

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Results of Operations

Overall Operations

2001 compared to 2000

Income from continuing operations was $59.6 million for 2001 compared to income from continuing operations of $101.1 million for 2000. The decrease is primarily due to reduced net income recorded by the Energy Trading and Marketing line of business, partially offset by an increase in net income from Avista Utilities. Also contributing to the decline in income from continuing operations was an increase in interest expense and $21.8 million of deferred power costs written off during 2001. The Energy Trading and Marketing line of business recorded net income of $70.1 million in 2001 compared to $161.8 million in 2000. Avista Energy’s operations continue to be positively affected by a well-positioned portfolio of energy-related assets in the Pacific Northwest and western energy markets. The primary reason for the decrease in net income was a reduction in the mark-to-market adjustment for the change in the fair value position of Avista Energy’s energy commodity portfolio. During the second half of 2001, volatility in wholesale energy markets in the western United States decreased, which reduced Avista Energy’s earnings potential. Net income recorded by Avista Utilities was $24.2 million in 2001, an increase from a net loss of $38.8 million in 2000. Avista Utilities’ net loss for 2000 was primarily due to unprecedented sustained peaks in electric energy prices compounded by a wholesale short position.

The Information and Technology line of business incurred a net loss of $19.4 million for 2001 compared to a net loss of $19.0 million for 2000 as Avista Advantage and Avista Labs continued to grow their operations.

The Other line of business incurred a net loss of $15.3 million for 2001 compared to a net loss of $2.9 million for 2000. The increase in the net loss from 2000 is primarily a result of increased interest expense on intercompany borrowings between Avista Capital and Avista Corp. that is eliminated in the consolidated financial statements.

The discontinued operations of Avista Communications incurred a net loss of $47.4 million for 2001 compared to a net loss of $9.4 million for 2000. The significant loss from Avista Communications is primarily due to pre-tax asset impairment charges of $58.4 million recorded during the third quarter of 2001.

Total revenues decreased $1,895.7 million in 2001 compared to 2000. Avista Utilities’ revenues decreased $281.3 million, or 19 percent, primarily due to decreased wholesale electric sales partially offset by increased retail revenues from both electric and natural gas sales. The increase in retail revenues is primarily a result of higher rates approved by state regulatory agencies to recover deferred power and natural gas costs. Revenues from the Energy Trading and Marketing line of business decreased $1,530.6 million, or 23 percent, primarily due to decreased sales volumes of electricity and natural gas from the continued downsizing of the business. Revenues from the Information and Technology companies increased 141 percent to $13.8 million primarily as a result of customer growth at Avista Advantage. Revenues from the Other line of business decreased $16.6 million, or 50 percent, reflecting decreased activity in this line of business. Intersegment eliminations represent the transactions between Avista Utilities and Avista Energy for commodities and services. Intersegment eliminations increased $75.4 million from 2000 to 2001. The significant increase was primarily due to an increase in prices for natural gas to serve Avista Utilities’ retail customers and to fuel natural gas-fired turbines to generate electricity.

Resource costs decreased $1,829.0 million in 2001 compared to 2000. Avista Utilities’ resource costs decreased $396.5 million, or 32 percent, primarily due to reduced wholesale power purchases. Energy Trading and Marketing resource costs decreased $1,357.1 million, or 22 percent, primarily due to decreased energy trading volumes.

Administrative and general expenses decreased $15.7 million primarily due to reduced expenses for Avista Utilities and Energy Trading and Marketing. This was primarily a result of company-wide initiatives to reduce expenses. This was also due to decreased incentive compensation expense based on lower earnings by both Avista Energy and the Company.

Interest expense increased $38.2 million in 2001 compared to 2000, primarily due to higher levels of outstanding debt during the year. Long-term debt and short-term borrowings outstanding as of December 31, 2001 increased $320.2 million from December 31, 2000.

Capitalized interest increased $7.1 million from 2000 to 2001 primarily due to increased interest capitalized for the Coyote Springs 2 power plant project.

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Income taxes decreased $42.6 million in 2001 compared to 2000, primarily due to decreased earnings before income taxes. The effective tax rate was 36.6 percent for 2001 compared to 43.2 percent for 2000. The higher effective tax rate in 2000 was primarily due to higher state income taxes.

Preferred stock divided requirements decreased from 2000 due to the conversion of all outstanding shares of Series L Preferred Stock into shares of common stock, which resulted in a one-time charge of $21.3 million for preferred stock dividend requirements in 2000.

Diluted earnings per share from continuing operations were $1.20 for 2001 compared to earnings from continuing operations of $1.67 per diluted share for 2000. Avista Utilities contributed $0.46 per share for 2001 compared to a net loss of $1.37 per share for 2000. The Energy Trading and Marketing operations contributed $1.47 per diluted share for 2001 compared to a contribution of $3.51 per diluted share for 2000. The Information and Technology operations recorded a net loss of $0.41 per diluted share for 2001, consistent with a net loss of $0.41 per diluted share for 2000. The Other line of business recorded a net loss of $0.32 per diluted share for 2001 compared to a net loss of $0.06 per diluted share for 2000. The discontinued operations of Avista Communications recorded a net loss of $1.00 per diluted share for 2001 compared to a net loss of $0.20 per diluted share for 2000.

2000 compared to 1999

Income from continuing operations was $101.1 million for 2000, an increase compared to income from continuing operations of $28.7 million for 1999. The primary reason for the increase in income from continuing operations was earnings of $161.8 million recorded by the Energy Trading and Marketing line of business, compared to a loss of $60.7 million in 1999 recorded by this business segment. Avista Energy benefited in 2000 from a well-positioned portfolio of energy-related assets and significant increases in the volatility of Pacific Northwest and western United States energy markets during 2000. The loss from Avista Energy in 1999 related to expenses associated with the downsizing and restructuring of the business, as well as operational losses. The positive earnings from Avista Energy in 2000 were partially offset by net losses from the other lines of business. Avista Utilities’ operations recorded a net loss of $38.8 million for 2000 compared to net income of $59.6 million for 1999, primarily the result of significantly higher purchased power costs compounded by short positions related to wholesale trading activity at the utility during the second quarter of 2000. (See paragraphs below for additional information about the higher energy prices and short positions).

The Information and Technology line of business incurred a net loss of $19.0 million for 2000 compared to a net loss of $6.0 million for 1999 as Avista Advantage and Avista Labs substantially increased their operations and the corresponding effect on operating expenses.

The Other line of business incurred a net loss of $2.9 million for 2000 compared to net income of $35.8 million for 1999. The 1999 earnings included transactional gains recorded by Pentzer that totaled $35.9 million from the sale of two groups of portfolio companies.

The discontinued operations of Avista Communications resulted in a net loss of $9.4 million for 2000 compared to a net loss of $2.6 million for 1999 reflecting the expansion of operations.

Total revenues increased $3.2 million in 2000 compared to 1999; however, there were large changes within the individual lines of business. Avista Utilities’ revenues increased $396.5 million, or 36 percent, primarily due to increased wholesale electric sales. Revenues for Energy Trading and Marketing decreased $164.1 million, or 2 percent due to decreased sales volumes of electricity and natural gas from the restructuring and downsizing of the business, offset by higher energy commodity prices. Revenues from the Information and Technology companies increased 153 percent to $5.7 million as Avista Advantage continued to increase its customer base. Revenues from the Other line of business decreased $89.4 million or 73 percent due to the sale of the Creative Solutions Group and Store Fixtures Group of portfolio companies by Pentzer during 1999. Intersegment eliminations increased $143.3 million from 1999 to 2000. The significant increase from 1999 to 2000 was primarily due to an entire year of activity under the agency agreement whereby Avista Energy serves as agent for Avista Utilities, managing its natural gas pipeline transportation contract rights and storage assets, as well as purchasing natural gas for Avista Utilities’ retail customers.

Resource costs decreased $97.8 million from 1999 to 2000. Avista Utilities’ resource costs increased 75 percent, primarily due to increased wholesale power purchases to meet wholesale sales requirements. Energy Trading and Marketing’s resource costs decreased 7 percent, due to reduced energy trading volumes partially offset by higher energy commodity prices.

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Operation and maintenance expenses decreased $58.1 million from 1999 to 2000 primarily due to the Other line of business as a result of the sales of portfolio companies by Pentzer during 1999.

Administrative and general expenses increased $10.9 million from 1999 to 2000. This was due to both the expansion of operations in the Information and Technology line of business and increased incentive compensation at Avista Energy. These increases are partially offset by decreased administrative and general expenses for the Other line of business as a result of the sales of portfolio companies by Pentzer during 1999.

Interest expense increased $3.5 million in 2000 compared to 1999, primarily due to higher levels of outstanding debt during the year. Long-term debt and short-term borrowings outstanding as of December 31, 2000 were $217.1 million higher than as of December 31, 1999.

Other income-net decreased $48.1 million from 1999 to 2000 primarily due to a decrease in the net gain on subsidiary transactions. The net gain of $57.5 million in 1999 primarily related to the sale of two groups of portfolio companies by Pentzer.

Income taxes increased $60.1 million in 2000 compared to 1999, primarily due to increased earnings before income taxes. The effective tax rate was 43.2 percent for 2000 compared to 37.1 percent for 1999.

Preferred stock dividend requirements increased $2.3 million in 2000 compared to 1999 due to the conversion costs and dividends paid associated with converting the Convertible Preferred Stock, Series L, into common stock in February 2000.

Diluted earnings per share from continuing operations were $1.67 for 2000 compared to $0.19 for 1999. Energy Trading and Marketing’s earnings per diluted share increased to $3.51 in 2000 compared to a loss of $1.59 per diluted share in 1999, due primarily to the volatile energy market discussed above. Avista Utilities’ recorded a loss of $1.37 per diluted share in 2000 compared to earnings of $1.00 per diluted share in 1999. Information and Technology’s net loss increased to $0.41 per diluted share in 2000 compared to a loss of $0.16 per diluted share in 1999, as Avista Advantage and Avista Labs continued to grow their operations. Income from the Other line of business decreased to a loss of $0.06 per diluted share in 2000 compared to earnings of $0.94 per diluted share in 1999. The 1999 earnings included transactional gains recorded by Pentzer from the sale of two groups of portfolio companies. The discontinued operations of Avista Communication’s net loss was $0.20 per diluted share in 2000 compared to a loss of $0.07 per diluted share in 1999.

Avista Utilities

2001 compared to 2000

Avista Utilities recorded net income of $24.2 million in 2001 compared to a net loss of $38.8 million in 2000. Avista Utilities’ pre-tax income from operations was $114.9 million for 2001 compared to $3.2 million for 2000. This increase was primarily due to an increase in gross margin. Avista Utilities’ operating revenues decreased $281 million and resource costs decreased $396 million resulting in an increase of $115 million in gross margin for 2001 as compared to 2000.

Based on views of streamflows, historic wholesale market prices and energy availability in the second quarter of 2000, Avista Utilities entered into contracts and sold call options for fixed-price power for delivery without making matching purchases at the same time. Avista Utilities also made certain short-term sales at fixed prices that were offset by purchases at prices indexed to the market price at the time of delivery. Certain of these wholesale trading positions were outside normal operating guidelines. Avista Utilities was required to buy additional power not only to meet its obligations to its retail and long-term wholesale customers, but also to cover its wholesale trading positions. An orderly process to complete the necessary power purchases was impeded by the rapid escalation of market prices and lack of liquidity in the power markets during the second quarter of 2000. These purchases were made at fixed prices significantly higher than the related selling prices and at index, which settled at unprecedented levels in June 2000. The pricing of these purchases caused the majority of Avista Utilities’ net loss for 2000.

Avista Utilities’ short position was compounded by the May 2000 sale of its interest in the Centralia Power Plant to TransAlta, which reduced its system capacity by 200 megawatts. Based on historical trends and Avista Utilities’ views on power prices and availability of power for May and June 2000, Avista Utilities did not seek to replace the Centralia Power Plant generation for those two months with firm commitments. Avista Utilities entered into a three-and-one-half-year contract to purchase 200 megawatts from TransAlta beginning in July 2000.

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Retail electric revenues increased $4.0 million for 2001 from 2000. This increase was primarily due to the electric surcharges implemented in Washington and Idaho to recover deferred power costs, partially offset by decreased use per customer and kWh sold. Wholesale electric revenues decreased $383.9 million, or 44 percent, while wholesale sales volumes decreased 60 percent from 2000, reflecting average sales prices that were 40 percent higher than the prior year. Wholesale sales volumes decreased due to management’s decision in 2000 to reduce power imbalance volume limits (the difference between projected load obligations and projected resource availability). This decision was based on the emergent market price volatility, and Avista Utilities’ strategy to focus primarily on energy transactions necessary to efficiently manage power resources to meet retail customer loads and wholesale obligations. The extent of future wholesale transactions will be determined based on resource additions or changes and load obligations and contract commitments.

Natural gas revenues increased $83.8 million for 2001 from 2000 due to increased prices approved by state commissions to recover increased natural gas costs partially offset by decreased therm sales, primarily due to both decreased retail and transportation customer volumes.

Power purchased during 2001 decreased $364.2 million, or 34 percent compared to 2000 primarily due to the decreased volume of power purchases, partially offset by higher average prices. Average purchased power prices for 2001 were 28 percent higher than for 2000; however, volumes purchased decreased 48 percent. The decrease in the volume of purchased power was primarily the result of decreases in the volume of wholesale electric sales.

During 2001 Avista Utilities deferred $145.4 million (net of the $21.8 million write-off) in power costs in Washington and $73.7 million in Idaho. The total balance of deferred power costs was $140.2 million for Washington and $73.1 million for Idaho as of December 31, 2001. Avista Utilities will only be able to recover these balances of deferred power costs in the amounts, and at the times, authorized by the WUTC and the IPUC. In September 2001, the WUTC approved a temporary electric surcharge of 25 percent. In 2001, revenue collected under the Washington surcharge was $10.2 million and $53.8 million of a deferred non-cash credit was offset against deferred power costs. In October 2001, the IPUC approved a PCA surcharge and the extension of a previously approved PCA surcharge for a total of 19.4 percent. In 2001, revenue collected under the Idaho PCA surcharges was $4.2 million and $6.9 million of a deferred non-cash credit was offset against deferred power costs. In March 2002, the WUTC issued an order approving the prudence and recoverability of 90 percent of deferred power supply costs incurred during the period from July 1, 2000 through December 31, 2001. This resulted in the Company recording an additional expense for $21.8 million of power supply costs previously deferred in 2001. Additionally, the order also provided that one-fifth of the 25 percent electric surcharge will be applied to offset the Company’s general operating costs and the remainder will continue to be applied as a recovery of deferred power costs. The WUTC order also approved a 6.2 percent (or $14.7 million in annual revenues) increase in base retail rates. See further description of issues related to deferred power costs in the section “Avista Utilities — Regulatory Matters.”

Avista Utilities deferred, net of amortization, $7.7 million of purchased natural gas costs during 2001 and total deferred natural gas costs were $52.7 million as of December 31, 2001. In July 2001, the Company filed requests for purchased gas cost adjustments (PGA) with the WUTC and the IPUC in order to recover certain deferred natural gas costs related to Washington and Idaho natural gas purchases. The Washington PGA increase of 12.2 percent approved by the WUTC and the Idaho PGA increase of 11.5 percent approved by the IPUC became effective in August 2001. Avista Utilities estimates these PGA rate changes will increase revenues by $24.6 million for approximately one year. Based on current PGAs in place and current natural gas prices, Avista Utilities expects that the deferred natural gas cost balance will be fully recovered by December 2002. However, there will be no impact on net income as deferred natural gas costs are amortized to offset this increase in revenues.

The cost of fuel for generation for 2001 increased $12.9 million from 2000 primarily due to an increase in natural gas-fired combustion turbine plant generation and partially due to the increased cost of natural gas. Natural gas costs were relatively high compared to historical prices during the first half of 2001 before declining in the second half of 2001.

The expense for natural gas purchased for resale for 2001 increased $50.8 million compared to 2000 due to the increased cost of natural gas partially offset by a decrease in total therms sold. Consistent with changes in fuel for generation, natural gas costs have declined during the second half of 2001 compared to the first half of the year.

As part of the strategy to mitigate the decline in electric resources caused by the poor hydroelectric conditions and volatile energy markets, Avista Utilities had several buy-back and rebate programs for residential, commercial and industrial customers during 2001. The programs were designed to encourage conservation and decrease average

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customer usage.

Construction is continuing on the 280 MW combined cycle natural gas-fired turbine power plant at the Coyote Springs 2 site near Boardman, Oregon. During the fourth quarter of 2001, the Company completed the sale of 50 percent of its interest in the Coyote Springs 2 plant to an affiliate of Mirant Americas Development, Inc. (Mirant). Avista Corp. and Mirant will share equally in the costs of construction, operation and output from the plant. As of December 31, 2001, the Company had invested $92.5 million in the Coyote Springs 2 project (net of funds received from Mirant in connection with the sale) and the total cost of the plant is expected to be $190 million. If total costs equal the amount projected, Mirant will fund the remaining costs to complete the plant. The Company’s 50 percent ownership interest in the Coyote Springs 2 plant will transfer from Avista Power to Avista Corp. to be operated as an asset of Avista Utilities upon the completion of the construction, which is expected to be in the third quarter of 2002.

2000 compared to 1999

Avista Utilities recorded a net loss of $38.8 million in 2001 compared to net income of $59.6 million in 1999. Avista Utilities’ pre-tax income from operations was $3.2 million in 2000, a decrease of $139.4 million from 1999. The net loss in 2000 resulted primarily from significantly higher electric energy prices in wholesale markets, compounded by a short position related to wholesale trading activity. Avista Utilities’ operating revenues and expenses increased $396.5 million and $535.8 million, respectively, in 2000 compared to 1999.

During 2000, Avista Utilities purchased energy in order to meet system obligations to serve retail and wholesale customers. Unprecedented sustained peaks in electric energy prices throughout the WSCC beginning in May 2000, compounded by a wholesale short position and the sale of the Centralia Power Plant discussed above, contributed to significant losses recorded by Avista Utilities in the second quarter of 2000. The cost of these power purchases was significantly higher than the amounts recovered through power sales. Based on historical trends, Avista Utilities had forecast on-peak power prices of approximately $19 per megawatthour for May and June of 2000. On-peak power costs in the market averaged $60 per megawatthour in May and over $180 per megawatthour in June, with hourly spikes as high as $1,300 per megawatthour.

Retail electric revenues increased $10.6 million in 2000 compared to 1999 due to increased rates, as well as greater sales volumes due to customer growth and increased usage due to weather. Wholesale electric revenues increased $342.3 million, or 66 percent, while sales volumes decreased 20 percent in 2000 compared to 1999, reflecting average sales prices 107 percent higher in 2000. Wholesale sales volumes decreased due to management’s decision in mid-year to reduce power imbalance volume limits as discussed above.

Natural gas revenues increased $37.4 million in 2000 compared to 1999. Retail natural gas revenues increased $49.0 million, primarily due to increased natural gas rates, partially offset by a $9.5 million decrease in wholesale sales. Wholesale natural gas sales are sales of natural gas commodity and related services outside of the Avista Utilities distribution system to other utilities and large industrial customers. Revenues from these sales are offset by corresponding increases in purchased gas expense, and margins from these transactions are credited back to retail customers through rate changes approved by state regulators for the cost of natural gas.

Purchased power volumes were 15 percent lower in 2000 as compared to 1999 primarily due to decreased wholesale sales, but average purchased power prices were 132 percent higher, resulting in a $529.0 million, or 97 percent, increase in purchased power expense in 2000 compared to 1999. The $33.9 million deferral of power costs pursuant to the WUTC accounting order and the $4.5 million deferred under the Idaho PCA partially offset purchased power cost recognized as expenses in 2000. Streamflows in 2000 were 86 percent of normal compared to 112 percent in 1999. Fuel for power generation expense increased $22.7 million due to increased generation at the thermal plants as a result of increased demand for power, decreased hydroelectric generation and increases in natural gas commodity prices. Purchased natural gas costs increased $53.4 million in 2000, primarily due to increased prices for the commodity, and partially due to increased volumes of sales resulting from customer growth and increased usage due to weather.

Energy Trading and Marketing

Energy Trading and Marketing includes the results of Avista Energy and Avista Power. Avista Energy maintains an energy trading portfolio that it marks to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings variability in the future. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments. For longer-term positions and certain short-term positions for which market prices are not available, a model based on forward price curves is also utilized. Although Avista

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Energy scaled back operations to focus primarily in the western United States during 2000, its trading operations continue to be affected by, among other things, volatility of prices within the electric energy and natural gas markets, the demand for and availability of energy, lower unit margins on new sales contracts, FERC-ordered price caps and deregulation of the electric utility industry.

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 a largely unregulated “over-the-counter” basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges). As a result of these trading activities, Avista Energy is subject to various risks, including market, liquidity, commodity and credit risk. See “Business Risks” and “Note 7 of Notes to Consolidated Financial Statements” for further information. The following summarizes information with respect to energy trading activities during 2001 (dollars in thousands):

                         
    Natural Gas   Electric   Total
    Assets and   Assets and   Unrealized
    Liabilities   Liabilities   Gain(Loss)
   
 
 
Fair value of contracts as of December 31, 2000
  $ 15,319     $ 201,636     $ 216,955  
Less contracts settled during 2001 (1)
    (51,291 )     (114,785 )     (166,076 )
Fair value of new contracts when entered into during 2001 (2)
                 
Change in fair value due to changes in valuation techniques (3)
    1,282       13,971       15,253  
Change in fair value attributable to market prices and other market changes
    73,082       47,503       120,585  
 
   
     
     
 
Fair value of contracts as of December 31, 2001
  $ 38,392     $ 148,325     $ 186,717  
 
   
     
     
 

(1)   Contracts settled during 2001 includes those contracts that were open in 2000 but settled in 2001 as well as new contracts entered into and settled during 2001. Amount represents realized earnings associated with these settled transactions.
(2)   Avista Energy did not enter into any origination transactions during 2001 in which dealer profit or mark-to-market gain or loss was recorded at inception.
(3)   During 2001, Avista Energy changed the interest rate used to discount trading positions from an incremental borrowing rate to LIBOR. Additionally, Avista Energy eliminated a specific liquidity and valuation adjustment related to the California market that was in place as of December 31, 2000.

The following discloses summarized information with respect to valuation techniques and contractual maturities of energy commodity contracts outstanding as of December 31, 2001 (dollars in thousands):

                                           
              2003 and   2005 and   2006 and        
      2002   2004   2006   later   Total
     
 
 
 
 
Natural gas assets and liabilities
                                       
 
Prices from other external sources (1)
  $ 11,217     $ 21,594     $     $     $ 32,811  
 
Fair value based on valuation models (2)
    1,829       581       2,031       1,140       5,581  
 
   
     
     
     
     
 
 
Total natural gas assets and liabilities
  $ 13,046     $ 22,175     $ 2,031     $ 1,140     $ 38,392  
 
   
     
     
     
     
 
Electric assets and liabilities
                                       
 
Prices from other external sources (1)
  $ 92,456     $ 43,344     $     $     $ 135,800  
 
Fair value based on valuation models (3)
    (1,842 )     7,125       8,546       (1,304 )     12,525  
 
   
     
     
     
     
 
 
Total electric assets and liabilities
  $ 90,614     $ 50,469     $ 8,546     $ (1,304 )   $ 148,325  
 
   
     
     
     
     
 

(1)   The fair value is determined based upon actively traded, “over-the-counter” market quotes received from third party brokers. For natural gas assets and liabilities, these market quotes are generally available through three years. For electric assets and liabilities, these market quotes are generally available through two 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 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 seven years, an escalation is used to estimate the valuation.
(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 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 conducts frequent stress tests on the valuation of its portfolio. By changing the input assumptions to the internally developed market curves,

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    these stress tests attempt to capture the Company’s sensitivity to changes in portfolio valuation. These stress tests indicate that, for the portfolio valued under internally developed market curves, the valuations can be reasonably certain to fall within 20 percent, upwards or downwards, of the reported values listed above.

2001 compared to 2000

Energy Trading and Marketing’s net income was $70.1 million for 2001, compared to $161.8 million for 2000. Avista Energy’s operations continue to be positively affected by a well-positioned portfolio of energy-related assets in the Pacific Northwest and western energy markets. The primary reason for the decrease in net income was a decrease in the mark-to-market adjustment for the change in the fair value position of Avista Energy’s energy commodity portfolio. The mark-to-market adjustment was an unrealized loss of $30.2 million for 2001 compared to an unrealized gain of $176.8 million for 2000. The decrease is primarily due to a significant amount of contracts settled during 2001 and the realization of previous unrealized gains. Volatility in energy markets and increased commodity prices during 2000 resulted in significant unrealized gains during 2000. These unrealized gains were partially realized during 2001. The majority of the remaining unrealized gains are expected to be realized during 2002 and 2003 as commodity contracts are settled.

Energy Trading and Marketing’s operating revenues and cost of sales decreased $1,530.6 million and $1,357.1 million, respectively, for 2001 compared to 2000, resulting in a decrease in gross margin of $173.5 million. The decrease in revenues and expenses is primarily the result of decreased sales volumes from 2000. Although gross margin decreased from 2000 to 2001, realized gross margin increased to $164.5 million in 2001 from $130.9 million in 2000.

Administrative and general expenses decreased $7.8 million or 19 percent from 2000 primarily due to reduced incentive compensation expense based on lower earnings in 2001.

Expenses associated with the exit of Avista Energy’s operations in Houston and Boston during the first half of 2000 totaled $7.9 million in 2000.

During 2001 the Company recorded an impairment charge of $8.2 million related to three turbines owned by Avista Power which is reflected in the line item other income-net in the Consolidated Statements of Income. The Company originally planned to use these turbines in a non-regulated generation project. The Company decided that it would no longer pursue the development of additional non-regulated generation projects. As such, the Company wrote down the carrying value of the turbines to estimated fair value less selling costs and is in the process of completing the sale of the turbines.

Energy Trading and Marketing’s total assets decreased $8.77 billion from December 31, 2000 to December 31, 2001 primarily due to a decrease in total current and non-current energy commodity assets. This decrease in commodity assets primarily reflects the settlement of a significant amount of contracts during 2001 and a decrease in the forward price and estimated value of natural gas and electricity from December 31, 2000 to December 31, 2001.

Avista Power is a 49 percent owner of a 270 MW natural gas-fired combustion turbine plant in Rathdrum, Idaho, which commenced commercial operation in September 2001. The output from this plant is contracted to Avista Energy for 25 years. Avista Power is in the process of constructing the Coyote Springs 2 power plant and it sold 50 percent of its interest to Mirant during the fourth quarter of 2001. Upon the planned completion of the plant in the third quarter of 2002, Avista Power’s 50 percent ownership interest will be transferred to Avista Corp. for inclusion with the Avista Utilities’ power generation resource portfolio.

2000 compared to 1999

Energy Trading and Marketing’s net income was $161.8 million for 2000 compared to a net loss of $60.7 million for 1999. A well-positioned portfolio in the volatile Pacific Northwest and western electric markets positively affected Avista Energy’s operations in 2000. During the second half of 1999 and the first half of 2000, Avista Energy’s operations were negatively impacted by losses from the liquidation of its Eastern electric book and associated operating costs to close its Eastern operations in Houston and Boston.

In November 1999, Avista Energy began redirecting its focus away from national energy trading toward a more regionally based energy trading and marketing effort in the western United States. Its more narrowly focused operations are backed by contracts for energy commodities and by the output of specific facilities available under contracts. Avista Energy shut down its operations in Houston and Boston during the first half of 2000 and reduced

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employment by approximately 80 positions. The Eastern electric book was sold at a $1.0 million after-tax loss in early 2000.

Energy Trading and Marketing’s operating revenues and operating expenses decreased $164.1 million and $512.1 million, respectively, in 2000 compared to 1999. The decrease in revenues was primarily due to lower sales volumes, partially offset by increased energy commodity prices. The decreased expenses primarily resulted from reduced volumes of transactions, partially offset by increased resource costs due to higher energy commodity prices, and the closure of Avista Energy’s Eastern operations and refocusing the business to the western United States.

The volume of power and natural gas sales decreased significantly as Avista Energy’s focus was redirected to the WSCC. Electric sales volumes decreased 22 percent, while natural gas sales decreased 65 percent. The exception to this was the comparatively minor coal sales, which increased 115 percent in volume in 2000 compared to 1999. However, after the Houston and Boston offices were closed, no more coal sales were made and the remaining contracts expired by the end of 2000.

Energy Trading and Marketing’s balance sheet increased $8.68 billion from December 31, 1999 to December 31, 2000. Avista Energy’s energy commodity assets and liabilities increased primarily as a result of significant price increases for both natural gas and power during this period. Trade receivables and payables increased due to higher market prices on current positions.

Information and Technology

The Information and Technology line of business includes the results of Avista Advantage and Avista Labs. Consistent with its overall business strategy, the Company is attempting to find equity partners to assist in financing the continued growth of these businesses.

2001 compared to 2000

Information and Technology’s net loss was $19.4 million for 2001 compared to a net loss of $19.0 million for 2000. Operating revenues and expenses for this line of business increased $8.1 million and $11.5 million, respectively, as compared to 2000. Avista Advantage accounted for the increase in revenues primarily due to the expansion of its customer base. The increase in operating expenses reflects expansion of operations for Avista Advantage and further fuel cell development by Avista Labs.

2000 compared to 1999

Information and Technology’s net loss was $19.0 million for 2000 compared to a net loss of $6.0 million for 1999. Operating revenues and expenses for this line of business increased $3.5 million and $21.0 million, respectively, over 1999. Avista Advantage accounted for the increase in operating revenues while each of Avista Advantage and Avista Labs contributed to the increase in operating expenses.

Other

The Other line of business includes the results of Avista Ventures, Avista Capital (parent company only amounts), Pentzer and several other minor subsidiaries.

2001 compared to 2000

The net loss from this line of business was $15.3 million for 2001, compared to a net loss of $2.9 million for 2000. The increase in the net loss from 2000 is primarily a result of increased interest expense on intercompany borrowings between Avista Capital and Avista Corp. that is eliminated in the consolidated financial statements. Operating revenues and expenses from this line of business decreased $16.6 million and $16.0 million, respectively, during 2001 as compared to 2000 reflecting reduced activities in this line of business.

2000 compared to 1999

The net loss from this line of business was $2.9 million for 2000, compared to net income of $35.8 million in 1999. The 2000 net loss includes a $1.2 million after-tax charge recorded by Pentzer in the first quarter for expenses related to employee terminations resulting from a redirection of Pentzer’s business focus. The 1999 earnings included transactional gains totaling $35.9 million, net of taxes, recorded by Pentzer as a result of the sale of its

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Creative Solutions Group and Store Fixtures Group of portfolio companies, partially offset by a loss on the sale of equipment.

Operating revenues and expenses from this line of business decreased $89.4 million and $79.9 million, respectively, during 2000, primarily as a result of the sales of portfolio companies by Pentzer. The Creative Solutions Group of companies was sold at the end of the first quarter of 1999 and the Store Fixtures Group of companies were sold during the third quarter of 1999. Revenues and expenses from these companies were included only in the 1999 amounts.

Discontinued Operations

In September 2001, the Company reached a decision that it would dispose of substantially all of the assets of Avista Communications. The divestiture is expected to be completed during the first half of 2002. In October 2001, minority shareholders of Avista Communications acquired ownership of its Montana and Wyoming operations as well as its dial-up internet access operations in Spokane, Washington and Coeur d’Alene, Idaho. In December 2001, Avista Communications completed the sale of the assets and customer accounts of its Yakima and Bellingham, Washington operations to Advanced Telcom Group, Inc. In December 2001, Avista Communications entered an agreement to transfer voice and integrated services customer accounts in Spokane, Washington and Coeur d’Alene, Idaho to certain subsidiaries of XO Communications, Inc. The Company is continuing to pursue disposal of the remaining portions of the business.

In connection with the planned disposal of substantially all of the operating assets of Avista Communications, the Company wrote down the value of the assets to the estimated fair value of the assets upon the planned disposal of the business unit, resulting in a charge of $58.4 million.

2001 compared to 2000

The net loss for 2001 was $47.4 million, compared to a net loss of $9.4 million for 2000. The significant net loss for 2001 was due to asset impairment charges. The loss from operations for Avista Communications was $21.1 million for 2001 compared to $15.4 million for 2000.

2000 compared to 1999

The net loss for 2000 was $9.4 million, compared to a net loss of $2.6 million for 2000. The loss from operations for Avista Communications was $15.4 million for 2001 compared to $4.3 million for 2000. The significant increase in the net loss and the loss from operations from 1999 to 2000 was due to the rapid expansion of the Avista Communications business during this period.

Critical Accounting Policies

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 impact on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

The Company prepares its consolidated financial statements in accordance with the provisions of Statement of Financial Accounting Standards (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) be reflected in a deferral account in the balance sheet and not be reflected in the statement of income until matching revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 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 such costs were expected to be recovered in the future. In accordance with SFAS No. 71, profits recognized by Avista Energy on natural gas sales to Avista Utilities, including unrealized gains on natural gas contracts, are not eliminated in the consolidated financial statements. This is due to the fact that costs incurred by Avista Utilities for natural gas purchases to serve retail customers and for fuel for electric generation are recovered through future rates.

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The Company’s primary regulatory assets include power and natural gas deferrals, investment in exchange power, regulatory assets for deferred income taxes, unamortized debt expense, regulatory asset offsetting energy commodity derivative liabilities, conservation programs and the provision for postretirement benefits. Deferred credits include regulatory liabilities created when the Centralia Power Plant was sold and the gain on the general office building sale/leaseback which is being amortized over the life of the lease.

Avista Energy accounts for derivative commodity instruments entered into for trading purposes using the mark-to-market method of accounting, in compliance with Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Energy Trading and Risk Management Activities”, with unrealized gains and losses recognized in the consolidated statements of income. Avista Energy recognizes revenue based on the change in the market value of outstanding derivative commodity sales contracts, net of future servicing costs and reserves, in addition to revenue related to physical and financial contracts that have matured. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments. For longer-term positions and certain short-term positions for which market prices are not available, a valuation model based on estimated forward price curves is also utilized which requires the use of subjective assumptions and variables. The use of different assumptions and variables in the valuation model could have a material impact on the fair value of the commodity instruments and the unrealized gain or loss recognized in the consolidated financial statements.

Avista Utilities buys and sells energy under forward contracts that are considered to be derivatives and accounts for these derivatives in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under forward contracts, Avista Utilities commits to purchase or sell a specified amount of capacity and energy. These contracts are generally entered into to manage Avista Utilities’ energy requirements and resources. In conjunction with the issuance of SFAS No. 133, the WUTC and the IPUC issued accounting orders requiring Avista Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. As a result, unrealized gains or losses for Avista Utilities are not recognized in the consolidated statements of income and comprehensive income.

Interpretations that may be issued by the Derivatives Implementation Group, a task force created to assist the Financial Accounting Standards Board (FASB) in answering questions that companies have in implementing SFAS No. 133, may change the conclusions that the Company has reached regarding accounting for energy contracts. As a result, the accounting treatment and financial statement impact could change in future periods.

For further information on the Company’s accounting policies and new accounting standards that will be adopted by the Company in future periods see “Notes 1 and 2 of Notes to Consolidated Financial Statements.”

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Liquidity and Capital Resources

Review of Cash Flow Statement

Continuing Operating Activities Net cash used in continuing operating activities was $93.3 million in 2001 compared to net cash provided by continuing operating activities of $84.1 million in 2000. The primary reason for the increase in net cash used in continuing operating activities was power and natural gas cost deferrals including interest, net of amortization, of $248.4 million in 2001 compared to $67.3 million in 2000. This was primarily due to the effect of increased purchased power prices, fuel for generation and natural gas costs, as well as low hydroelectric availability that increased the volume of purchased power that was needed to meet retail demand. Also contributing to the decrease in cash flows from continuing operating activities was a decrease in net income. Net cash used in working capital components increased in 2001 compared to 2000, with net cash used of $90.0 million in 2001 compared to net cash provided by working capital components of $74.7 million in 2000. Decreased commodity prices and energy transactions that affected both Avista Utilities and Avista Energy were primarily responsible for the large changes in various working capital components, such as receivables and accounts payable. Significant changes in non-cash items also include a $183.5 million change in energy commodity assets and liabilities, primarily related to Avista Energy.

Continuing Investing Activities Net cash used in continuing investing activities was $218.4 million in 2001 compared to $65.1 million in 2000. The increase in net cash used in continuing investing activities was primarily the result of increased capital expenditures in 2001 including $157.0 million by the Energy Trading and Marketing line of business. These expenditures were primarily for the construction of the Coyote Springs 2 power plant and Avista Power’s acquisition of turbines originally planned for use in a non-regulated generation project. In 2001, proceeds from property sales and subsidiary investments were $76.0 million, primarily related to the sale of the 50 percent interest in the Coyote Springs 2 power plant and Avista Power’s turbines. In 2000, $105.2 million in proceeds were provided from the sale of property and subsidiary investments, primarily related to the sale of the Company’s interest in the Centralia Power Plant.

Continuing Financing Activities Net cash provided by continuing financing activities was $302.9 million in 2001 compared to $175.3 million in 2000. Short-term borrowings decreased $88.1 million and long-term debt increased $410.2 million in 2001. The overall increase in borrowings in 2001 reflects increased cash needs for the Company to fund investing activities, increased power and natural gas costs and other operating needs.

On April 3, 2001, the Company issued $400.0 million of 9.75 percent Senior Notes (Senior Notes) due June 1, 2008. The net proceeds from the issuance were used to fund a portion of construction expenditures, pay down balances outstanding under the Company’s committed line of credit and for other general corporate purposes. The Senior Notes were issued under an indenture that, among other things, restricts the ability of the Company and its subsidiaries from engaging in certain activities, including certain transactions with affiliates. In December 2001, the Company issued $150.0 million of 7.75 percent First Mortgage Bonds due in 2007. The proceeds from the issuance were used to fund maturing Medium-Term Notes and pay down balances outstanding under the Company’s committed line of credit. During 2001, $15.0 million of Secured Medium-Term Notes, with rates of 7.59 percent and 7.60 percent, and $74.0 million of Unsecured Medium-Term Notes, with rates between 8.0 percent and 9.57 percent, matured. The Company also used a portion of the $150.0 million of proceeds from issuance of First Mortgage Bonds to legally defease $50.0 million of Medium-Term Notes scheduled to mature in 2002 with interest rates between 6.28 percent and 8.15 percent.

Short-term borrowings increased $42.1 million and long-term debt increased $169.7 million in 2000. In August and December of 2000, the Company issued a total of $224.0 million of Unsecured MTNs, Series D at rates of 8.0 percent and 8.625 percent due in 2001 and 2003. A total of $44.9 million of Secured MTNs matured during 2000, with rates between 6.13 percent and 8.20 percent.

During 2001, the Company issued 423,989 shares of common stock for $8.3 million. The shares were issued through the Employee Investment Plan, the Dividend Reinvestment and Stock Purchase Plan as well as restricted stock through the Long-Term Incentive Plan.

Discontinued Operations Net cash used in discontinued operations was $17.2 million in 2001 compared to $37.1 million of net cash used in discontinued operations in 2000. The decrease was primarily due to a decrease in capital expenditures by Avista Communications as the Company decided to dispose of the operations.

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Overall Liquidity

The Company’s cash outlays for purchased power have exceeded the related amounts paid to the Company by its retail customers. This condition, which was due to reduced availability of hydroelectric resources, increased prices in the wholesale market and increased volumes purchased to meet retail customer demand, has existed since the second quarter of 2000. 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. Debt service is another significant cash requirement. In addition, the Company made significant cash investments to finance the development of companies in the Information and Technology line of business.

The temporary electric surcharge in Washington and the PCA surcharge in Idaho, which were implemented during September and October 2001, respectively, provide a basis for improving the Company’s liquidity. The Company completed the sale of 50 percent of its interest in the Coyote Springs 2 project to Mirant during the fourth quarter of 2001. The Company is also in the process of selling three turbines owned by Avista Power with part of the proceeds received during 2001 and the remainder to be received during the first half of 2002. Additionally, the Company reduced capital expenditures by $15 million for the fourth quarter of 2001 and by $40 million for 2002 from the amount originally budgeted. The Company’s disposal of Avista Communications reduces future cash investments in the Information and Technology line of business. These measures are largely related to the Company’s efforts to improve cash flows and should provide the Company the ability to maintain access to adequate levels of credit with its banks. In March 2002, the WUTC issued an order approving the prudence and recoverability of 90 percent (or $196 million) of deferred power supply costs incurred by the Company through December 31, 2001. Additionally, the WUTC order provides for one-fifth of the existing 25 percent surcharge be applied to offset the Company’s general operating costs and the remainder will continue to be applied against the deferred power cost balance. The WUTC also approved a 6.2 percent (or $14.7 million in annual revenues) increase in base electric rates for Washington customers. However, the Company still needs to receive a favorable outcome in the Washington general electric case filed in December 2001 in order to continue to improve liquidity. See further description of issues related to deferred power costs in the section “Avista Utilities - Regulatory Matters.”

If Avista Utilities’ purchased power and natural gas costs continue to exceed the levels recovered from retail customers, its cash flows will continue to be negatively affected. Factors that could cause purchased power costs to continue at higher levels than planned include, but are not limited to, a return to high prices in wholesale markets and continued high volumes of energy purchased in the wholesale markets. Factors beyond the Company’s control that could result in high volumes of energy purchased include 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.

Total deferred natural gas costs were $52.7 million as of December 31, 2001. In order to recover deferred natural gas costs, Avista Utilities received approval from the WUTC and the IPUC for purchased gas cost adjustments during August 2001. Avista Utilities estimates these PGA rate changes will increase revenues by $24.6 million for approximately one year. Based on current PGAs in place and current natural gas prices, Avista Utilities expects that the deferred natural gas cost balance will be fully recovered by December 2002.

The Company was not able to obtain conventional financing for the Coyote Springs 2 project due to lenders’ concerns with regards to the level of deferred power costs and the corresponding effect on cash flows. As a result, the Company sold 50 percent of the Coyote Springs 2 project to Mirant. As of December 31, 2001, the Company had an investment of $92.5 million in the Coyote Springs 2 project and the total cost of the plant is expected to be $190 million.

Capital Resources

The Company has incurred significant indebtedness to support capital expenditures, to fund electric and natural gas costs that were in excess of the amount recovered currently through rates and to maintain working capital. As of December 31, 2001, the Company had total debt outstanding of $1,252.6 million. In addition, the Company needs to finance capital expenditures and obtain additional working capital from time to time. The cash requirements to service the total amount of indebtedness, both short-term and long-term, could reduce the amount of cash flow available to fund working capital, future acquisitions, deferred power and natural gas costs, dividends, other corporate requirements and capital expenditures.

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The Company 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. External financings and cash provided by operating activities remain the Company’s primary source of funds for operating needs, dividends and capital expenditures. In 2002 and subsequent years, the Company expects cash flows from operations to improve primarily from the recovery of deferred power and natural gas costs. This should allow the Company to reduce total debt outstanding. Capital expenditures are financed on an interim basis with short-term borrowings.

Avista Corp. has a committed line of credit of $220 million that expires on May 29, 2002. As of December 31, 2001, $55 million was borrowed under this committed line of credit. As of February 28, 2002, $25 million was borrowed under this committed line of credit. Under this committed line of credit, the Company may have up to $50 million in letters of credit outstanding. As of December 31, 2001 there were $13.9 million of letters of credit outstanding. As of February 28, 2002, there were $9.4 million of letters of credit outstanding.

The committed line of credit agreement contains customary covenants and default provisions, including covenants not to permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be, at the end of any fiscal quarter, greater than 60 percent. As of December 31, 2001, the ratio was in compliance with this covenant at 59.4 percent. The committed line of credit also has a covenant requiring the ratio of “consolidated cash flow” to “consolidated fixed charges” of Avista Corp. or Avista Utilities for any four-fiscal quarter period ending at any fiscal quarter end to be less than certain specified ratios. In August 2001, the Company determined that it would not be in compliance with the fixed charge coverage covenant for the period ending September 30, 2001 or for any subsequent period through the termination date of the agreement. Accordingly, in September 2001, Avista Corp. requested, and obtained, a waiver of this covenant through the termination date of the agreement. As a result of this waiver, the failure to comply with this covenant does not constitute an event of default under the agreement. Additionally, Avista Corp. secured the committed line of credit with first mortgage bonds in connection with this waiver.

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 virtually impossible 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 part of its ongoing cash management practices and operations, Avista Corp. may, at any time, have short-term notes receivable and payable with Avista Capital. In turn, Avista Capital may also have short-term notes receivable and payable with its subsidiaries. As of December 31, 2001, Avista Corp. had short-term notes receivable of $180.1 million from Avista Capital of which $128.8 million of the receivables represents loans to Avista Power, primarily for the Coyote Springs 2 project.

In February 2002, the Company repurchased $25 million of Medium-Term Notes scheduled to mature in September 2003 at a premium of $1.2 million. As of December 31, 2001, the Company had remaining authorization to issue up to $317.0 million of Unsecured Medium-Term Notes.

The Mortgage and Deed of Trust securing the Company’s First Mortgage Bonds contains limitations on the amount of First Mortgage Bonds which may be issued based on, among other things, a 70 percent debt-to-collateral ratio and a 2/1 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, 2001, the Company could issue $146.7 million of additional First Mortgage Bonds under the most restrictive of these 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, 2001, approximately $217.4 million of additional preferred stock could be issued at an assumed divided rate of 6.95 percent with a maturity date later than June 1, 2008.

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 under this registration statement. The Company is currently considering issuing convertible preferred stock instead of common stock due to changes in market conditions and the decline in the price of the Company’s common stock. If market conditions warrant, the Company currently plans to issue equity securities during late 2002.

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Off-Balance Sheet Arrangements

WWP Receivables Corp. (WWPRC) is a wholly owned, bankruptcy-remote subsidiary of the Company formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. WWPRC and the Company have an agreement whereby WWPRC can sell without recourse, on a revolving basis, up to $90.0 million of those receivables. The current agreement expires in May 2002. WWPRC 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, 2001 and 2000, $75.0 million and $80.0 million, respectively, in receivables were sold pursuant to the agreement. As of February 28, 2002, $90.0 million of receivables were sold.

WP Funding LP is an entity that was formed for the purpose of acquiring the Company’s natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT). WP Funding LP purchased the Rathdrum CT from the Company with funds provided by unrelated investors of which 97 percent represented debt. The Company operates and leases the Rathdrum CT from WP Funding LP and makes lease payments currently at $4.5 million per year. The total amount of debt outstanding that is not included on the Company’s balance sheet is $54.5 million as of December 31, 2001. The lease term expires in February 2020; however, the current debt matures in October 2005 and will need to be refinanced at that time. The FASB is currently discussing several issues relating to the identification of and accounting for special-purpose entities such as WP Funding LP. A current proposal by the FASB could require the Company to begin consolidating WP Funding LP in 2003.

Total Company Capitalization

The Company’s total common equity decreased $4.2 million during 2001 to $720.1 million as of December 31, 2001 primarily due to dividends offset by net income and the issuance of common stock through stock compensation plans, the employee 401(k) plan and the Dividend Reinvestment Plan. The Company’s consolidated capital structure, including the current portion of long-term debt and short-term borrowings as of December 31, 2001, was 59.4 percent debt, 6.4 percent preferred securities and 34.2 percent common equity, compared to 52.1 percent debt, 7.5 percent preferred securities and 40.4 percent common equity as of December 31, 2000. It is the Company’s plan to target a capital structure of 50 percent debt and 50 percent preferred and common equity. The Company plans to achieve this capital structure by reducing total debt as well as the issuance of preferred or common stock and net earnings.

Credit Ratings

Two credit rating agencies lowered the Company’s credit ratings in October 2001 and a third downgraded the Company’s credit ratings in December 2001. The downgrades resulted 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 on reasonable terms. The following table summarizes the Company’s current credit ratings:

                           
      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
  Negative   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.

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Avista Utilities Operations

During the 2002-2003 period, utility capital expenditures are expected to be $175 million and long-term debt maturities and preferred stock sinking fund requirements are expected to be $209 million. During this period, internally generated funds and external financings are expected to be sufficient to fund the Company’s capital expenditures, maturing long-term debt and preferred stock sinking fund requirements. Sources of funds would include, but are not necessarily limited to, recovery of deferred power and natural gas costs, other positive operating cash flow, sales of certain assets, additional long-term debt, leasing or issuance of equity securities. Cash dividends from the Avista Capital subsidiaries will also provide funds. 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.

See Notes 6, 13, 14, 15, 16, 17, 18, 19 and 20 of Notes to Consolidated Financial Statements for additional details related to financing activities.

Energy Trading and Marketing Operations

Avista Capital’s total investment in this line of business was $330.5 million as of December 31, 2001. Avista Energy funds its ongoing operations with a combination of internally generated cash and a bank line of credit.

As of December 31, 2001 Avista Energy and its subsidiary, Avista Energy Canada, Ltd., as co-borrowers, had a credit agreement with a group of commercial lenders in the aggregate amount of $155 million expiring June 28, 2002. Subsequent to December 31, 2001, the amount of the credit agreement was reduced to $113.4 million. This credit agreement may be terminated by the banks at any time and all extensions of credit under the agreement are payable upon demand, in either case at the lenders’ sole discretion. This agreement also provides, on an uncommitted basis, for the issuance of letters of credit to secure contractual obligations to counterparties. This facility is guaranteed by Avista Capital and secured by substantially all of 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 million. As of December 31, 2001, there were no cash advances (demand notes payable) outstanding and letters of credit outstanding under the facility totaled approximately $39.6 million.

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 which the co-borrowers may incur. In addition, the agreement contains certain restricted payment provisions generally prohibiting distributions.

Avista Capital, in the course of business, may provide guarantees to other parties with whom Avista Energy may be doing business. Avista Capital’s investment in Avista Energy totaled $301.6 million as of December 31, 2001.

Periodically, Avista Capital loans funds to Avista Energy to support its short-term cash and collateral needs. These loans are subordinate to any obligations of Avista Energy to the banks under the credit agreements. As of December 31, 2001 there were no loans between Avista Capital and Avista Energy outstanding.

Avista Energy manages collateral requirements with counterparties by providing letters of credit, providing guarantees from Avista Capital and offsetting transactions with counterparties. In addition to the letters of credit and other items included above, cash deposited with counterparties totaled $1.5 million as of December 31, 2001, and is included in the consolidated balance sheet in prepayments and other current assets. Avista Energy held cash deposits from other parties in the amount of $15.7 million as of December 31, 2001, and such amounts are subject to refund if conditions warrant because of continuing portfolio value fluctuations with those parties.

As of December 31, 2001, Avista Energy had $159.6 million in cash. Covenants in Avista Energy’s credit agreement restrict the amount of cash dividends that can be distributed to Avista Capital and ultimately Avista Corp.

Capital expenditures for the Energy Trading and Marketing companies were $225.8 million for the 1999-2001 period, primarily due to Avista Power’s investment in the Coyote Springs 2 project as well as the purchase of turbines during 2001. During the fourth quarter of 2001, Avista Power received $53.6 million in proceeds from the sale of 50 percent of the Coyote Springs 2 project and $22.7 million in partial payments for the sale of three turbines. Capital expenditures are expected to be $2.0 million in this line of business during the 2002-2003 period.

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Information and Technology Operations

Capital expenditures for the Information and Technology line of business were $16.7 million for the 1999-2001 period. The 2002-2003 capital expenditures are expected to be $14.0 million. Avista Advantage and Avista Labs expect to support these capital requirements through a combination of funding from Avista Corp. and third party equity investment. Two venture capital firms made minority interest investments totaling $3.4 million in Avista Advantage during the fourth quarter of 2000. At December 31, 2001, the Information and Technology companies had $0.2 million in cash and cash equivalents and $1.3 million in debt outstanding.

Other Operations

Capital expenditures for these companies were $11.8 million for the 1999-2001 period. The 2002-2003 capital expenditures are expected to be $7.0 million. As of December 31, 2001, this line of business had $1.0 million in cash and cash equivalents and temporary investments, with $21.1 million in debt outstanding. In October 2001, Avista Capital issued a $20 million promissory note collateralized by certain receivables. The note has a balloon payment of $18.8 million due in October 2002. As of December 31, 2001, there was $19.8 million outstanding under the promissory note.

Contractual Obligations

The following table provides a summary of the Company’s future contractual obligations as of December 31, 2001 (dollars in millions):

                                                   
      2002   2003   2004   2005   2006   Thereafter
     
 
 
 
 
 
Avista Utilities:
                                               
 
Long-term debt maturities
  $     $ 205     $ 30     $ 30     $ 38     $ 875  
 
Short-term debt (1)
    130                                
 
Preferred stock redemptions
    2       2       2       2       2       27  
 
Preferred trust securities
                                  100  
 
Energy purchase contracts (2)
    374       357       308       162       141       1,412  
 
Operating lease obligations
    13       12       10       7       7       76  
Avista Capital (consolidated):
                                               
 
Long-term debt maturities
    2                                
 
Short-term debt
    20                                
 
Energy purchase contracts (3)
    1,573       533       293       163       149       403  
 
Operating lease obligations
    5       4       4       2       1       2  
 
Capital lease obligations
    1       1                          
 
   
     
     
     
     
     
 
Total cash requirements
  $ 2,120     $ 1,114     $ 647     $ 366     $ 338     $ 2,895  
 
   
     
     
     
     
     
 

(1)   Represents a $220 million ($55 million outstanding at December 31, 2001) line of credit and a $90 million ($75 million outstanding at December 31, 2001) accounts receivable financing facility, both expiring in May 2002.
(2)   All of the energy purchase contracts were entered 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.
(3)   Represents Avista Energy’s contractual commitments to purchase physical energy commodities in future periods. Avista Energy also has sales commitments related to energy commodities in future periods. Financial transactions, which could possibly change the cash flow associated with these transactions, have been excluded because it is not possible to identify those financial transactions entered into to economically hedge purchase commitments. Avista Energy uses a portfolio type of hedging or trading strategy.

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Other Commercial Commitments

The following table summarizes the Company’s other commercial commitments outstanding as of December 31, 2001 (dollars in millions):

                 
    Commitment   Commitment
    Outstanding   Expiration
   
 
Letters of credit (1)
  $ 54       2002  
Guarantees (2)
  $ 92        

(1)   Represents the $155 million credit agreement at Avista Energy and the $50 million available for letters of credit under Avista Corp.’s $220 million line of credit. As of December 31, 2001, letters of credit totaled $39.6 million at Avista Energy and $13.9 million at Avista Corp. and primarily relate to energy purchase contracts.
(2)   The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was approximately $1.2 billion as of December 31, 2001. At any point in time, Avista Capital is only liable for the outstanding portion of the guarantee, which was $91.6 million as of December 31, 2001. Most guarantees do not have set expiration dates; however, either party may terminate the guarantee at any time with minimal written notice.

As of December 31, 2001, Avista Corp. did not have any commitments outstanding with equity triggers.

Additional Financial Data

As of December 31, 2001, the total long-term debt of the Company and its consolidated subsidiaries, as shown in the Company’s consolidated financial statements, was $1,175.7 million. Of such amount, $863.8 million represents long-term unsecured and unsubordinated indebtedness of the Company, and $313.5 million represents secured indebtedness of the Company. The unamortized debt discount was $2.5 million. The subsidiaries had long-term debt of $1.0 million. Consolidated long-term debt does not include the Company’s subordinated indebtedness held by the issuers of Company-obligated preferred trust securities. An additional $55 million of the Company’s short-term debt outstanding under or backed by the $220 committed line of credit is secured indebtedness.

Future Outlook

Business Strategy

Avista Utilities seeks to maintain a strong, low-cost and efficient electric and natural gas utility business focused on providing reliable, high quality service to its customers. The utility business is expected to grow modestly, consistent with historical trends. Expansion will primarily result from economic growth in its service territory. It is Avista Utilities’ strategy to own or control a sufficient amount of resources to meet its retail and wholesale electric requirements on an average annual basis. During 2000, Avista Energy scaled back its operations regionally to work primarily within the WSCC and has focused on reducing the size and the risk associated with its energy trading and marketing activities. Avista Energy’s marketing efforts are expected to be driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WSCC, as well as its relationship-focused approach to its customers. During 2001, the Company decided that Avista Power would no longer pursue the development of additional non-regulated generation plants. The Company intends to find equity partners to assist in financing the continued growth of the Information and Technology businesses, Avista Advantage and Avista Labs. The Company plans to dispose or phase out of assets and operations that are not related to its energy operations.

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 sources of power may compete for sales to existing Avista Utilities customers, including new market entrants as a result of deregulation. Competition for available electric resources has become more critical to utilities as surplus power resources were absorbed by load growth. Avista Utilities’ natural gas distribution operations compete with other energy sources but 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.

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The Avista Capital subsidiaries, particularly the Information and Technology companies, 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 legislative and governmental regulations, the price and supply of purchased power, fuel and natural gas, recovery of purchased power and purchased natural gas costs, weather conditions, availability of generation facilities, competition, technology and availability of funding.

As described under “Avista Corp. Lines of Business,” hydroelectric conditions in 2001 were significantly below normal, leading to greater than normal reliance on purchased power. The earnings impact of these factors is mitigated by regulatory mechanisms that are intended to defer increased costs for recovery in future periods. In order to recover deferred power costs, the WUTC approved a temporary 25 percent electric rate surcharge to Washington customers in September 2001 and the IPUC approved a total of a 19.4 percent PCA surcharge to Idaho customers in October 2001. In December 2001, the Company filed a general rate case with the WUTC. In March 2002, the WUTC issued an order approving the prudence and recoverability of 90 percent (or $196 million) of deferred power supply costs incurred by the Company during the period from July 1, 2000 through December 31, 2001. Avista Utilities is not able to fully predict how the combination of energy resources, energy loads, prices, rate recovery and other factors will ultimately drive deferred costs and the timing of recovery of these costs in future periods. Current estimates and projections by the Company indicate that deferred power costs would be recovered by 2007. See further information at “Avista Utilities — Regulatory Matters.”

Challenges facing Avista Utilities’ electric operations include, among other things, the ability to recover deferred power supply costs and the timing of such recovery, changes in the availability of and volatility in the prices of power and fuel, generating unit availability, legislative and governmental regulations, and weather conditions. Avista Utilities believes it faces minimal risk for stranded utility assets resulting from deregulation, due to its relatively low-cost generation portfolio and because of the slower and more cautious approach to regulatory changes in Washington and Idaho. In a deregulated environment, however, evolving technologies that provide alternate energy supplies could affect the market price of power, and certain generating assets could have capital and operating costs above the prevailing market prices.

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. 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 based on the levels of existing reserves and potential 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 electric space and water heating 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, conservation and the timing for recovery of increased commodity costs. Avista Utilities’ natural gas business also faces the potential for large 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. Avista Utilities has long-term transportation contracts with seven of its largest industrial customers, which reduces the risks of these customers by-passing the system in the foreseeable future.

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 new risks resulting from the recent imposition of market controls by federal and state agencies. The FERC is conducting separate proceedings related to market controls within California and within the Pacific Northwest that include proposals by certain parties to retroactively impose price caps. 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

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prior periods. Avista Energy and Avista Utilities have joined other parties in vigorously opposing these proposals. If retroactive price caps were imposed, Avista Energy could develop offsetting claims.

In connection with matching loads and resources, 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. As discussed above, Avista Utilities may also be exposed to refunds for wholesale power sales depending on the outcome of the FERC’s retroactive price cap proceeding for the Pacific Northwest but would also have the opportunity to establish offsetting claims.

Commodity Price Risk    Both Avista Utilities and Avista Energy are subject to energy commodity price risk. Historically, the price of power in wholesale markets was affected primarily by production costs and by other factors including 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 thermal generating units. Any combination of these factors that resulted in a shortage of energy generally caused the market price of power to move upward. Now, however, market prices appear to be affected by other factors as well. These factors include the gradual decline of excess generating capacity in the WSCC and the effects of the restructuring of the electric utility business at the state and federal levels and the deregulation of wholesale energy markets. As discussed above and in the section “Western Power Market Issues” the FERC imposed a price mitigation plan in the western United States in June 2001.

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, price movements may be correlated to 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) are also correlated to price movements. 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.

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 not only the risk that a counterparty may default due to circumstances relating directly to it, but also 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. However, despite mitigation efforts, defaults by counterparties periodically occur. Avista Energy experienced payment receipt defaults from certain parties impacted by the California energy crisis. Avista Energy and Avista Corp. (through the Avista Utilities division) have engaged in physical and financial transactions with Enron and certain of its affiliates and experienced disruptions to forward contract commitments as a result of Enron’s December 2001 bankruptcy. See “Enron Exposure” for more information.

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

Other Operating Risks. In addition to commodity price risk, Avista Utilities’ commodity positions are subject to operational and event risks including, among others, increases in load demand, transmission or transport disruptions, fuel quality specifications and forced outages at generating plants. Avista Utilities also has exposure to weather conditions and natural disasters that can cause physical damage to property, requiring immediate repairs to restore utility service.

Interest Rate Risk. The Company is subject to the risk of fluctuating interest rates in the normal course of business. The fair value of the Company’s cash and short-term investment portfolio and the fair value of notes payable as of

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December 31, 2001 approximated carrying value. Given the short-term nature of these instruments, market risk, as measured by the change in fair value resulting from a hypothetical change in interest rates, is immaterial.

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. A portion of the Company’s capitalization consisted of floating rate Pollution Control Bonds, with the interest rate adjusted periodically prior to January 2002. In January 2002, the interest rate on the bonds was fixed for a period of seven years. The interest rate on $40 million of Company-Obligated Mandatorily Redeemable Preferred Trust Securities — Series B adjusts quarterly, reflecting current market conditions. As of December 31, 2001, a hypothetical 15 percent change in interest rates would result in an immaterial change in the Company’s cash flows related to the increased interest expense associated with these floating rate securities.

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.

Foreign Currency Risk. The Company has investments in Canadian companies through Avista Energy Canada, Ltd. and 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 in 2001 and is not expected to change materially in the near future.

Risk Management

Risk Policies and Oversight. Avista Utilities and Avista Energy use a variety of techniques to manage risks. The Company has risk management oversight for these risks for each area of the Company’s energy-related business. The Company has a comprehensive Risk Management Committee, separate from the units that create such risk exposure and overseen by the Audit Committee of the Company’s Board of Directors, to monitor compliance with the Company’s risk management policies and procedures. Avista Utilities and Avista Energy have policies and procedures to manage the risks, both quantitative and qualitative, inherent in their businesses. 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, and other factors may result in losses in earnings, cash flows and/or fair values.

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 help match 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 in the 24-month forward planning horizon. Any imbalance is required to remain within limits, or management action or decisions are triggered to address larger imbalance situations. Volume limits for forward periods are based on monthly and 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 may only be available to approximate Avista Utilities’ desired transaction size and shape. Therefore, open imbalance positions exist at any given time.

Avista Energy measures the risk in its power and natural gas portfolio daily utilizing a Value-at-Risk (VAR) model, monitoring its risk in comparison to established thresholds. VAR measures the worst expected loss over a given time interval under normal market conditions at a given confidence level. 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.

The VAR computations are based on an historical simulation, that utilizes price movements over a specified period to simulate forward price curves in the energy markets to estimate the 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.

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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 written and embedded physical options in the trading portfolio.

As of December 31, 2001, Avista Energy’s estimated potential one-day unfavorable impact on gross margin was $0.4 million, as measured by VAR, related to its commodity trading and marketing business, compared to $4.0 million as of December 31, 2000. The average daily VAR for 2001 was $1.2 million, compared to $1.6 million in 2000. Avista Energy was outside of its one-day VAR limits a total of two times during 2001. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits. Market risks associated with derivative commodity instruments held for purposes other than trading were not material as of December 31, 2001.

For forward transactions that settle beyond the immediate 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 near-term markets.

Economic and Load Growth

Avista Utilities expects economic growth to continue in its eastern Washington and northern Idaho service area. Avista Utilities, along with others in the service area, is continuing its efforts to facilitate expansion of existing businesses and attract new businesses to the Inland Northwest. Although agriculture, mining and lumber were the primary industries for many years, today health care, education, electronic and other manufacturing, tourism and the service sectors have become important industries that operate in Avista Utilities’ service area. Avista Utilities also 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 3.0 percent annually for the next five years, primarily due to increases in both population and the number of businesses in its service territory. The number of electric customers is expected to increase and the average annual usage by residential customers is expected to remain steady.

Avista Utilities anticipates natural gas load growth, including transportation volumes, in its Washington and Idaho service area to average between 1.5 and 2.0 percent annually for the next five years. The Oregon and South Lake Tahoe, California service areas are anticipated to average between 2.0 and 3.0 percent growth annually during that same period. The anticipated natural gas load growth is primarily due to expected conversions from electric space and water heating to natural gas, and increases in both population and the number of businesses in its service territory.

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 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.

Environmental 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 the Cabinet Gorge and Noxon Rapids hydroelectric projects 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. A collaborative bull trout recovery program with the U.S.

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Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana is underway on the lower Clark Fork River. The FERC license establishes a plan for bull trout restoration.

The Company continues to study the issue of high dissolved gas levels downstream of Cabinet Gorge during spill periods, as agreed to in the Settlement Agreement for relicensing Cabinet Gorge. To date, intensive biological studies in the lower Clark Fork River and Lake Pend Oreille documented minimal biological effects of high dissolved gas levels on free ranging fish. Under the terms of the Settlement Agreement, the Company will develop an abatement and/or mitigation strategy in 2002.

See “Note 24 of Notes to Consolidated Financial Statements” for additional information.

Other

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

Safe Harbor for Forward-Looking Statements

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. 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. Such risks and uncertainties include, among others:

     the outcome of the general electric rate case filed in the state of Washington on December 3, 2001
 
     changes in the utility regulatory environment in the states in which the Company operates and the western United States
 
     the impact of regulatory and legislative decisions including FERC price controls and including possible retroactive price caps and resulting refunds
 
     the availability and prices of purchased energy, volatility and illiquidity in wholesale energy markets
 
     wholesale and retail competition (including but not limited to electric retail wheeling and transmission costs)
 
     future streamflow conditions and the impact on the availability of hydroelectric resources
 
     changes in future demand, either due to weather conditions or customer growth
 
     failure to deliver on the part of any parties from which the Company purchases capacity or energy
 
     the Company’s ability to obtain financing through debt and/or equity issuance
 
     the outcome of the proposed Montana Hydroelectric Security Act Initiative (See Note 24 of Notes to Consolidated Financial Statements)

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, but 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, and 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.

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AVISTA CORPORATION

Avista Utilities’ Operations -

In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for Avista Utilities’ operations to differ materially from those discussed in forward-looking statements include continuing legislative developments; governmental policies and regulatory actions with respect to allowed rates of return, financings, or industry and rate structures; weather conditions; outages of any generating facilities; availability of economic supplies of power and natural gas; competition in present or future natural gas distribution or transmission competition (including but not limited to prices of alternative fuels and system deliverability costs); recovery of purchased power and purchased gas costs; the ability to make profitable sales of any surplus electric capacity or energy in wholesale markets; present or prospective generation, operations and construction of plant facilities; and acquisition and disposal of assets or facilities.

Energy Trading and Marketing Operations -

In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the Energy Trading and Marketing operations to differ materially from those discussed in forward-looking statements include further industry restructuring evolving from federal and/or state legislation; federal and state regulatory and legislative actions; demand for and availability of energy throughout the country; wholesale competition; availability of economic supplies of power and natural gas; margins on purchased power; changes in market factors; the formation of additional alliances or entities; the availability of economically feasible generating projects; and the availability of funding for new generating assets.

Information and Technology, and Other Operations -

Certain additional important factors which could cause actual results or outcomes for the remaining subsidiaries’ operations to differ materially from those discussed in forward-looking statements include competition from other companies and other technologies; obsolescence of technologies; the inability to reduce costs of the technologies down to economic levels; the inability to obtain new customers and loss of significant customers or suppliers; reliability of customer orders; business acquisitions; disposal of assets; the availability of funding from other sources; research and development findings; and the availability of economic expansion or development opportunities.

Factors Common to All Operations -

The business and profitability of the Company are also influenced by, among other things, economic risks; changes in and compliance with environmental and safety laws and policies; weather conditions; population growth rates and demographic patterns; market demand for energy from plants or facilities; changes in tax rates or policies; unanticipated project delays or changes in project costs; unanticipated changes in operating expenses or capital expenditures; labor negotiation or disputes; changes in credit ratings or capital market conditions; inflation rates; inability of the various counterparties to meet their obligations with respect to the Company’s financial instruments; changes in accounting principles and/or the application of such principles to the Company; changes in technology; changes in economic, business or political conditions, including the continuing impact on the economy of the September 11, 2001 terrorist attacks; and outcomes of legal proceedings.

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations: Future Outlook: Business Risk and Risk Management.”

Item 8. Financial Statements and Supplementary Data

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

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

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INDEPENDENT AUDITORS’ REPORT

Avista Corporation
Spokane, Washington

We have audited the accompanying consolidated balance sheets and statements of capitalization of Avista Corporation and subsidiaries (the Company) as of December 31, 2001 and 2000, and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows, which include the schedule of information by business segments, for each of the three years in the period ended December 31, 2001. 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, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Seattle, Washington
February 8, 2002
(March 4, 2002, as to Note 1)

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CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

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

                             
        2001   2000   1999
       
 
 
OPERATING REVENUES
  $ 6,009,847     $ 7,905,577     $ 7,902,399  
 
   
     
     
 
OPERATING EXPENSES:
                       
 
Resource costs
    5,464,530       7,293,520       7,391,277  
 
Operations and maintenance
    125,656       129,708       187,853  
 
Administrative and general
    119,216       134,912       123,996  
 
Depreciation and amortization
    71,981       65,936       67,873  
 
Taxes other than income taxes
    59,172       54,608       53,085  
 
Restructuring and exit costs
          9,805       42,922  
 
   
     
     
 
   
Total operating expenses
    5,840,555       7,688,489       7,867,006  
 
   
     
     
 
INCOME FROM OPERATIONS
    169,292       217,088       35,393  
 
   
     
     
 
OTHER INCOME (EXPENSE):
                       
 
Interest expense
    (106,480 )     (68,255 )     (64,747 )
 
Capitalized interest
    10,498       3,359       1,001  
 
   
     
     
 
   
Net interest expense
    (95,982 )     (64,896 )     (63,746 )
 
Other income — net
    20,681       25,861       73,912  
 
   
     
     
 
   
Total other income (expense)-net
    (75,301 )     (39,035 )     10,166  
 
   
     
     
 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    93,991       178,053       45,559  
INCOME TAXES
    34,386       76,998       16,897  
 
   
     
     
 
INCOME FROM CONTINUING OPERATIONS
    59,605       101,055       28,662  
 
   
     
     
 
DISCONTINUED OPERATIONS:
                       
 
Loss from operations
    (21,130 )     (15,367 )     (4,324 )
 
Asset impairment charges
    (58,417 )            
 
Minority interest
    4,319       2,454       1,536  
 
Income tax benefit
    27,779       3,537       157  
 
   
     
     
 
LOSS FROM DISCONTINUED OPERATIONS
    (47,449 )     (9,376 )     (2,631 )
 
   
     
     
 
NET INCOME
    12,156       91,679       26,031  
DEDUCT-Preferred stock dividend requirements
    2,432       23,735       21,392  
 
   
     
     
 
INCOME AVAILABLE FOR COMMON STOCK
  $ 9,724     $ 67,944     $ 4,639  
 
   
     
     
 
Weighted-average common shares outstanding (thousands), Basic
    47,417       45,690       38,213  
EARNINGS PER COMMON SHARE, BASIC (Note 21):
                       
 
Earnings per common share from continuing operations
  $ 1.21     $ 1.69     $ 0.19  
 
Loss per common share from discontinued operations
    (1.00 )     (0.20 )     (0.07 )
 
   
     
     
 
   
Total earnings per common share, basic
  $ 0.21     $ 1.49     $ 0.12  
 
   
     
     
 
EARNINGS PER COMMON SHARE, DILUTED (Note 21):
                       
 
Earnings per common share from continuing operations
  $ 1.20     $ 1.67     $ 0.19  
 
Loss per common share from discontinued operations
    (1.00 )     (0.20 )     (0.07 )
 
   
     
     
 
   
Total earnings per common share, diluted
  $ 0.20     $ 1.47     $ 0.12  
 
   
     
     
 
Dividends paid per common share
  $ 0.48     $ 0.48     $ 0.48  
NET INCOME
  $ 12,156     $ 91,679     $ 26,031  
 
   
     
     
 
OTHER COMPREHENSIVE INCOME (LOSS):
                       
 
Foreign currency translation adjustment
    (221 )     (82 )     376  
 
Unfunded accumulated benefit obligation — net of tax
    (740 )            
 
Unrealized investments gains (losses) — net of tax
    1,585       (475 )     (201 )
 
   
     
     
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
    624       (557 )     175  
 
   
     
     
 
COMPREHENSIVE INCOME
  $ 12,780     $ 91,122     $ 26,206  
 
   
     
     
 

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

                       
          2001   2000
         
 
ASSETS:
               
CURRENT ASSETS:
               
 
Cash and cash equivalents
  $ 171,221     $ 197,238  
 
Temporary investments
    1,872       1,058  
 
Accounts and notes receivable-less allowances of $50,211 and $14,404, respectively
    388,083       859,149  
 
Energy commodity assets
    477,037       7,956,229  
 
Materials and supplies, fuel stock and natural gas stored
    21,776       20,923  
 
Taxes receivable
    32,348       13,157  
 
Prepayments and other current assets
    19,364       53,613  
 
Assets held for sale from discontinued operations
    21,316       50,665  
 
   
     
 
   
Total current assets
    1,133,017       9,152,032  
 
   
     
 
NET UTILITY PROPERTY:
               
 
Utility plant in service
    2,277,779       2,205,230  
 
Construction work in progress
    54,964       33,535  
 
   
     
 
   
Total
    2,332,743       2,238,765  
 
Less: Accumulated depreciation and amortization
    767,101       720,453  
 
   
     
 
   
Total net utility property
    1,565,642       1,518,312  
 
   
     
 
OTHER PROPERTY AND INVESTMENTS:
               
 
Investment in exchange power-net
    43,314       46,981  
 
Non-utility properties and investments-net
    230,800       172,275  
 
Non-current energy commodity assets
    383,497       1,367,107  
 
Other property and investments-net
    13,620       21,885  
 
   
     
 
   
Total other property and investments
    671,231       1,608,248  
 
   
     
 
DEFERRED CHARGES:
               
 
Regulatory assets for deferred income tax
    149,033       156,692  
 
Other regulatory assets
    192,760       23,935  
 
Utility energy commodity derivative assets
    1,889        
 
Power and natural gas deferrals
    265,063       75,648  
 
Unamortized debt expense
    41,222       27,874  
 
Other deferred charges
    17,366       14,340  
 
   
     
 
   
Total deferred charges
    667,333       298,489  
 
   
     
 
     
TOTAL ASSETS
  $ 4,037,223     $ 12,577,081  
 
   
     
 
LIABILITIES AND CAPITALIZATION:
               
CURRENT LIABILITIES:
               
 
Accounts payable
  $ 367,899     $ 886,268  
 
Energy commodity liabilities
    373,837       7,834,007  
 
Current portion of long-term debt
    1,827       89,454  
 
Short-term borrowings
    75,099       163,160  
 
Interest accrued
    18,583       16,585  
 
Other current liabilities
    84,587       143,623  
 
Liabilities of discontinued operations
    6,642       5,763  
 
   
     
 
   
Total current liabilities
    928,474       9,138,860  
 
   
     
 
NON-CURRENT LIABILITIES AND DEFERRED CREDITS:
               
 
Non-current liabilities
    46,601       38,975  
 
Deferred revenue
    35,824       46,002  
 
Non-current energy commodity liabilities
    299,980       1,272,374  
 
Utility energy commodity derivative liabilities
    159,418        
 
Deferred income taxes
    517,428       446,310  
 
Other deferred credits
    18,720       95,530  
 
   
     
 
   
Total non-current liabilities and deferred credits
    1,077,971       1,899,191  
 
   
     
 
CAPITALIZATION (See Consolidated Statements of Capitalization)
    2,030,778       1,539,030  
 
   
     
 
COMMITMENTS AND CONTINGENCIES (Notes 12, 15 and 24)
               
     
TOTAL LIABILITIES AND CAPITALIZATION
  $ 4,037,223     $ 12,577,081  
 
   
     
 

The Accompanying Notes are an Integral Part of These Statements

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CONSOLIDATED STATEMENTS OF CAPITALIZATION

Avista Corporation
As of December 31
Dollars in thousands

                       
          2001   2000
         
 
LONG-TERM DEBT:
               
 
First Mortgage Bonds:
               
   
Secured Medium-Term Notes:
               
     
Series A - 6.25% to 7.90% due 2003 through 2023
  $ 104,500     $ 129,500  
     
Series B - 6.50% to 7.89% due 2005 through 2010
    59,000       74,000  
 
   
     
 
     
Total secured medium-term notes
    163,500       203,500  
   
First Mortgage Bonds - 7.75% due 2007
    150,000        
 
   
     
 
     
Total first mortgage bonds
    313,500       203,500  
 
   
     
 
 
Unsecured Pollution Control Bonds:
               
   
Floating Rate, Colstrip 1999A, due 2032
    66,700       66,700  
   
Floating Rate, Colstrip 1999B, due 2034
    17,000       17,000  
   
6% Series due 2023
    4,100       4,100  
 
   
     
 
     
Total unsecured pollution control bonds
    87,800       87,800  
 
   
     
 
 
Unsecured Senior Notes:
               
   
9.75% due 2008
    400,000        
 
   
     
 
 
Unsecured Medium-Term Notes:
               
   
Series A - 7.94% to 8.99% due 2003 through 2007
    13,000       13,000  
   
Series B - 6.75% to 8.23% due 2003 through 2023
    79,000       89,000  
   
Series C - 5.99% to 8.02% due 2007 through 2028
    109,000       109,000  
   
Series D - 8.625% due 2003
    175,000       175,000  
 
   
     
 
     
Total unsecured medium-term notes
    376,000       386,000  
 
   
     
 
 
Other long-term debt
    962       2,619  
 
   
     
 
 
Unamortized debt discount
    (2,547 )     (113 )
 
   
     
 
   
Total long-term debt
    1,175,715       679,806  
 
   
     
 
COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES:
               
   
7.875%, Series A, due 2037
    60,000       60,000  
   
Floating Rate, Series B, due 2037
    40,000       40,000  
 
   
     
 
     
Total company-obligated mandatorily redeemable preferred trust securities
    100,000       100,000  
 
   
     
 
PREFERRED STOCK-CUMULATIVE:
               
 
10,000,000 shares authorized:
               
 
Subject to mandatory redemption:
               
 
   
     
 
   
$6.95 Series K; 350,000 shares outstanding ($100 stated value)
    35,000       35,000  
 
   
     
 
COMMON EQUITY:
               
 
Common stock, no par value; 200,000,000 shares authorized; 47,632,678 and 47,208,689 shares outstanding
    617,737       610,741  
 
Note receivable from employee stock ownership plan
    (5,679 )     (7,040 )
 
Capital stock expense and other paid in capital
    (11,924 )     (11,696 )
 
Accumulated other comprehensive income (loss)
    (99 )     (723 )
 
Retained earnings
    120,028       132,942  
 
   
     
 
   
Total common equity
    720,063       724,224  
 
   
     
 
TOTAL CAPITALIZATION
  $ 2,030,778     $ 1,539,030  
 
   
     
 

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

                               
          2001   2000   1999
         
 
 
CONTINUING OPERATING ACTIVITIES:
                       
 
Net income
  $ 12,156     $ 91,679     $ 26,031  
 
Loss from discontinued operations
    47,449       9,376       2,631  
 
Non-cash items included in net income:
                       
   
Depreciation and amortization
    71,981       65,936       67,873  
   
Provision for deferred income taxes
    79,141       79,274       (1,085 )
   
Power and natural gas cost deferrals including interest, net of amortizations
    (248,386 )     (67,299 )     (14,906 )
   
Loss (gain) on sale of property and subsidiary investments-net
    299       (16,506 )     (57,860 )
   
Impairment of non-operating assets
    8,225             33,622  
   
Energy commodity assets and liabilities
    10,636       (172,918 )     (9,841 )
   
Other-net
    15,129       19,843       (25,425 )
   
Changes in working capital components:
                       
     
Sale of customer accounts receivable-net
    (5,000 )     35,000       20,000  
     
Receivables and prepaid expense
    453,309       (375,558 )     (139,878 )
     
Materials and supplies, fuel stock and natural gas stored
    (853 )     7,037       890  
     
Accounts payable and other accrued liabilities
    (503,475 )     442,984       162,775  
     
Other
    (33,940 )     (34,758 )     47,180  
 
   
     
     
 
NET CASH PROVIDED BY (USED IN) CONTINUING OPERATING ACTIVITIES
    (93,329 )     84,090       112,007  
 
   
     
     
 
CONTINUING INVESTING ACTIVITIES:
                       
 
Utility property construction expenditures (excluding AFUDC)
    (119,905 )     (98,680 )     (87,160 )
 
Other capital expenditures
    (162,279 )     (73,515 )     (17,573 )
 
Changes in other non-current balance sheet items-net
    11,163       3,403       (7,636 )
 
Proceeds from property sales and sale of subsidiary investments
    75,953       105,228       148,851  
 
Assets acquired and investments in subsidiaries
    (23,321 )     (1,496 )     (48,931 )
 
   
     
     
 
NET CASH USED IN CONTINUING INVESTING ACTIVITIES
    (218,389 )     (65,060 )     (12,449 )
 
   
     
     
 
CONTINUING FINANCING ACTIVITIES:
                       
 
Increase (decrease) in short-term borrowings
    (88,061 )     42,126       110,522  
 
Redemption of preferred trust securities
          (10,000 )      
 
Proceeds from issuance of long-term debt
    550,457       224,000       115,749  
 
Redemption and maturity of long-term debt
    (140,208 )     (54,283 )     (211,514 )
 
Redemption of preferred stock
                (5,918 )
 
Issuance of common stock, net of repurchases
    8,267       2,625       (81,985 )
 
Cash dividends paid
    (25,110 )     (28,304 )     (39,757 )
 
Other-net
    (2,434 )     (850 )     (4,634 )
 
   
     
     
 
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES
    302,911       175,314       (117,537 )
 
   
     
     
 
NET CASH USED IN DISCONTINUED OPERATIONS
    (17,210 )     (37,094 )     (14,830 )
NET INCREASE (DECREASE) IN CASH & CASH EQUIVALENTS
    (26,017 )     157,250       (32,809 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    197,238       39,988       72,797  
 
   
     
     
 
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 171,221     $ 197,238     $ 39,988  
 
   
     
     
 
SUPPLEMENTAL CASH FLOW INFORMATION:
                       
 
Cash paid (received) during the period:
                       
   
Interest
  $ 98,571     $ 61,774     $ 63,207  
   
Income taxes
    (38,817 )     31,404       42,891  
 
Non-cash financing and investing activities:
                       
   
Accounts receivable from sale of non-operating assets
    22,665              
   
Intangibles acquired through issuance of subsidiary stock
    1,114              
   
Series L preferred stock converted to common stock
          271,286        
   
Property purchased under capitalized leases
    469             2,557  
   
Unrealized investment gains (losses)
    2,437       (475 )     (201 )
   
Sale of property through issuance of note receivable
    2,548       3,500        

The Accompanying Notes are an Integral Part of These Statements.

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

                                                 
    Preferred Stock   Convertible Preferred Stock,                
    Series K   Series L   Common Stock
   
 
 
    Shares   Amount   Shares   Amount   Shares   Amount
   
 
 
 
 
 
Balance as of December 31, 1998
    350,000     $ 35,000       1,540,460     $ 269,227       40,453,729     $ 381,401  
 
   
     
     
     
     
     
 
Net income
                                               
Repurchase of common stock and common stock equivalents
                    (32,250 )     (5,918 )     (4,788,900 )     (62,393 )
Stock issued under compensatory plans
                                    (16,590 )     (277 )
Repayments of note receivable
                                               
Foreign currency translation adjustment
                                               
Unrealized investment loss-net
                                               
Cash dividends paid (common stock)
                                               
Cash dividends paid (preferred stock)
                                               
ESOP dividend tax savings
                                               
 
   
     
     
     
     
     
 
Balance as of December 31, 1999
    350,000     $ 35,000       1,508,210     $ 263,309       35,648,239     $ 318,731  
 
   
     
     
     
     
     
 
Net income
                                               
Conversion of convertible preferred stock into common stock
                    (1,508,210 )     (263,309 )     11,410,047       289,118  
Repurchase of common stock
                                    (45,975 )     (1,488 )
Stock issued under compensatory plans
                                    70,742       1,192  
Employee Investment Plan (401-K)
                                    97,478       2,614  
Dividend Reinvestment Plan
                                    28,158       574  
Repayments of note receivable
                                               
Foreign currency translation adjustment
                                               
Unrealized investment loss-net
                                               
Cash dividends paid (common stock)
                                               
Cash dividends paid (preferred stock)
                                               
ESOP dividend tax savings
                                               
 
   
     
     
     
     
     
 
Balance as of December 31, 2000
    350,000     $ 35,000           $       47,208,689     $ 610,741  
 
   
     
     
     
     
     
 
Net income
                                               
Stock issued under compensatory plans
                                    91,128       1,763  
Employee Investment Plan (401-K)
                                    172,681       2,823  
Dividend Reinvestment Plan
                                    160,180       2,410  
Repayments of note receivable
                                               
Foreign currency translation adjustment
                                               
Unfunded accumulated benefit obligation
                                               
Unrealized investment gain-net
                                               
Cash dividends paid (common stock)
                                               
Cash dividends paid (preferred stock)
                                               
ESOP dividend tax savings
                                               
 
   
     
     
     
     
     
 
Balance as of December 31, 2001
    350,000     $ 35,000           $       47,632,678     $ 617,737  
 
   
     
     
     
     
     
 

[Additional columns below]

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

                                         
    Note                                
    Receivable   Capital   Accumulated                
    from Employee   Stock Expense   Other                
    Stock   and Other   Comprehensive   Retained        
    Ownership Plan   Paid-in Capital   Income (Loss)   Earnings   Total
   
 
 
 
 
Balance as of December 31, 1998
  $ (9,295 )   $ (4,176 )   $ (341 )   $ 120,445     $ 792,261  
 
   
     
     
     
     
 
Net income
                            26,031       26,031  
Repurchase of common stock and common stock equivalents
            (171 )             (19,315 )     (87,797 )
Stock issued under compensatory plans
                            (84 )     (361 )
Repayments of note receivable
    1,055                               1,055  
Foreign currency translation adjustment
                    376               376  
Unrealized investment loss-net
                    (201 )             (201 )
Cash dividends paid (common stock)
                            (18,301 )     (18,301 )
Cash dividends paid (preferred stock)
                            (21,402 )     (21,402 )
ESOP dividend tax savings
                            147       147  
 
   
     
     
     
     
 
Balance as of December 31, 1999
  $ (8,240 )   $ (4,347 )   $ (166 )   $ 87,521     $ 691,808  
 
   
     
     
     
     
 
Net income
                            91,679       91,679  
Conversion of convertible preferred stock into common stock
            (8,009 )             (17,868 )     (68 )
Repurchase of common stock
                            (419 )     (1,907 )
Stock issued under compensatory plans
            689               101       1,982  
Employee Investment Plan (401-K)
            (29 )                     2,585  
Dividend Reinvestment Plan
                                    574  
Repayments of note receivable
    1,200                               1,200  
Foreign currency translation adjustment
                    (82 )             (82 )
Unrealized investment loss-net
                    (475 )             (475 )
Cash dividends paid (common stock)
                            (22,616 )     (22,616 )
Cash dividends paid (preferred stock)
                            (5,600 )     (5,600 )
ESOP dividend tax savings
                            144       144  
 
   
     
     
     
     
 
Balance as of December 31, 2000
  $ (7,040 )   $ (11,696 )   $ (723 )   $ 132,942     $ 759,224  
 
   
     
     
     
     
 
Net income
                            12,156       12,156  
Stock issued under compensatory plans
            (228 )             (14 )     1,521  
Employee Investment Plan (401-K)
                                    2,823  
Dividend Reinvestment Plan
                                    2,410  
Repayments of note receivable
    1,361                               1,361  
Foreign currency translation adjustment
                    (221 )             (221 )
Unfunded accumulated benefit obligation
                    (740 )             (740 )
Unrealized investment gain-net
                    1,585               1,585  
Cash dividends paid (common stock)
                            (22,765 )     (22,765 )
Cash dividends paid (preferred stock)
                            (2,432 )     (2,432 )
ESOP dividend tax savings
                            141       141  
 
   
     
     
     
     
 
Balance as of December 31, 2001
  $ (5,679 )   $ (11,924 )   $ (99 )   $ 120,028     $ 755,063  
 
   
     
     
     
     
 

The Accompanying Notes are an Integral Part of These Statements.

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

                             
        2001   2000   1999
       
 
 
OPERATING REVENUES:
                       
 
Avista Utilities
  $ 1,230,847     $ 1,512,101     $ 1,115,647  
 
Energy Trading and Marketing
    5,000,955       6,531,551       6,695,671  
 
Information and Technology
    13,815       5,732       2,266  
 
Other
    16,385       32,937       122,303  
 
Intersegment eliminations
    (252,155 )     (176,744 )     (33,488 )
 
   
     
     
 
   
Total operating revenues
  $ 6,009,847     $ 7,905,577     $ 7,902,399  
 
   
     
     
 
RESOURCE COSTS:
                       
 
Avista Utilities:
                       
   
Power purchased
  $ 708,321     $ 1,072,475     $ 543,436  
   
Natural gas purchased for resale
    220,692       169,924       116,553  
   
Fuel for generation
    81,949       69,077       46,368  
   
Power and natural gas deferrals, net of amortizations
    (210,540 )     (70,250 )     (14,616 )
   
Other
    49,574       5,233       19,411  
 
Energy Trading and Marketing:
                       
   
Cost of sales
    4,866,689       6,223,805       6,713,613  
 
Intersegment eliminations
    (252,155 )     (176,744 )     (33,488 )
 
   
     
     
 
   
Total resource costs (excluding non-energy businesses)
  $ 5,464,530     $ 7,293,520     $ 7,391,277  
 
   
     
     
 
GROSS MARGINS:
                       
 
Avista Utilities
  $ 380,851     $ 265,642     $ 404,495  
 
Energy Trading and Marketing
    134,266       307,746       (17,942 )
 
   
     
     
 
   
Total gross margins
  $ 515,117     $ 573,388     $ 386,553  
 
   
     
     
 
OPERATIONS AND MAINTENANCE EXPENSES:
                       
 
Avista Utilities
  $ 97,831     $ 95,117     $ 90,390  
 
Energy Trading and Marketing
          249       370  
 
Information and Technology
    12,607       6,611       6,310  
 
Other
    15,218       27,731       90,783  
 
   
     
     
 
   
Total operations and maintenance expenses
  $ 125,656     $ 129,708     $ 187,853  
 
   
     
     
 
ADMINISTRATIVE AND GENERAL EXPENSES:
                       
 
Avista Utilities
  $ 53,416     $ 62,111     $ 66,362  
 
Energy Trading and Marketing
    33,494       41,256       31,732  
 
Information and Technology
    23,918       22,329       3,389  
 
Other
    8,388       9,216       22,513  
 
   
     
     
 
   
Total administrative and general expenses
  $ 119,216     $ 134,912     $ 123,996  
 
   
     
     
 
DEPRECIATION AND AMORTIZATION EXPENSES:
                       
 
Avista Utilities
  $ 61,383     $ 57,479     $ 55,545  
 
Energy Trading and Marketing
    2,188       2,466       3,692  
 
Information and Technology
    5,403       2,169       1,175  
 
Other
    3,007       3,822       7,461  
 
   
     
     
 
   
Total depreciation and amortization expenses
  $ 71,981     $ 65,936     $ 67,873  
 
   
     
     
 
INCOME FROM OPERATIONS (PRE-TAX):
                       
 
Avista Utilities
  $ 114,927     $ 3,177     $ 142,567  
 
Energy Trading and Marketing
    94,669       250,196       (97,785 )
 
Information and Technology
    (29,872 )     (26,424 )     (8,966 )
 
Other
    (10,432 )     (9,861 )     (423 )
 
   
     
     
 
   
Total income from operations
  $ 169,292     $ 217,088     $ 35,393  
 
   
     
     
 

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        2001   2000   1999
       
 
 
INCOME FROM CONTINUING OPERATIONS:
                       
 
Avista Utilities
  $ 24,164     $ (38,781 )   $ 59,573  
 
Energy Trading and Marketing
    70,087       161,753       (60,739 )
 
Information and Technology
    (19,384 )     (19,032 )     (5,989 )
 
Other
    (15,262 )     (2,885 )     35,817  
 
   
     
     
 
   
Total income from continuing operations
  $ 59,605     $ 101,055     $ 28,662  
 
   
     
     
 
ASSETS:
                       
 
Avista Utilities
  $ 2,396,317     $ 2,143,791     $ 1,976,716  
 
Energy Trading and Marketing
    1,506,185       10,271,834       1,595,470  
 
Information and Technology
    26,891       14,429       6,312  
 
Other
    86,514       96,362       114,929  
 
Discontinued Operations
    21,316       50,665       20,067  
 
   
     
     
 
   
Total assets
  $ 4,037,223     $ 12,577,081     $ 3,713,494  
 
   
     
     
 
CAPITAL EXPENDITURES (excluding AFUDC):
                       
 
Avista Utilities
  $ 119,905     $ 98,680     $ 87,160  
 
Energy Trading and Marketing
    157,020       65,095       3,676  
 
Information and Technology
    4,644       8,409       3,628  
 
Other
    615       976       10,171  
 
   
     
     
 
   
Total capital expenditures
  $ 282,184     $ 173,160     $ 104,635  
 
   
     
     
 

The Accompanying Notes are an Integral Part of These Statements

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AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corporation (Avista Corp. or the Company) is an energy company involved in the generation, transmission and distribution of energy as well as other energy-related businesses. The utility portion of the Company, doing business as Avista Utilities, an operating division of Avista Corp. and not a separate entity, provides electric and natural gas service to customers in four western states and is subject to state and federal regulation. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies engaged in the other non-regulated lines of business.

The Company’s operations are exposed to risks, including legislative and governmental regulations, the price and supply of purchased power, fuel and natural gas, recovery of purchased power and purchased natural gas costs, weather conditions, availability of generation facilities, competition, technology and availability of funding. In addition, the energy business exposes the Company to the financial, liquidity, credit and commodity price risks associated with wholesale purchases and sales.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries. The accompanying financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (See Note 8).

Use of Estimates

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material impact on the consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein.

System of Accounts

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

Regulation

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

Business Segments

Financial information for each of the Company’s lines of business is reported in the “Schedule of Information by Business Segments.” Such information is an integral part of these consolidated financial statements. The business segment presentation reflects the basis currently used by the Company’s management to analyze performance and determine the allocation of resources. Avista Utilities’ business is managed based on the total regulated utility operation. The Energy Trading and Marketing line of business operations primarily includes non-regulated electricity and natural gas marketing and trading activities including derivative commodity instruments such as futures, options, swaps and other contractual arrangements. The Information and Technology line of business operations includes utility internet billing services and fuel cell technology. The Other line of business encompasses other investments and non-energy operations of various subsidiaries as well as the operations of Avista Capital on a parent company only basis. The Company is in the process of divesting Avista Communications, its telecommunications business, which is reported as a discontinued operation.

Operating Revenues

Operating revenues are recorded on the basis of service rendered, which includes estimated unbilled revenue. Avista Energy follows the mark-to-market method of accounting for energy contracts entered into for trading and price risk management purposes. Avista Energy recognizes revenue based on the change in the market value of outstanding derivative commodity sales contracts, net of future servicing costs and reserves, in addition to revenue related to physical and financial contracts that have settled.

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AVISTA CORPORATION

Intersegment Eliminations

Intersegment eliminations represent the transactions between Avista Utilities and Avista Energy for energy commodities and services.

Research and Development Expenses

Company-sponsored research and development expenses related to present and future products are expensed as incurred. The majority of the Company’s research and development expenses are related to the Information and Technology line of business. Research and development expenses totaled $8.4 million, $8.1 million and $3.3 million in 2001, 2000 and 1999, respectively.

Advertising Costs

The Company expenses advertising costs as incurred. Advertising expenses totaled $1.8 million, $1.2 million and $0.6 million in 2001, 2000 and 1999, respectively.

Taxes other than income taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers are recorded as both revenue and expense and totaled $26.3 million, $23.5 million and $21.3 million in 2001, 2000 and 1999, respectively.

Other Income-Net

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

                           
      2001   2000   1999
     
 
 
Interest income
  $ 32,044     $ 11,824     $ 3,615  
Net gain on subsidiary transactions
    2,997       770       57,531  
Gain (loss) on property dispositions
    (8,338 )     20,278       4,071  
Minority interest
    217       694       466  
Other — net
    (6,239 )     (7,705 )     8,229  
 
   
     
     
 
 
Total
  $ 20,681     $ 25,861     $ 73,912  
 
   
     
     
 

Income Taxes

The Company and its eligible subsidiaries file consolidated federal income tax returns. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Company’s federal income tax returns were examined with all issues resolved, and all payments made, through the 1998 return.

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

Stock-Based Compensation

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

Comprehensive Income

The Company’s comprehensive income is comprised of net income, foreign currency translation adjustments, unfunded accumulated benefit obligation and unrealized gains and losses on investments available-for-sale.

Foreign Currency Translation Adjustment

The assets and liabilities of Avista Energy Canada, Ltd. are denominated in Canadian dollars and translated to United States dollars at exchange rates in effect on the balance sheet date. Revenues and expenses are translated using an average exchange rate. Translation adjustments resulting from this process are reflected as a component of

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AVISTA CORPORATION

other comprehensive income in the Consolidated Statements of Comprehensive Income.

Earnings Per Common Share

Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share is calculated by dividing income available for common stock by diluted weighted average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options and convertible stock. See Note 21 for earnings per common share calculations.

Cash and Cash Equivalents

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

Temporary Investments

Temporary investments consist of marketable equity securities classified as “available for sale.” The unrealized gain on temporary investments totaled $1.4 million as of December 31, 2001 compared to an unrealized loss of $0.7 million as of December 31, 2000, respectively, net of taxes,