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CONFORMED

 
 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

     þ       ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
                          ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004 OR

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

TO                     

Commission file number 1-3701

AVISTA CORPORATION


(Exact name of Registrant as specified in its charter)
     
Washington   91-0462470
     
(State or other jurisdiction of
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

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       þ       No       o

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. [ ]

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act):

Yes       þ       No       o

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 $876,757,918 based on the last reported sale price thereof on the consolidated tape on June 30, 2004.

As of February 28, 2005, 48,473,059 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 12, 2005
  Part III, Items 10, 11,
12, 13 and 14
 
 

 


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INDEX

         
Item   Page  
No.   No.  
  iv   
       
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    49  

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Item   Page  
No.   No.  
    49  
    50  
    50  
    50  
    50  
    51  
    51  
    52  
    53  
    53  
    54  
    54  
    57  
    59  
    59  
    59  
    59  
    59  
    60-61  
Financial Statements
    62-70  
    62  
    63  
    64-65  
    66-67  
    68  
    69-70  
    71  
    *  
    111  
    113  
       
    113  
    114  
    114  
    115  
    115  
       
    116  
    117  
    118  
    119  
 EXHIBIT 4(d)-1
 EXHIBIT 4(d)-2
 EXHIBIT 10(o)-6
 EXHIBIT 10(o)-7
 EXHIBIT 10(o)-13
 EXHIBIT 10(o)-14
 EXHIBIT 12
 EXHIBIT 21
 EXHIBIT 31.1
 EXHIBIT 31.2
 EXHIBIT 32


* = not an applicable item in the 2004 calendar year for the Company

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

     
Acronym/Term   Meaning
aMW
 
- Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time
 
   
AFUDC
 
- Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period
 
   
AM&D
 
- Advanced Manufacturing and Development
 
   
APB
 
- Accounting Principles Board
 
   
Avista Advantage
 
- Avista Advantage, Inc., provider of utility bill processing, payment and information services to multi-site customers in North America, subsidiary of Avista Capital
 
   
Avista Capital
 
- Parent company to the Company’s non-utility businesses
 
   
Avista Corp.
 
- Avista Corporation, the Company
 
   
Avista Energy
 
- Avista Energy, Inc., an electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital
 
   
Avista Utilities
 
- operating division of Avista Corp. comprising the regulated utility operations
 
   
BPA
 
- Bonneville Power Administration
 
   
Capacity
 
- the rate at which a particular generating source produces energy, measured in KW or MW
 
   
Cabinet Gorge
 
- the Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho
 
   
Colstrip
 
- the coal-fired Colstrip Generating Plant in southeastern Montana
 
   
Coyote Springs 2
 
- the natural gas-fired Coyote Springs 2 Generating Plant located near Boardman, Oregon
 
   
CPUC
 
- California Public Utilities Commission
 
   
CT
 
- Combustion turbine
 
   
Dekatherm
 
- Unit of measurement for natural gas; a dekatherm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy)
 
   
DOE
 
- the State of Washington’s Department of Ecology
 
   
Energy
 
- the amount of electricity produced or consumed over a period of time, measured in KWH or MWH
 
   
EITF
 
- Emerging Issues Task Force
 
   
ERM
 
- the Energy Recovery Mechanism in the State of Washington
 
   
FASB
 
- Financial Accounting Standards Board
 
   

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Acronym/Term   Meaning
FIN
  - Financial Accounting Standards Board Interpretation
 
   
FERC
  - Federal Energy Regulatory Commission
 
   
IPUC
  - Idaho Public Utilities Commission
 
   
Jackson Prairie
 
- Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington
 
   
kV
  - Kilovolt - a measure of capacity on transmission lines
 
   
Lancaster Project
 
- the natural gas-fired combined cycle combustion turbine plant located in northern Idaho that is 49 percent owned by Avista Power
 
   
KW, KWH
  - Kilowatt or 1000 watts, kilowatt-hour or 1000 watt hours
 
   
MW, MWH
  - Megawatt or 1000 KW, megawatt-hour or 1000 KWH
 
   
NERC
  - North American Electricity Reliability Council
 
   
Noxon Rapids
  - the Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana
 
   
OASIS
  - Open Access Same-Time Information System
 
   
OPUC
  - Oregon Public Utility Commission
 
   
PCA
  - the Power Cost Adjustment mechanism in the State of Idaho
 
   
PLP
  - Potentially liable party
 
   
PUD
  - Public Utility District
 
   
PURPA
  - the Public Utility Regulatory Policies Act of 1978
 
   
RTO
  - Regional Transmission Organization
 
   
SFAS
  - Statement of Financial Accounting Standards
 
   
Spokane River Project
 
- the five hydroelectric plants operating under one FERC license on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls)
 
   
Therm
 
- Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
 
   
VAR
 
- Value-at-Risk, measures the expected risk of portfolio loss under hypothetical adverse price movements, over a given time interval within a given confidence level
 
   
Watt
 
- Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt
 
   
WECC
  - Western Electricity Coordinating Council
 
   
WUTC
  - Washington Utilities and Transportation Commission
 
   

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PART I

This Annual Report on Form 10-K contains forward-looking statements, which 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 - 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,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “projects,” “predicts,” and similar expressions. Such statements are subject to a variety of risks and uncertainties and other factors, most of which are beyond the control of Avista Corporation and many of which could have a significant impact on Avista Corporation’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Available Information

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

Item 1. Business

Company Overview

Avista Corp., incorporated in the State of Washington in 1889, is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. As of December 31, 2004, the Company employed approximately 1,485 people in its utility operations and approximately 485 people in its subsidiary businesses. The Company’s corporate headquarters are in Spokane, Washington, center of the Inland Northwest geographic region. Agriculture, mining and lumber were the primary industries in the Inland Northwest for many years; today health care, education, finance, electronic and other manufacturing, tourism and the service sectors are growing in importance.

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

The Company has four business segments – Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. As of December 31, 2004, the Company had common equity investments of $495.8 million and $257.4 million in Avista Utilities and Avista Capital, respectively.

Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations that started in 1889. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Utilities also engages in wholesale purchases and sales of electric capacity and energy. Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Avista Utilities expects to continue its modest, yet steady, combined growth of electric and natural gas customers of 2 to 3 percent per year, primarily from economic and population growth in its service territory. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, the Company has entered into an agreement to sell its natural gas distribution properties in South Lake Tahoe, California (see “Note 27 of the Notes to Consolidated Financial Statements”). Avista Utilities has operational strategies to have available resources sufficient to meet its energy requirements under a range of operating and weather conditions. In January 2005, the Company completed its acquisition of Mirant Oregon, LLC’s 50 percent ownership interest in the approximately 280 megawatt (MW) combined cycle natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) (see “Note 28 of the Notes to Consolidated Financial Statements”).

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The Energy Marketing and Resource Management business segment is comprised of Avista Energy, Inc. (Avista Energy) and Avista Power, LLC (Avista Power). Avista Energy, which commenced operations in 1997, is an electricity and natural gas marketing, trading and resource management business, operating primarily in the Western Electricity Coordinating Council (WECC) geographical area, which is comprised of eleven Western states and the provinces of British Columbia and Alberta, Canada. Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 250 industrial and commercial customers that represent over 400 sites in British Columbia, Canada. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. Avista Power is an investor in certain generation assets, primarily its 49 percent interest in a 270 MW natural gas-fired combined cycle combustion turbine plant in northern Idaho (Lancaster Project), and owns a turbine and related equipment.

Avista Advantage, Inc. (Avista Advantage), which commenced operations in 1998, is a provider of utility bill processing, payment and information services to multi-site customers throughout North America. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling services. Avista Advantage remains focused on increasing revenues, controlling operating expenses, continuously enhancing client satisfaction and developing complementary value-added services.

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

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

(BUSINESS SEGMENT CHART)

¨ - - denotes a business entity; Avista Advantage is also a business segment.

¡ - - denotes business segment .

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

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Avista Utilities

General

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

Avista Utilities provides electric distribution and transmission as well as natural gas distribution services in a 26,000 square mile area in eastern Washington and northern Idaho with a population of approximately 855,000. It also provides natural gas distribution service in a combined 4,000 square mile area in northeast and southwest Oregon and the South Lake Tahoe region of California with a population of approximately 500,000. At the end of 2004, Avista Utilities supplied retail electric service to a total of 331,000 customers and retail natural gas service to a total of 305,000 customers across its entire service territory. The Company has entered into an agreement to sell its natural gas distribution properties in the South Lake Tahoe region of California (see “Note 27 of the Notes to Consolidated Financial Statements”), an area with a population of approximately 35,000 and total customers of 18,750 at the end of 2004. See “Item 2. Properties” for further information with respect to Avista Utilities’ electric distribution and transmission assets, as well as natural gas distribution assets.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Economic and Load Growth” for information with respect to projected load growth in Avista Utilities service territory.

The Company has experienced a decrease in usage per customer for both electric and natural gas retail customers exclusive of weather related factors. This appears to be due to the conservation efforts of individual customers, improved efficiency of appliances, improved energy efficiency in new construction, as well as customer response to rate increases.

Electric Operations

In addition to providing electric distribution and transmission services, Avista Utilities generates electricity from facilities that it owns or controls. It is Avista Utilities’ strategy to own or to have contracts that provide a sufficient amount of electric resources to meet its retail and wholesale energy requirements under a range of operating conditions. See “Item 2. Properties” for further information with respect to generation properties. In addition to company-owned resources, Avista Utilities has a number of long-term power purchase and exchange contracts that increase its available resources.

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

Participants in the wholesale market include other utilities, federal power marketing agencies, energy marketing and trading companies, and independent power producers. The electric wholesale market continues to change with respect to the number and types of market participants involved, volume of buying and selling activity, price volatility, market liquidity, regulatory initiatives and challenges in regulatory and legal arenas, and credit strength by market participants. See “Industry Restructuring” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Competition, – Business Risk and – Risk Management” for more information.

Avista Utilities’ generation assets are interconnected through its transmission system and are operated on a coordinated basis to achieve a high level of load-serving capability and reliability. Avista Utilities offers transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Avista Utilities’ Open Access Same-Time Information System (OASIS) is part of the Joint Transmission Services Information Network that covers much of the

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United States. Transmission revenues, which are included in Other Electric Revenues at “Avista Utilities Operating Statistics – Electric Operations,” totaled $13.9 million, $11.6 million and $11.5 million for 2004, 2003 and 2002, respectively. Avista Utilities is currently in the process of expanding and enhancing its 230 kV transmission system, which Avista Utilities expects to be completed by the end of 2007.

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

Electric Requirements

The peak electric load requirement for 2004 was 2,220 MW (including retail native load of 1,766 MW, long-term wholesale obligations of 129 MW and short-term wholesale obligations of 325 MW). This peak occurred on January 5, 2004 at which time the maximum resource capacity available from Avista Utilities was 2,552 MW. The maximum resource capacity included 1,497 MW of company-owned electric generation, 167 MW of long-term hydroelectric contracts, 352 MW of other long-term wholesale purchases and 536 MW of short-term wholesale purchases. Variations in energy usage by Avista Utilities’ customers occur from year to year, from season to season and hour to hour as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both purchases and sales of energy for annual, quarterly, monthly, daily and hourly periods in order to meet electric requirements and to prudently manage and optimize available resources.

Electric Resources

General Avista Utilities has a diverse electric resource mix of hydroelectric projects, thermal generating facilities, and power purchases and exchanges. At the end of 2004, Avista Utilities’ owned facilities had a total net capability of approximately 1,663 MW, of which 59 percent was hydroelectric and 41 percent was thermal. The addition of the remaining interest in Coyote Springs 2 changes Avista Utilities net capability mix to 54 percent hydroelectric and 46 percent thermal. See “Avista Utilities Operating Statistics – Electric Operations” for energy resource statistics.

Hydroelectric Resources Avista Utilities owns and operates six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. See “Item 2. Properties” for detailed information with respect to hydroelectric facilities. Hydroelectric generation is Avista Utilities’ lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on its total power supply costs. Under normal streamflow and operating conditions, Avista Utilities projects that it would be able to meet approximately one-half of its total average electric requirements (both retail and long-term wholesale) with the combination of its own hydroelectric generation and long-term hydroelectric purchase contracts with certain Public Utility Districts (PUDs) in Washington state. Historically, under normal streamflow conditions, total hydroelectric resources (including resources purchased under long-term hydroelectric contracts) generate 550 average megawatts (aMW) (or 4.8 million MWhs) annually. Hydroelectric resources generated 523 aMW, 492 aMW and 553 aMW during 2004, 2003 and 2002, respectively. The streamflows to company-owned hydroelectric projects were 86 percent, 84 percent and 112 percent of normal in 2004, 2003 and 2002, respectively.

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

                         
    2004     2003     2002  
 
Noxon Rapids
    1,595       1,543       1,816  
Cabinet Gorge
    1,062       975       1,085  
Post Falls
    96       80       87  
Upper Falls
    71       67       75  
Monroe Street
    107       99       105  
Nine Mile
    135       122       126  
Long Lake
    511       465       511  
Little Falls
    212       189       205  
 
                 
Total company-owned hydroelectric generation
    3,789       3,540       4,010  
Long-term hydroelectric contracts with PUDs
    794       775       837  
 
                 
Total hydroelectric generation
    4,583       4,315       4,847  
 
                 

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Thermal Resources At the end of 2004, Avista Utilities owned a 50 percent interest in Coyote Springs 2 located near Boardman, Oregon. In January 2005, the Company acquired the remaining 50 percent ownership interest in Coyote Springs 2 from Mirant Oregon, LLC. Avista Utilities owns a 15 percent interest in a twin-unit, coal-fired generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana. Avista Utilities owns a wood-waste-fired generating facility known as the Kettle Falls Generating Station (Kettle Falls) in northeastern Washington and a two-unit natural gas-fired CT generating facility, located in northeast Spokane (Northeast CT). Avista Utilities leases and operates a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT). WP Funding LP, an entity that is included in Avista Corp.’s consolidated financial statements and included in the Avista Utilities business segment, owns the Rathdrum CT. In addition, Avista Utilities owns two small generating facilities (Boulder Park and Kettle Falls CT) that were placed into operation in 2002.

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

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

Kettle Falls’ primary fuel is wood-waste generated as a by-product and delivered by trucks 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 and spot purchases have provided, and are expected to meet, future fuel requirements for Kettle Falls.

The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used for peaking electric requirements and are also operated when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

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

                         
    2004     2003     2002  
 
Coyote Springs 2 (1)
    407       397        
Colstrip
    1,605       1,593       1,397  
Kettle Falls
    366       366       261  
Northeast CT and Rathdrum CT
    6       20       39  
Boulder Park and Kettle Falls CT
    24       22       17  
 
                 
Total thermal generation
    2,408       2,398       1,714  
 
                 


(1) The Company owned 50 percent of Coyote Springs 2 as of December 31, 2004. In January 2005, the Company acquired the remaining 50 percent ownership interest in Coyote Springs 2 from Mirant Oregon, LLC. Coyote Springs 2 was placed into service in July 2003 and experienced a transformer failure that resulted in a significant outage, which affected availability in 2004.

Purchases, Exchanges and Sales Avista Utilities purchases and sells power under various long-term contracts. Avista Utilities also enters into a significant number of short-term purchases and sales with terms of up to one year. See “Electric Operations” for additional information with respect to Avista Utilities’ use of wholesale purchases and sales as part of its resource optimization process.

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 between 2015 and 2022.

See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2004, 2003 and 2002.

Hydroelectric Relicensing

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

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expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages.

In March 2001, Avista Utilities received a 45-year operating license from the FERC for the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) and the Noxon Rapids Hydroelectric Generating Project (Noxon Rapids). The Clark Fork Settlement Agreement that was entered into during 1999 and incorporated into the FERC license preserved the projects’ economic peaking and load following operations. Also, as part of the Clark Fork Settlement Agreement, Avista Utilities initiated implementation of protection, mitigation and enhancement measures in March 1999. Measures in the agreement address issues related to fisheries, water quality, wildlife, recreation, land use, cultural resources and erosion. Previously deferred hydroelectric relicensing costs, as well as estimated levels of ongoing costs associated with implementation of the Clark Fork Settlement Agreement, were addressed by both the WUTC and IPUC and received recovery through retail rates.

See “Clark Fork Settlement Agreement” in “Note 25 of the Notes to Consolidated Financial Statements” for disclosure of dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge during periods when excess river flows must be diverted over the spillway and the Company’s mitigation plans and efforts.

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

Future Resource Needs

Avista Utilities has operational strategies to have available resources sufficient to meet its energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed over hourly, daily, monthly and annual durations, which vary widely because of the factors that influence demand. The following is a forecast of Avista Utilities’ average annual energy requirements and resources for 2005, 2006, 2007 and 2008:

Forecasted Electric Energy Requirements and Resources
(aMW)

                                 
    2005     2006     2007     2008  
 
Requirements:
                               
System load
    1,065       1,098       1,120       1,151  
Contracts for power sales
    62       60       60       60  
 
                       
Total requirements
    1,127       1,158       1,180       1,211  
 
                       
 
                               
Resources:
                               
Company-owned and contract hydro generation (1)
    461       517       517       517  
Company-owned base load thermal generation
    236       226       229       243  
Company-owned other thermal generation
    262       272       282       268  
Contracts for power purchases
    283       292       295       294  
 
                       
Total resources
    1,242       1,307       1,323       1,322  
 
                       
 
                               
Surplus resources
    115       149       143       111  
Additional available energy (2)
    146       142       145       145  
 
                       
Total surplus resources
    261       291       288       256  


(1)   Forecasts as of March 1, 2005 indicate that hydroelectric generation will be approximately 461 aMW in 2005, which is 84 percent of historical normal. This forecast may change based upon precipitation, temperatures and other variables. The forecasts for 2006, 2007 and 2008 assume normal hydroelectric generation of 517 aMW. This amount is less than the historical normal hydroelectric generation of 550 aMW, which is primarily due to changes in hydroelectric contracts.

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(2)   Additional available resources are the Northeast CT and Rathdrum CT, which are generally only used to meet electric load requirements due to either below normal hydroelectric generation or increased loads or outages at other generating facilities, and/or when operating costs are lower than short-term wholesale market prices. The combined maximum capacity of the Northeast CT and Rathdrum CT is 243 MW, with estimated available energy production as indicated for each year.

Natural Gas Operations

General Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, northeast and southwest Oregon, and the South Lake Tahoe region of California. The Company has entered into an agreement to sell its natural gas distribution properties in the South Lake Tahoe region of California (see “Note 27 of the Notes to Consolidated Financial Statements”). Natural gas commodity costs in excess of, or which fall below, the amount recovered in current retail rates are deferred and recovered or refunded as a pass-through to customers in future periods with applicable regulatory approval through adjustments to rates.

During recent years, natural gas prices have been volatile with a general upward trend. Avista Utilities’ average prices per dekatherm were $6.62, $5.50 and $4.95 in 2004, 2003 and 2002, respectively. This continued upward price trend has caused the recovery period for deferred natural gas costs to lengthen. 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 long-term market advantage over competing energy sources 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 competing space and water heating energy sources to natural gas.

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

Avista Utilities offers natural gas sales and transportation service to large natural gas customers. The majority of Avista Utilities’ large industrial customers purchase natural gas through marketers. For these customers, Avista Utilities provides transportation services for a fee to move the customers’ natural gas through Avista Utilities distribution system from the natural gas transmission pipeline delivery points to the customers’ premises. Several of Avista Utilities’ largest natural gas customers are provided natural gas transportation service under individual contracts. All individual contracts are subject to regulatory review and approval. The total volume transported on behalf of transportation customers for 2004, 2003 and 2002 was 154.4, 153.4 and 174.9 million therms, which represented approximately 31 percent, 31 percent and 34 percent of Avista Utilities’ total system deliveries, respectively.

Natural Gas Supply Avista Utilities does not have any natural gas reserves and purchases all of its natural gas in the wholesale market. Avista Utilities is connected to multiple supply basins in the western United States and western Canada and believes there will be sufficient supplies of natural gas to meet its customers’ needs. However, natural gas prices in the Pacific Northwest are increasingly affected by supply and demand factors in other regions of the United States and Canada because of growth in transcontinental pipeline capacity. Global energy markets also affect natural gas prices. Avista Utilities has capacity delivery rights on seven pipelines and owns natural gas storage facilities. Access to a diverse portfolio of natural gas resources allows Avista Utilities to make natural gas procurement decisions that benefit its natural gas customers. Approximately 25 percent of Avista Utilities’ natural gas supplies are obtained from domestic sources, with the remaining 75 percent from Canadian sources.

Starting in 1999, the Company’s energy marketing, trading and resource management subsidiary, Avista Energy, was responsible for the daily management and optimization of these resources for the requirements of customers in the states of Washington, Idaho and Oregon under an Agency Agreement with Avista Utilities. Under this relationship, Avista Utilities retained ownership of its transportation, storage and long-term contracts and Avista Energy acted as an agent to optimize these resources. In February 2004, the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. In April 2004, the WUTC approved Avista Utilities’ transition plan, which provides for the movement of these functions back into Avista Utilities to be completed by March 31, 2005. Effective April 1, 2005, the Company will also be moving these functions from Avista Energy to Avista Utilities for Idaho and Oregon natural gas customers with the expiration of the current agreements. See “Regulatory Issues — Natural Gas Benchmark Mechanism” for additional information.

Natural Gas Storage Avista Utilities owns a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 8.8 million therms, with a total working natural gas inventory of 213.6 million therms.

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The role of Jackson Prairie in providing flexible natural gas supplies is important to Avista Utilities’ natural gas operations. It enables Avista Utilities to place natural gas into storage when prices are low or to meet minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are high. Avista Energy controls a portion of the capacity at Jackson Prairie for a ten-year period ending in 2009. During 2002, a multi-year project to further increase the capacity at Jackson Prairie commenced. Avista Utilities has contracted to release a total of approximately 37 percent of its Jackson Prairie capacity to two other utilities. One of these contracts requires two-years notice for termination and one contract is renewed on a year-to-year basis.

Regulatory Issues

General 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), the California Public Utilities Commission (CPUC) and the Public Service Commission of the State of Montana (Montana Commission). Approval of the issuance of securities is not required from the CPUC and the Montana Commission. If the Company’s sale of its South Lake Tahoe natural gas distribution properties is completed as planned in 2005, the Company will no longer be subject to the jurisdiction of the 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 Jackson Prairie, licensing of hydroelectric generation resources, and for electric transmission service and wholesale electric sales.

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

Power Cost Deferrals Avista Utilities defers the recognition in the income statement of certain power supply costs that are in excess of the level currently recovered from retail customers as authorized by the WUTC and the IPUC. A portion of power supply costs are recorded as a deferred charge on the balance sheet for future review and the opportunity for recovery through retail rates. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Power Cost Deferrals and Recovery Mechanisms” and “Note 1 — Power Cost Deferrals and Recovery Mechanisms of the Notes to Consolidated Financial Statements” for detailed information on Avista Utilities power cost deferrals and recovery mechanisms in Washington and Idaho.

General Rate Cases Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – General Rate Cases” for information on general rate case activity in 2004 and 2003.

Purchased Gas Adjustment (PGA or Natural Gas Trackers) Under established regulatory practices in each respective state, Avista Utilities is allowed to adjust its natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs already included in retail rates are deferred and charged or credited to expense when regulators approve inclusion of the cost changes in rates. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Purchased Gas Adjustments” for information on natural gas rate increases to recover increased natural gas costs in 2004 and 2003.

Natural Gas Benchmark Mechanism The IPUC, WUTC and OPUC approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations with Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets have been managed by Avista Energy through an Agency Agreement. Avista Utilities has continued to manage natural gas procurement for its California operations, which the Company has entered into an agreement to sell (see “Note 27 of the Notes to Consolidated Financial Statements”).

In the first quarter of 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. In February 2004, the WUTC ordered that the

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Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. In April 2004, the WUTC approved Avista Utilities’ transition plan, which provides for the movement of these functions back into Avista Utilities to be completed by March 31, 2005. Effective April 1, 2005, the Company will also be moving these functions from Avista Energy to Avista Utilities for Idaho and Oregon natural gas customers with the expiration of the current agreements.

Residential Exchange Program The Residential Exchange Program provides access to the benefits of low-cost federal hydroelectricity to residential and small-farm customers of the region’s investor-owned utilities. The Bonneville Power Administration (BPA) administers the Residential Exchange Program in accordance with federal law. Avista Corp. has executed an agreement with the BPA in settlement of each party’s rights and obligations under the Residential Exchange Program for the period October 1, 2001 through September 30, 2011. The benefits that Avista Corp, receives under the agreement with the BPA are passed through directly to residential and small-farm customers via a credit to their monthly electric bills. The current BPA rate period began on October 1, 2001 and continues through September 30, 2006. In 2004, Avista Corp. and other investor-owned utilities entered into amended agreements to provide benefits to customers during the rate period from October 1, 2006 through September 30, 2011.

Numerous parties have filed Petitions for Review in the Ninth Circuit Court of Appeals challenging the agreements between Avista Corp. and the BPA, as well as the BPA’s agreements with other investor-owned utilities. This could possibly affect the amount of benefits paid by the BPA to Avista Corp. that are passed through to residential and small-farm customers. However, since these benefits are passed through to customers as adjustments to electric rates, which must be approved by the WUTC and the IPUC, the outcome of these Petitions for Review is not expected to have a significant effect on Avista Corp.’s financial condition or results of operations.

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) expanded the authority of the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity for the purpose of providing these services. It also created “exempt wholesale generators,” a class of independent power plant owners that are able to sell generation only at the wholesale level. This permits public utilities and other entities to participate through subsidiaries in the development of independent electric generating plants for sales to wholesale customers.

FERC orders issued in the mid-1990’s require public utilities operating under the Federal Power Act to provide access to their transmission systems to third parties and establish an OASIS to provide transmission customers with information about available transmission capacity and other information by electronic means. FERC orders also require each public utility subject to the rule to functionally separate its transmission and wholesale power merchant functions.

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

The North American Electric Reliability Council (NERC) and the WECC have undertaken initiatives to establish a series of security coordinators to oversee the reliable operation of the regional transmission system. Accordingly, Avista Utilities, in cooperation with other utilities in the Pacific Northwest, established the Pacific Northwest Security Coordinator (PNSC) in the late-1990’s, 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.

The utility industry experienced a significant blackout in August 2003, when 50 million people lost power in the northeastern United States and eastern Canadian provinces. As a result of this outage, the NERC, in conjunction with the

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FERC, conducted a comprehensive investigation of the outage and issued certain reliability related recommendations. These recommendations addressed compliance with existing national and regional standards and initiatives to prevent or mitigate future blackouts. Utilities in the western United States, including Avista Utilities, had already been following the provisions of approximately half of these NERC recommendations and Avista Utilities already complies with many of the remaining NERC recommendations.

In February 2005, the NERC Board of Trustees approved reliability standards, to become effective April 1, 2005, which have the goal of restating existing standards in a manner that is clear, unambiguous, measurable and enforceable. In February 2005, the FERC issued an order to supplement its April 2004 policy statement, which interprets the term “Good Utility Practice”, as that term is used in the Open Access Transmission Tariff, to include compliance with reliability standards developed by the NERC.

Avista Utilities believes that it has implemented appropriate operating practices and processes with respect to its transmission system, which provide for compliance with the NERC reliability standards. Avista Utilities implemented the majority of these procedures prior to the August 2003 blackout in the northeastern United States. The Company is now reviewing the NERC reliability standards issued in February 2005 for possible amendments to operating policies and practices.

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

Avista Corp. is in continuing discussions with utilities and others in the Pacific Northwest to define how such an RTO might work in the region. The Company has participated in negotiations with nine other utilities in the western United States on the possible formation of an RTO, RTO West, a non-profit organization. These utilities and other regional stakeholders have since shifted their approach to developing a regional platform that would incorporate an initial or beginning state of an RTO structure. Interim bylaws governing continuing developmental activities for this non-profit corporation, under the new name Grid West, were adopted on December 9, 2004. The next phase of the development of Grid West would be the establishment of a board of directors, which is currently planned for late-2005.

The Company and two other western utilities also discussed the formation of a for-profit Independent Transmission Company, TransConnect. In March 2005, the companies decided to no longer pursue the formation of TransConnect.

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

In September 2003, a new organization called Western Interconnection L.L.C. (WI) filed an application with the FERC for certification as an RTO to provide transmission service in the western United States. As part of its application, WI requested that FERC order each jurisdictional utility in the western United States (including Avista Corp.) to provide escrow funding to WI in the amount of $4.0 million per year. In February 2005, WI filed a notice of its intent to withdraw its application with the FERC for certification as an RTO.

Wholesale Power Market Design In April 2003, the FERC issued a White Paper presenting a revised version of proposed wholesale power market rules. The White Paper emphasizes a focus on the formation of RTOs and on ensuring that all independent transmission organizations have sound market rules. The White Paper further indicates that the implementation schedule will vary depending on regional needs and will also allow for regional differences. The White Paper reflects significant concerns raised with respect to the FERC’s initial proposal of a Standard Market Design in July 2002. The FERC’s stated goals with respect to wholesale power markets include: reliable and reasonably priced electric service for all customers; sufficient electric infrastructure; transparent markets with fair rules for all market participants; stability and regulatory certainty for customers, the electric power industry, and investors; technological innovation; and efficient use of the nation’s resources. At this time, the Company cannot predict the ultimate impact any related structural changes in the Pacific Northwest may have on its operations as well as how any such changes may impact Grid West development.

State Level 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

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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 electric rates that are among the lowest in the country. There is currently no movement toward deregulation in Washington or Idaho.

Environmental Issues

General The Company is subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which Avista Utilities has an ownership interest were designed to comply with all applicable environmental laws. Furthermore, the Company conducts periodic reviews of all its facilities and operations to respond to or to anticipate emerging environmental issues. The Company’s Board of Directors has a committee to oversee 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 facilities. Avista Utilities does, however, purchase power under long-term contracts with PUDs 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 future actions. The Company received a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids in March 2001 that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, particularly bull trout, is a principal focus of the agreement. The result is a collaborative bull trout recovery program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. See “Hydroelectric Relicensing” for further information.

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

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

Water Quality See “Clark Fork Settlement Agreement” in “Note 25 of the Notes to Consolidated Financial Statements” for disclosure of dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge during periods when excess river flows must be diverted over the spillway and the Company’s mitigation plans and efforts.

Other Environmental Issues See “Colstrip Generating Project Complaint,” “Environmental Protection Agency Administrative Compliance Order,” “Hamilton Street Bridge,” “Spokane River” and “Other Contingencies” in “Note 25 of the Notes to Consolidated Financial Statements” for additional information with respect to environmental issues.

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AVISTA UTILITIES OPERATING STATISTICS
                         
    Years Ended December 31,  
    2004     2003     2002  
ELECTRIC OPERATIONS
                       
ELECTRIC OPERATING REVENUES (Dollars in Thousands):
                       
Residential
  $ 209,518     $ 204,783     $ 196,156  
Commercial
    201,775       201,339       194,732  
Industrial
    90,288       78,276       68,096  
Public street and highway lighting
    4,847       4,770       4,683  
 
                 
Total retail revenues
    506,428       489,168       463,667  
Wholesale revenues
    62,399       73,463       64,082  
Revenues from sales of fuel
    63,990       71,456       40,937  
Other revenues
    19,264       16,835       15,455  
 
                 
Total electric operating revenues
  $ 652,081     $ 650,922     $ 584,141  
 
                 
 
                       
ELECTRIC ENERGY SALES (Thousands of MWhs):
                       
Residential
    3,343       3,298       3,203  
Commercial
    2,919       2,919       2,837  
Industrial
    2,076       1,785       1,519  
Public street and highway lighting
    25       25       25  
 
                 
Total retail energy sales
    8,363       8,027       7,584  
Wholesale energy sales
    1,472       2,075       2,216  
 
                 
Total electric energy sales
    9,835       10,102       9,800  
 
                 
 
                       
ELECTRIC ENERGY RESOURCES (Thousands of MWhs):
                       
Hydro generation (from Company facilities)
    3,789       3,540       4,010  
Thermal generation (from Company facilities)
    2,408       2,398       1,714  
Purchased power — long-term hydroelectric contracts with PUDs
    794       775       837  
Purchased power — wholesale
    3,422       3,909       3,828  
Power exchanges
    38       36       17  
 
                 
Total power resources
    10,451       10,658       10,406  
Energy losses and Company use
    (616 )     (556 )     (606 )
 
                 
Total energy resources (net of losses)
    9,835       10,102       9,800  
 
                 
 
                       
NUMBER OF ELECTRIC CUSTOMERS (Average for Period):
                       
Residential
    288,422       283,497       279,735  
Commercial
    36,728       36,279       35,910  
Industrial
    1,416       1,414       1,420  
Public street and highway lighting
    418       422       413  
 
                 
Total electric retail customers
    326,984       321,612       317,478  
Wholesale
    43       47       46  
 
                 
Total electric customers
    327,027       321,659       317,524  
 
                 
 
                       
ELECTRIC RESIDENTIAL SERVICE AVERAGES:
                       
Annual use per customer (KWh)
    11,591       11,633       11,450  
Revenue per KWh (in cents)
    6.27       6.21       6.12  
Annual revenue per customer
  $ 726.43     $ 722.35     $ 701.22  
 
                       
ELECTRIC AVERAGE HOURLY LOAD (aMW)
    1,025       984       935  
 
                 
 
                       
RESOURCE AVAILABILITY at time of system peak (MW):
                       
Total requirements (winter):
                       
Retail native load
    1,766       1,509       1,346  
Wholesale obligations
    454       417       297  
 
                 
Total requirements (winter)
    2,220       1,926       1,643  
Total resource availability (winter)
    2,552       2,557       2,213  
 
                       
Total requirements (summer):
                       
Retail native load
    1,488       1,487       1,389  
Wholesale obligations
    294       449       466  
 
                 
Total requirements (summer)
    1,782       1,936       1,855  
Total resource availability (summer)
    2,409       2,365       2,287  
COOLING DEGREE DAYS: (1)
                       
Spokane, WA
                       
Actual
    571       578       405  
30 year average
    394       394       394  
% of average
    145 %     147 %     103 %


(1)   Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures).

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AVISTA UTILITIES OPERATING STATISTICS
                         
    Years Ended December 31,  
    2004     2003     2002  
NATURAL GAS OPERATIONS
                       
NATURAL GAS OPERATING REVENUES (Dollars in Thousands):
                       
Residential
  $ 194,470     $ 166,925     $ 183,964  
Commercial
    104,754       90,523       104,974  
Industrial
    9,423       7,475       7,127  
 
                 
Total retail natural gas revenues
    308,647       264,923       296,065  
Wholesale revenues
    152       280       695  
Transportation revenues
    8,134       8,485       9,664  
Other revenues
    3,560       3,601       3,399  
 
                 
Total natural gas operating revenues
  $ 320,493     $ 277,289     $ 309,823  
 
                 
 
                       
THERMS DELIVERED (Thousands of Therms):
                       
Residential
    201,696       198,471       199,686  
Commercial
    122,852       122,115       126,220  
Industrial
    13,274       12,737       11,243  
 
                 
Total retail
    337,822       333,323       337,149  
Wholesale
    305       675       2,306  
Transportation
    154,427       153,352       174,891  
Interdepartmental and Company use
    3,030       3,124       2,145  
 
                 
Total therms delivered
    495,584       490,474       516,491  
 
                 
 
                       
SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):
                       
Purchases
    341,398       334,609       344,793  
Storage – injections
    (60 )     (74 )     (53 )
Storage – withdrawals
    52       76       60  
Natural gas for transportation
    154,427       153,352       174,891  
Interdepartmental transportation
    2,551       2,607       1,513  
Distribution system losses
    (2,784 )     (96 )     (4,713 )
 
                 
Total natural gas supply
    495,584       490,474       516,491  
 
                 
 
                       
NUMBER OF NATURAL GAS CUSTOMERS (Average for Period):
                       
Residential
    268,571       261,063       254,700  
Commercial
    31,886       31,312       30,823  
Industrial
    311       310       315  
 
                 
Total retail customers
    300,768       292,685       285,838  
Wholesale customers
    1       1       1  
Transportation customers
    81       84       88  
 
                 
Total natural gas customers
    300,850       292,770       285,927  
 
                 
 
                       
NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
                       
Washington and Idaho
                       
Annual use per customer (therms)
    796       813       841  
Revenue per therm (in cents)
    92.63       83.68       93.05  
Annual revenue per customer
  $ 737.17     $ 679.96     $ 782.16  
Oregon and California
                       
Annual use per customer (therms)
    668       663       679  
Revenue per therm (in cents)
    104.79       85.07       90.00  
Annual revenue per customer
  $ 699.85     $ 564.31     $ 610.68  
 
                       
NET SYSTEM MAXIMUM CAPABILITY (Thousands of Therms):
                       
Net system maximum demand (winter)
    3,098       2,270       2,253  
Net system maximum firm contractual capacity (winter)
    4,340       4,340       4,340  
 
                       
HEATING DEGREE DAYS: (1)
                       
Spokane, WA
                       
Actual
    6,314       6,351       6,818  
30 year average
    6,820       6,820       6,842  
% of average
    93 %     93 %     100 %
Medford, OR
                       
Actual
    3,933       4,046       4,230  
30 year average
    4,592       4,592       4,611  
% of average
    86 %     88 %     92 %


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

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Energy Marketing and Resource Management

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

Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily within the WECC. Avista Energy’s headquarters are in Spokane, Washington, and it also has an office in Vancouver, British Columbia, Canada. Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 250 industrial and commercial customers that represent over 400 sites in British Columbia, Canada. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers. Avista Energy’s earnings are primarily derived from the following activities:

•   Marketing and managing the output and availability of combustion turbines and hydroelectric assets owned by other entities.
 
•   Capturing price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process.
 
•   Purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks.
 
•   Transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations within the WECC.
 
•   Taking speculative positions on future price movements within established risk management policies.

Avista Energy trades electricity and natural gas, along with derivative commodity instruments including futures, options, swaps and other contractual arrangements. Most transactions are conducted on an “over-the-counter” basis. Avista Energy’s trading operations are affected by, among other things, volatility of prices within the electric energy and natural gas markets, the demand for and availability of energy, changing regulation of the electric and natural gas industries, the creditworthiness of counterparties and variations in liquidity in energy markets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - - Business Risk and — Risk Management” for further information.

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

                         
    2004     2003     2002  
 
Gross Physical Realized Sales Volume:
                       
Electricity (thousands of MWhs)
    32,629       41,579       40,426  
Natural gas (thousands of dekatherms)
    219,719       228,397       225,983  

In September 1999, Avista Energy began managing Avista Utilities’ natural gas storage assets, transportation contracts and natural gas purchasing operations. Under an Agency Agreement, Avista Energy served 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 continued to be owned by Avista Utilities; however, they were fully integrated operationally into Avista Energy’s portfolio. In February 2004, the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. In April 2004, the WUTC approved Avista Utilities’ transition plan, which provides for the movement of these functions back into Avista Utilities to be completed by March 31, 2005. Effective April 1, 2005, the Company will also be moving these functions from Avista Energy to Avista Utilities for Idaho and Oregon natural gas customers with the expiration of the current agreements.

Avista Energy is subject to the various risks inherent in commodity trading including, particularly, market risk, liquidity risk, commodity price risk and credit risk, as well as possible risks resulting from the imposition of market controls by federal and state regulatory agencies. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Business Risks and — Risk Management,” and “Notes 1, 2, 7 and 8 of Notes to

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Consolidated Financial Statements” for additional information regarding the market and credit risks inherent in the energy trading business, Avista Energy’s risk management policies and procedures, accounting practices, and positions held by Avista Energy as of December 31, 2004.

Avista Power

Avista Power is an investor in certain generation assets, primarily its 49 percent ownership interest in the Lancaster Project, as well as a turbine and related equipment. The Lancaster Project capacity is contracted to Avista Energy through 2026 through a power purchase agreement. The power purchase agreement gives Avista Energy the right to purchase natural gas for generation, and convert to electricity for a fixed fee. Avista Power is not seeking additional investment opportunities.

Avista Advantage

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

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

Avista Advantage has secured five patents on its two critical business systems: the Facility IQä system, which provides operational information drawn from facility bills, and the AviTrackä 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, 2004, Avista Advantage serviced 323 customers, having 141,442 billed sites throughout North America. This is an increase from 292 customers and 109,583 billed sites as of December 31, 2003. As of December 31, 2002, Avista Advantage serviced 247 customers and 98,251 billed sites. During 2004, Avista Advantage processed $7.6 billion of bills, an increase from $6.4 billion in 2003 and $4.9 billion in 2002.

Other

The Other business segment includes Avista Ventures, Pentzer, Avista Development and certain other operations of Avista Capital. Included in this business segment is AM&D doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal manufacturing of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also provides complete fabrication and turnkey assembly for arcade games, kiosks, store fixtures and displays. Other significant investments in this segment include commercial office buildings, investments in low income housing and venture capital partnerships, the remaining investment in a previous fuel cell subsidiary of the Company, and notes receivable from the sale of property and investments. Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment.

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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       265.0       261.0  
Post Falls (Spokane)
    6       14.8       18.0  
Montana:
                       
Noxon Rapids (Clark Fork)
    5       466.2       527.0  
 
                   
Total Hydroelectric
            899.2       979.7  
Thermal Generating Stations
                       
Washington:
                       
Kettle Falls
    1       50.7       50.0  
Kettle Falls CT
    1       6.9       6.9  
Northeast CT
    2       61.8       66.8  
Boulder Park
    6       24.6       24.6  
Idaho:
                       
Rathdrum CT (1)
    2       166.5       176.0  
Montana:
                       
Colstrip Units 3 and 4 (4)
    2       233.4       222.0  
Oregon:
                       
Coyote Springs 2 (5)
    1       143.5       137.1  
 
                   
Total Thermal
            687.4       683.4  
 
                   
Total Generation Properties
            1,586.6       1,663.1  
 
                   


(1)   All generation properties are owned by Avista Utilities with the exception of the Rathdrum CT, which is leased from WP Funding LP, an entity that is included in Avista Corp.’s consolidated financial statements in the Avista Utilities business segment.
 
(2)   Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.
 
(3)   Present capability is the maximum capacity of the plant without exceeding approved limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2004.
 
(4)   Jointly owned; data refers to Avista Utilities’ 15 percent interest.
 
(5)   Data refers to Avista Utilities’ 50 percent interest as of December 31, 2004. In January 2005, the Company acquired the remaining 50 percent ownership interest in Coyote Springs 2 from Mirant Oregon, LLC (see “Note 28 of the Notes to Consolidated Financial Statements”).

Electric Distribution and Transmission Plant

Avista Utilities operates approximately 17,000 miles of primary and secondary electric distribution lines. Avista Utilities has an electric transmission system of approximately 623 miles of 230 kV line and 1,537 miles of 115 kV line. Avista Utilities also owns an 11 percent interest (representing 465 MW capacity) in 495 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. The transmission and distribution system also includes numerous substations with transformers, switches, monitoring and metering devices, and other equipment related to its operation.

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The 230 kV lines are used to transmit power from Noxon Rapids and Cabinet Gorge to major load centers in Avista Utilities’ service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the BPA, PacifiCorp, NorthWestern Energy and Idaho Power Company. These interconnections serve as points of delivery for power from generating facilities outside of the Company’s distribution territory, including the Colstrip generating station, Coyote Springs 2, and to integrate Mid-Columbia hydroelectric generating facilities, as well as for the interchange of power with entities within and outside the Pacific Northwest. Avista Utilities is currently in the process of expanding and enhancing its 230 kV transmission system, which Avista Utilities expects to be completed by the end of 2007.

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 the BPA, Grant County PUD, Puget Sound Energy, the South Columbia Basin Irrigation District, Chelan County PUD, PacifiCorp and NorthWestern Energy. Both the 115 kV and 230kV interconnections with the BPA are used to exchange energy with the BPA to facilitate the General Transfer Agreement (GTA). The GTA allows the Company to serve its native load from the BPA’s transmission system and allows the BPA to serve their customers from the Company’s system.

Natural Gas Plant

Avista Utilities has natural gas distribution mains of approximately 2,660 miles in Washington, 1,550 miles in Idaho, 1,790 miles in Oregon and 230 miles in California. The natural gas distribution system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment related to its operation.

Avista Utilities owns a one-third interest in Jackson Prairie, which has a total peak day deliverability of 8.8 million therms, with a total working natural gas inventory of 213.6 million therms. Avista Utilities has contracted to release a total of approximately 37 percent of its Jackson Prairie capacity to two other utilities. One of these contracts requires two-years notice for termination and one contract is renewed on a year-to-year basis.

Item 3. Legal Proceedings

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

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

None.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Outstanding shares of common stock are listed on the New York and Pacific Stock Exchanges. As of February 28, 2005, there were approximately 15,219 registered shareholders of the Company’s no par value common stock.

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

On February 11, 2005, the Board of Directors declared a quarterly dividend of $0.135 per common share payable on March 15, 2005 to shareholders of record on February 25, 2005. This is an increase of $0.005 per common share over the previous quarterly dividend declared in November 2004 and the third such increase authorized by the Board of Directors in the last 18 months.

Covenants under the Company’s 9.75 percent Senior Notes that mature in 2008 limit the Company’s ability to increase its common stock cash dividend to no more than 5 percent over the previous quarter.

Avista Energy holds a significant portion of cash and cash equivalents reflected on the Consolidated Balance Sheet. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limiting the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. During 2004, Avista Energy paid $2.5 million in dividends to Avista Capital. In March 2005, Avista Energy paid $10.0 million in dividends to Avista Capital.

For additional information, refer to “Notes 1, 22, 23 and 24 of Notes to Consolidated Financial Statements.” For high and low stock price information, refer to “Note 29 of Notes to Consolidated Financial Statements.”

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

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Item 6. Selected Financial Data
(in thousands, except per share data and ratios)

                                         
    Years Ended December 31,  
    2004     2003     2002     2001     2000  
Operating Revenues:
                                       
Avista Utilities
  $ 972,574     $ 928,211     $ 893,964     $ 1,230,847     $ 1,512,101  
Energy Marketing and Resource Management
    275,646       307,141       222,634       403,743       546,893  
Avista Advantage
    23,444       19,839       16,911       13,151       4,971  
Other
    17,127       13,581       14,645       16,385       32,937  
Intersegment Eliminations
    (137,211 )     (145,387 )     (85,238 )     (152,375 )     (161,423 )
 
                             
Total
  $ 1,151,580     $ 1,123,385     $ 1,062,916     $ 1,511,751     $ 1,935,479  
 
                             
Income (Loss) from Operations (pre-tax):
                                       
Avista Utilities
  $ 134,073     $ 146,777     $ 149,180     $ 114,927     $ 3,177  
Energy Marketing and Resource Management
    11,681       30,078       29,211       94,669       250,196  
Avista Advantage
    1,742       (1,331 )     (6,363 )     (15,098 )     (14,482 )
Other
    (7,026 )     (3,821 )     (14,886 )     (10,432 )     (9,861 )
 
                             
Total
  $ 140,470     $ 171,703     $ 157,142     $ 184,066     $ 229,030  
 
                             
Income (Loss) from Continuing Operations:
                                       
Avista Utilities
  $ 32,467     $ 36,241     $ 36,382     $ 24,164     $ (38,781 )
Energy Marketing and Resource Management
    9,733       20,672       22,425       63,246       161,753  
Avista Advantage
    577       (1,334 )     (4,253 )     (10,748 )     (11,022 )
Other
    (7,163 )     (4,936 )     (12,380 )     (8,421 )     (2,885 )
 
                             
Total
    35,614       50,643       42,174       68,241       109,065  
Loss from discontinued operations
          (4,949 )     (6,719 )     (56,085 )     (17,386 )
 
                             
Net income before cumulative effect of accounting change
    35,614       45,694       35,455       12,156       91,679  
Cumulative effect of accounting change
    (460 )     (1,190 )     (4,148 )            
 
                             
Net income
    35,154       44,504       31,307       12,156       91,679  
Deduct — preferred stock dividend requirements (1)
          1,125       2,402       2,432       23,735  
 
                             
Income available for common stock
  $ 35,154     $ 43,379     $ 28,905     $ 9,724     $ 67,944  
 
                             
Average common shares outstanding, basic
    48,400       48,232       47,823       47,417       45,690  
Average common shares outstanding, diluted
    48,886       48,630       47,874       47,435       46,103  
Common shares outstanding at year-end
    48,472       48,344       48,044       47,633       47,209  
Earnings per Common Share:
                                       
Avista Utilities
  $ 0.67     $ 0.72     $ 0.71     $ 0.46     $ (1.37 )
Energy Marketing and Resource Management
    0.20       0.43       0.47       1.33       3.51  
Avista Advantage
    0.01       (0.03 )     (0.09 )     (0.23 )     (0.23 )
Other
    (0.15 )     (0.10 )     (0.26 )     (0.18 )     (0.06 )
 
                             
Earnings per common share from continuing operations, diluted
    0.73       1.02       0.83       1.38       1.85  
Loss per common share from discontinued operations, diluted
          (0.10 )     (0.14 )     (1.18 )     (0.38 )
 
                             
Earnings per common share before cumulative effect of accounting change, diluted
    0.73       0.92       0.69       0.20       1.47  
Cumulative effect of accounting change, diluted
    (0.01 )     (0.03 )     (0.09 )            
 
                             
Total earnings per common share, diluted
  $ 0.72     $ 0.89     $ 0.60     $ 0.20     $ 1.47  
 
                             
Total earnings per common share, basic
  $ 0.73     $ 0.90     $ 0.60     $ 0.21     $ 1.49  
Dividends paid per common share
    0.515       0.49       0.48       0.48       0.48  
Book value per common share at year-end
  $ 15.54     $ 15.54     $ 14.84     $ 15.12     $ 15.34  
Total Assets at Year-End:
                                       
Avista Utilities
  $ 2,600,357     $ 2,532,936     $ 2,369,418     $ 2,569,798     $ 2,306,221  
Energy Marketing and Resource Management
    1,002,843       1,013,213       1,349,626       1,506,185       10,271,834  
Avista Advantage
    47,318       45,621       31,733       20,288       11,063  
Other
    53,305       48,305       42,866       86,514       96,362  
Discontinued Operations
                5,900       27,919       54,031  
 
                             
Total
  $ 3,703,823     $ 3,640,075     $ 3,799,543     $ 4,210,704     $ 12,739,511  
 
                             
Long-Term Debt (not including current portion)
  $ 901,556     $ 925,012     $ 902,635     $ 1,175,715     $ 679,806  
Long-Term Debt to Affiliated Trusts (2)
    113,403       113,403                    
Company-Obligated Mandatorily Redeemable Preferred Trust Securities (2)
                100,000       100,000       100,000  
Preferred Stock Subject to Mandatory Redemption (1)
    28,000       29,750       33,250       35,000       35,000  
Common Equity
  $ 753,205     $ 751,252     $ 712,791     $ 720,063     $ 724,224  
Ratio of Earnings to Fixed Charges
    1.60       1.88       1.69       1.98       3.62  
Ratio of Earnings to Fixed Charges and Preferred Dividend Requirements
    1.60       1.85       1.63       1.91       2.31  


(1)   Preferred Stock Subject to Mandatory Redemption was reclassified from equity to liabilities in 2003 with the adoption of SFAS No. 150. Accordingly, preferred stock dividend requirements were reclassified to interest expense effective July 1, 2003. Balance as of December 31, 2004 and 2003 does not include current portion.
 
(2)   Company-Obligated Mandatorily Redeemable Preferred Trust Securities were reclassified to Long-Term Debt to Affiliated Trusts in 2003 with the adoption of FASB Interpretation No. 46.

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

Forward-Looking Statements

Avista Corporation (Avista Corp. or the Company) from time to time makes forward-looking statements such as statements regarding future financial performance, capital expenditures, dividends, capital structure and other financial items, including the underlying assumptions (many of which are based, in turn, upon further assumptions), as well as strategic goals and objectives and plans for future operations. Such statements are made both in Avista Corp.’s reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. 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,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “projects,” “predicts,” and similar expressions.

All forward-looking statements (including those made in this Annual Report) are subject to a variety of risks and uncertainties and other factors, most of which are beyond the control of Avista Corp. and many of which could have a significant impact on Avista Corp.’s operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements. Such risks, uncertainties and other factors include, among others:

•   changes in the utility regulatory environment in the individual states and provinces in which the Company operates as well as the United States and Canada in general, which can impact allowed rates of return, financings, or industry and rate structures;
 
•   the impact of regulatory decisions including Federal Energy Regulatory Commission (FERC) price controls, and including possible retroactive price caps and resulting refunds;
 
•   the potential effects of any legislation or administrative rulemaking passed into law;
 
•   the impact from the potential formation of a Regional Transmission Organization and/or an Independent Transmission Company;
 
•   the impact from the potential implementation of the FERC’s proposed wholesale power market rules;
 
•   the ability to relicense the Spokane River Project at a cost-effective level with reasonable terms and conditions;
 
•   volatility and illiquidity in wholesale energy markets, including the availability and prices of purchased energy and demand for energy sales;
 
•   changes in wholesale energy prices that can affect, among other things, the market value of derivative assets and liabilities and unrealized gains and losses, as well as cash requirements to purchase electricity and natural gas for retail customers;
 
•   changes in global energy markets that can affect, among other things, the price of natural gas purchased for retail customers and purchased as fuel for electric generation;
 
•   wholesale and retail competition (including, but not limited to, electric retail wheeling and transmission costs);
 
•   future streamflow conditions that affect the availability of hydroelectric resources;
 
•   unplanned outages at any Company-owned generating facilities;
 
•   unanticipated delays or changes in construction costs with respect to present or prospective facilities;
 
•   changes in weather conditions that can affect customer demand, result in natural disasters and/or disrupt energy delivery;
 
•   changes in industrial, commercial and residential growth and demographic patterns in the Company’s service territory;
 
•   the loss of significant customers and/or suppliers;
 
•   failure to deliver on the part of any parties from which the Company purchases and/or sells capacity or energy;
 
•   changes in the creditworthiness of customers and energy trading counterparties;
 
•   the Company’s ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including the Company’s credit ratings, interest rate fluctuations and other capital market conditions;
 
•   the impact of any potential change in the Company’s credit ratings, including the effect on Avista Energy’s credit facility;
 
•   changes in future economic conditions in the Company’s service territory and the United States in general, including inflation or deflation and monetary policy;
 
•   changes in rapidly advancing technologies, possibly making some of the current technology quickly obsolete;
 
•   the potential for future terrorist attacks, particularly with respect to utility plant assets;
 
•   changes in tax rates and/or policies;

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•   changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs;
 
•   the outcome of legal and regulatory proceedings concerning the Company or affecting directly or indirectly its operations, including the potential disallowance of previously deferred costs;
 
•   employee issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, as well as the ability to recruit and retain employees;
 
•   changes in actuarial assumptions and the return on assets with respect to the Company’s pension plan, which can impact future funding obligations, costs and pension plan liabilities;
 
•   increasing health care costs and the resulting effect on health insurance premiums paid for employees and on the obligation to provide postretirement health care benefits; and
 
•   increasing costs of insurance, changes in coverage terms and the ability to obtain insurance.

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

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

Avista Corp. Business Segments

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. The Company has four business segments — Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other. Avista Utilities is an operating division of Avista Corp. comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. As of December 31, 2004, the Company had common equity investments of $495.8 million and $257.4 million in Avista Utilities and Avista Capital, respectively.

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

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

The Other business segment includes Avista Ventures, Inc. (Avista Ventures), Pentzer Corporation (Pentzer), Avista Development and certain other operations of Avista Capital. Included in this business segment is Advanced Manufacturing and Development (AM&D) doing business as METALfx, a subsidiary of Avista Ventures that performs custom sheet metal manufacturing of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also provides complete fabrication and turnkey assembly for arcade games, kiosks, store fixtures and displays. Other significant investments in this segment include commercial office buildings, investments in low income housing and venture capital partnerships, the remaining investment in a previous fuel cell subsidiary of the Company, and notes receivable from the sale of property and investments.

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Executive Level Summary

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

Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Avista Utilities expects to continue its modest, yet steady, combined growth of electric and natural gas customers of 2 to 3 percent per year primarily from economic and population growth in its service territory. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, the Company has entered into an agreement to sell its natural gas distribution properties in South Lake Tahoe, California (see “Note 27 of the Notes to Consolidated Financial Statements”).

It is Avista Utilities’ strategy to own or to have contracts that provide a sufficient amount of electric resources to meet its retail and wholesale energy requirements under a range of operating conditions. Available resources and the costs of those resources are significantly affected by Avista Utilities’ hydroelectric generation, which was 95 percent of normal in 2004. Based on forecasts as of March 1, 2005, Avista Utilities expects hydroelectric generation will be approximately 84 percent of normal in 2005 assuming normal precipitation for the remainder of the year. This expectation may change based upon precipitation, temperatures and other variables. The earnings impact of below normal hydroelectric generation is mitigated through power cost deferral and recovery mechanisms in Washington and Idaho. The expected reduction in hydroelectric generation is estimated to have a negative effect on operating cash flows of approximately $25 million from the amount originally forecasted, with approximately $2.5 million impacting pre-tax earnings. Avista Utilities believes that it has adequate liquidity through cash flows generated from operations and funds available under its committed line of credit to meet increased cash requirements for purchased power or fuel as a result of reduced hydroelectric generation.

Customer loads and resulting revenues are also significantly affected by weather, which causes changes in energy usage from season to season and from month to month within a season. Changes in wholesale electric prices and the amount of hydroelectric generation available to Avista Utilities also make quarter-to-quarter comparisons difficult. Avista Utilities normally experiences its highest retail energy sales during the heating season in the first and fourth quarters of the year. Although there were differences with respect to quarter-to-quarter comparisons, total heating and cooling degree days at Spokane, Washington for both 2004 and 2003 were similar with both warmer than normal heating and cooling seasons. As such, electric and natural gas loads, revenues and net income were not significantly affected by weather when comparing 2004 to 2003 results.

As is the case with most regulated entities, Avista Utilities generally has ongoing regulatory proceedings. Avista Utilities continues to make progress with respect to resolving its regulatory matters; however, certain issues remain unresolved. Avista Utilities received the following general rate increases in 2004 and 2003: (1) Oregon natural gas in September 2003; (2) Idaho electric and natural gas in September 2004; and (3) Washington natural gas in November 2004. These general rate increases have increased revenues and net income for 2004 as compared to 2003 and should result in increased net income in 2005 as compared to 2004. Avista Utilities will continue to file for rate adjustments to provide recovery of its costs and to more closely align earned returns with those allowed by regulatory agencies in each jurisdiction.

Avista Utilities’ net income decreased in 2004 as compared to 2003 primarily due to write-offs related to the Idaho general electric rate case, which was partially offset by the general rate increases described above. The Company expects Avista Utilities’ net income for 2005 to increase as compared to 2004 primarily due to the continued effect of general rate increases, subject to the influence of weather.

The Company has management succession plans that work towards ensuring that executive officer and key management positions can be appropriately filled as vacancies occur. The Company has taken similar steps in key technical and craft areas.

Avista Energy focuses on optimization of combustion turbines and hydroelectric assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy is also involved in trading electricity and natural gas, including derivative commodity instruments. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to approximately 250 industrial and commercial customers that represent over 400 sites in British Columbia, Canada. In addition to earnings and resulting cash flows from settled or realized

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transactions, Avista Energy records unrealized or mark-to-market adjustments for the change in the value of derivative commodity instruments. Avista Energy’s marketing, trading and resource management activities are driven by its base of knowledge and experience in the operation of both electric energy and natural gas physical systems in the WECC, as well as its relationship-focused approach with its customers.

Avista Energy is subject to certain regulatory proceedings that remain unresolved; however, Avista Energy believes that it has adequate reserves established for refunds that may be ordered. The wholesale power markets in which Avista Energy operates continue to change with respect to market participants involved, level of activity, volatility in market prices, liquidity, regulatory imposed price caps and counterparty credit issues.

Net income for Avista Energy and the Energy Marketing Resource Management segment decreased for 2004 as compared to 2003. This was primarily due to the positive effects in 2003 of accounting for energy trading activities under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” and the settlement of positions with certain Enron Corporation (Enron) affiliates. Both 2004 and 2003 net income for the Energy Marketing and Resource Management segment were decreased by impairment charges for a turbine and related equipment owned by Avista Power. The Company does not expect these factors to occur in 2005.

Avista Advantage remains focused on increasing revenues, controlling operating expenses, continuously enhancing client satisfaction and developing complementary value-added services. The Company expects that net income for Avista Advantage for 2005 will increase as compared to 2004 based on improving revenues and stabilized operating expenses from processing efficiencies.

Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment. The Company expects the net loss in the Other business segment to be less for fiscal year 2005 as compared to 2004 due to decreased losses from asset impairments and write-offs.

During 2005, the Company expects cash flows from operations and Avista Corp.’s five-year $350.0 million committed line of credit to provide adequate resources to fund capital expenditures, maturing long-term debt (excluding $54.6 million of maturing WP Funding LP debt) and other contractual commitments. However, if market conditions warrant such actions, the Company may issue securities to fund these obligations, refinance existing debt and repurchase long-term debt scheduled to mature in future years to reduce its overall debt service costs, as well as to manage the risk associated with future changes in interest rates on debt maturities scheduled for 2007 and 2008.

Avista Utilities — Electric Resources

As of December 31, 2004, Avista Utilities’ facilities had a total net capability of approximately 1,663 MW, of which 59 percent was hydroelectric and 41 percent was thermal. The addition of the remaining interest in Coyote Springs 2 changes Avista Utilities net capability mix to 54 percent hydroelectric and 46 percent 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. See “Note 7 of the Notes to Consolidated Financial Statements” for information with respect to Avista Utilities’ resource optimization process.

Avista Utilities — Regulatory Matters

General Rate Cases

Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. Avista Utilities plans to file an electric general rate case in Washington during March or April of 2005.

In January 2005, the Washington Utilities and Transportation Commission (WUTC) issued its final order with respect to a natural gas general rate case filed by Avista Utilities in Washington. The final order authorized, among other things, an increase in natural gas rates of 3.9 percent, which is designed to increase annual revenues by $5.4 million. The final order authorized an overall rate of return of 8.68 percent. The natural gas rate increase was implemented in November 2004 resulting from a settlement agreement reached among the Company, the staff of the WUTC and the Northwest Industrial Gas Users in October 2004. The increase was approved by the WUTC in November 2004 on a “subject to refund” basis to allow the non-settling parties the opportunity to further review the case.

In October 2004, the Idaho Public Utilities Commission (IPUC) issued its final order with respect to electric and natural gas general rate cases filed by Avista Utilities in Idaho. The final order authorized, among other things,

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Avista Utilities to increase its electric base rates by 16.9 percent, which is designed to increase annual revenues by $24.7 million, and increase its natural gas base rates by 6.4 percent, which is designed to increase annual revenues by $3.3 million. Due to a decrease implemented concurrently in Avista Utilities’ power cost adjustment (PCA) surcharge and certain other minor adjustments, the net increase in electric rates for Idaho customers was 1.9 percent above rates in effect at that time. The decrease in the PCA surcharge reduces the rate increase impact to customers and extends the period for recovery of deferred power costs. The final order authorized an overall rate of return of 9.25 percent and a return on common equity of 10.4 percent based on an authorized equity level of approximately 43 percent. The final order required Avista Utilities to write off a total of $14.4 million. The write-off included the disallowance of $12.0 million of certain deferred power costs, including associated interest, related to natural gas contracts entered into by Avista Utilities to provide fuel for its generating facilities and the disallowance of $2.4 million (net of $0.3 million of accumulated depreciation) of certain capitalized utility plant costs. Avista Utilities believes that such costs were prudently incurred and reasonable given the market conditions at the time. Avista Utilities filed a petition for reconsideration of certain portions of the final order including the disallowance of $4.8 million of certain deferred power costs and $2.6 million of certain utility plant costs. In November 2004, the IPUC denied the petition for reconsideration with the exception of certain minor technical corrections, which reduced the total write-off by $0.3 million. As such, the matter is closed.

In September 2003, the Oregon Public Utility Commission (OPUC) approved a natural gas general rate increase for Oregon customers, which was designed to increase annual revenues by $6.3 million effective October 1, 2003. The order authorized, among other things, an overall rate of return of 8.88 percent and a return on equity of 10.25 percent based on an authorized equity level of approximately 48 percent.

Other Regulatory Filings

In January 2005, Avista Utilities filed a request with the IPUC to include the acquisition of the remaining 50 percent of Coyote Springs 2 in base electric rates. Avista Utilities requested a 1.9 percent increase in base electric rates, which is designed to increase annual revenues by $3.2 million. At the same time, Avista Utilities requested that the IPUC approve a 1.9 percent reduction in the company’s current PCA rate surcharge. These two requests together would result in no overall change to customers’ existing rates. On March 1, 2005, the IPUC Staff filed comments in support of Avista Utilities’ request and one other party filed comments opposing Avista Utilities’ request. Avista Utilities plans to file reply comments by March 15, 2005. In Washington, the acquisition of Coyote Springs 2 will be addressed in the expected general rate case filing.

Avista Utilities is also involved in regulatory proceedings before the California Public Utilities Commission (CPUC) with respect to the sale of its South Lake Tahoe, California natural gas distribution properties. See “Note 27 of the Notes to Consolidated Financial Statements.”

Power Cost Deferrals and Recovery Mechanisms

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

In Washington, the Energy Recovery Mechanism (ERM) allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of the power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company. The Company expensed the initial $9.0 million of power supply costs above the amount included in base retail rates during 2004, 2003 and 2002 ($4.5 million due to mid-year implementation on July 1, 2002) and expects to expense the initial $9.0 million during 2005.

Under the ERM, Avista Utilities agreed to make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. In August 2004, the WUTC issued an order, which approved the recovery of $22.8 million of deferred power costs incurred in 2003. On or before December 31, 2006, Avista Utilities will make a filing with the WUTC that will allow interested parties the opportunity to review and propose changes to the ERM.

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Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the authorized level of net power supply expense approved in the last Idaho general rate case. As disclosed at “General Rate Cases” above, the IPUC issued its final order with respect to general electric and natural gas rate cases filed by Avista Utilities in Idaho. The final order required Avista Utilities to write off a total of $12.0 million of certain deferred power costs, including associated interest, related to natural gas contracts entered into by Avista Utilities to provide fuel for its generating facilities. The IPUC authorized the recovery of the remaining deferred power costs over a two-year period through a PCA rate surcharge to customers of 4.4 percent. See “Other Regulatory Filings” with respect to Avista Utilities’ request to decrease the PCA rate surcharge.

The following table shows activity in deferred power costs for Washington and Idaho during 2003 and 2004 (dollars in thousands):

                         
    Washington     Idaho     Total  
 
Deferred power costs as of December 31, 2002
  $ 123,749     $ 31,518     $ 155,267  
Activity from January 1 - December 31, 2003:
                       
Power costs deferred
    22,217       23,341       45,558  
Unrealized loss on fuel contracts (1)
    1,975       1,004       2,979  
Interest and other net additions
    6,002       1,037       7,039  
Write-off of deferred power costs
    (2,461 )           (2,461 )
Recovery of deferred power costs through retail rates
    (25,777 )     (26,615 )     (52,392 )
 
                 
Deferred power costs as of December 31, 2003
    125,705       30,285       155,990  
Activity from January 1 - December 31, 2004:
                       
Power costs deferred
    10,498       15,276       25,774  
Unrealized gain on fuel contracts (1)
    (3,139 )     (1,596 )     (4,735 )
Interest and other net additions
    6,354       532       6,886  
Write-off of deferred power costs
          (11,959 )     (11,959 )
Recovery of deferred power costs through retail rates
    (26,210 )     (23,040 )     (49,250 )
 
                 
Deferred power costs as of December 31, 2004
  $ 113,208     $ 9,498     $ 122,706  
 
                 


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

Purchased Gas Adjustments

During recent years, natural gas prices have been volatile with a general upward trend. Avista Utilities’ average prices per dekatherm were $6.62, $5.50 and $4.95 in 2004, 2003 and 2002, respectively. The continued upward price trend has caused the recovery period for deferred natural gas costs to lengthen. The Company is connected to multiple supply basins in the western United States and western Canada and believes there will be sufficient supplies of natural gas to meet its customers’ needs. However, natural gas prices in the Pacific Northwest are increasingly affected by supply and demand factors in other regions of the United States and Canada because of growth in transcontinental pipeline capacity. Global energy markets also affect natural gas prices. Natural gas commodity costs in excess of, or which fall below, the amount recovered in current retail rates are deferred and recovered or refunded as a pass-through to customers in future periods with applicable regulatory approval through adjustments to rates.

During September and October of 2003, natural gas rate increases of 8.7 percent, 2.4 percent, 12.4 percent and 15.0 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. During September through November of 2004, natural gas rate increases of 11.7 percent, 14.2 percent, 12.6 percent and 10.5 percent were approved and implemented in Washington, Idaho, Oregon and California, respectively. These natural gas rate increases are designed to pass through changes in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income. Total deferred natural gas costs were $28.6 million and $15.4 million as of December 31, 2004 and 2003, respectively.

Natural Gas Benchmark Mechanism

The IPUC, WUTC and OPUC approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations with Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets have been managed by Avista Energy through an Agency Agreement. In early 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. In February 2004,

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the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. In April 2004, the WUTC approved Avista Utilities’ transition plan, which provides for the movement of these functions back into Avista Utilities to be completed by March 31, 2005. Effective April 1, 2005, the Company will also be moving these functions from Avista Energy to Avista Utilities for Idaho and Oregon natural gas customers with the expiration of the current agreements. As part of the transition plan, Avista Utilities has begun procuring natural gas for load service. This procurement process includes entering into financial and physical hedging transactions as a means of managing risks. This transition of Avista Utilities’ natural gas procurement operations also impacts the level of counterparty credit requirements at both Avista Utilities and Avista Energy. In response to this as well as to provide enhanced financial flexibility, in May 2004 Avista Corp. increased the amount available under its committed line of credit to $350.0 million from $245.0 million. In December 2004, Avista Corp. entered into a five-year $350.0 million committed line of credit, which replaced the 364-day committed line of credit entered into in May 2004.

Power Market Issues

Legal and Regulatory Proceedings in Western Power Markets

Avista Energy and Avista Utilities are involved in a number of legal and regulatory proceedings and complaints with respect to power markets in the western United States. Most of these proceedings and complaints relate to the significant increase in the spot market price of energy in western power markets in 2000 and 2001, which allegedly contributed to or caused unjust and unreasonable prices and allegedly may have been the result of manipulations by certain other parties. These proceedings and complaints include, but are not limited to, refund proceedings and hearings in California and the Pacific Northwest, market conduct investigations by the FERC (including a specific investigation of Avista Utilities and Avista Energy), and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from Avista Energy and Avista Utilities, which could result in a negative impact on future earnings. Avista Energy and Avista Utilities have joined other parties in opposing these refund claims and complaints for damages. See further information under “Federal Energy Regulatory Commission Inquiry,” “Counterparty Defaults,” “California Refund Proceeding,” “Pacific Northwest Refund Proceeding,” “Reliant Energy, Inc. and Duke Energy Corporation Cross-Complaints,” “California Attorney General Complaint,” “Port of Seattle Complaint,” “Wah Chang Complaint,” “City of Tacoma Complaint,” and “State of Montana Proceedings” in “Note 25 of the Notes to Consolidated Financial Statements.”

Market Conduct Investigations and Market-Based Rate Authority

As a result of certain revelations about alleged improper practices engaged in by Enron and certain of its affiliates, the FERC initiated investigations in February 2002 of Avista Corp. doing business as Avista Utilities, Avista Energy and other unrelated parties. Avista Utilities and Avista Energy cooperated with the FERC investigation by providing requested documents and other information. Several parties filed documents with the FERC in March 2003 alleging improper market conduct by various parties, including Avista Utilities and Avista Energy, and requesting refunds and other relief. Avista Utilities and Avista Energy filed replies in response to the allegations of the parties.

In March 2003, the FERC policy staff issued its final report on its investigation of western energy markets. In the report, the FERC policy staff recommended the issuance of “show cause” orders to dozens of companies to respond to allegations of possible misconduct in the western energy markets during 2000 and 2001. Of the companies named in the March 2003 FERC policy staff report, Avista Corp. and Avista Energy were among the few that had already been subjects of a FERC investigation. See further information under “Federal Energy Regulatory Commission Inquiry” in “Note 25 of the Notes to Consolidated Financial Statements.”

Every three years or more frequently if certain regulatory triggers are met, Avista Corp. doing business as Avista Utilities, and Avista Energy are required to file for renewal of their respective market-based rate authority with the FERC. Avista Utilities and Avista Energy made their respective filings with the FERC on September 27, 2004. The filing was amended, at the request of the FERC Staff, with additional information on December 7, 2004 and February 4, 2005. No comments or interventions were filed by interested parties by the close of the comment period on February 14, 2005. By order issued on March 3, 2005, the FERC approved the renewal of the market-based rate authority of Avista Utilities and Avista Energy.

Wholesale Energy Markets and Development of Regional Transmission Organizations

The FERC has proposed changes to the design of the wholesale energy market, which includes the formation of Regional Transmission Organizations. This could significantly change how transmission facilities are regulated and operated.

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Avista Corp. has participated with other utilities in the western United States on the possible formation of a Regional Transmission Organization. Interim bylaws governing continuing developmental activities for this non-profit corporation, under the name Grid West, were adopted on December 9, 2004. The next phase of the development of Grid West would be the establishment of a board of directors, which is currently planned for late-2005.

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

Results of Operations

Diluted Earnings (Loss) per Common Share by Business Segments

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

                         
    2004     2003     2002  
 
Avista Utilities
  $ 0.67     $ 0.72     $ 0.71  
Energy Marketing and Resource Management
    0.20       0.43       0.47  
Avista Advantage
    0.01       (0.03 )     (0.09 )
Other
    (0.15 )     (0.10 )     (0.26 )
 
                 
Earnings per common share from continuing operations
    0.73       1.02       0.83  
Loss per common share from discontinued operations
          (0.10 )     (0.14 )
 
                 
Earnings per common share before cumulative effect of accounting change
    0.73       0.92       0.69  
Loss per common share from cumulative effect of accounting change
    (0.01 )     (0.03 )     (0.09 )
 
                 
Total earnings per common share, diluted
  $ 0.72     $ 0.89     $ 0.60  
 
                 

Overall Operations

2004 compared to 2003

Income from continuing operations was $35.6 million for 2004 compared to $50.6 million for 2003. This decrease was primarily due to the Idaho general rate case write-offs of $14.4 million ($9.4 million, net of tax) recorded at Avista Utilities, as well as reduced earnings for Avista Energy (Energy Marketing and Resource Management segment) and an increase in the net loss for the Other business segment. This was partially offset by the improved performance of Avista Utilities (excluding the Idaho write-offs) due to general rate increases, as well as net earnings from Avista Advantage for 2004 as compared to a net loss for 2003.

Net income for Energy Marketing and Resource Management was $9.7 million for 2004 compared to $20.7 million (excluding the cumulative effect of accounting change) for 2003. During 2003, Avista Energy’s earnings were positively impacted by the effects of accounting for energy contracts under SFAS No. 133 and a settlement with certain Enron affiliates. In addition, Avista Energy’s earnings were decreased due to lower natural gas trading margins in 2004 as compared to 2003. These decreases were partially offset by portfolio valuation adjustments at Avista Energy of approximately $2.9 million, net of tax, the most significant of which relates to increases in market liquidity in the Western power markets. Both 2004 and 2003 net income for the Energy Marketing and Resource Management segment were decreased by impairment charges for a turbine and related equipment owned by Avista Power, which is classified as held for sale.

Net income for Avista Utilities was $32.5 million for 2004, compared to $36.2 million for 2003. The decrease for Avista Utilities was primarily due to the Idaho general rate case write-offs. Excluding the write-offs, net income increased primarily due to an increase in gross margin as a result of general rate increases, partially offset by an increase in other operating expenses (operations and maintenance, administrative and general, depreciation and amortization, and taxes other than income taxes).

Avista Advantage had net income of $0.6 million for 2004 compared to a net loss of $1.3 million for 2003. The change was primarily due to an increase in operating revenues, partially offset by the settlement of an employment contract.

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The Other business segment incurred a net loss of $7.2 million (excluding the cumulative effect of accounting change) for 2004 compared to a net loss of $4.9 million for 2003. The increase in the net loss was primarily due to the impairment of goodwill at AM&D, the write-off of an investment in a natural gas storage project, the accrual of an environmental liability at Avista Development and Avista Capital’s purchase of Avista Advantage preferred stock at a premium. This was partially offset by a reduced net loss from AM&D, excluding the goodwill impairment.

Total revenues increased $28.2 million for 2004 compared to 2003. Avista Utilities’ revenues increased $44.4 million due to increases in both electric and natural gas revenues. The increase in natural gas revenues was primarily due to natural gas rate increases implemented during 2004 and 2003 and partially due to increased therms sold, primarily as a result of customer growth. The increase in electric revenues reflects an increase in retail revenues, partially offset by a decrease in wholesale revenues and sales of fuel. Revenues from Energy Marketing and Resource Management decreased $31.5 million primarily due to decreased net trading margin on contracts accounted for under SFAS No. 133, a settlement with Enron affiliates during 2003 and decreased revenues under the Agency Agreement with Avista Utilities, partially offset by increased revenues for Avista Energy Canada. Revenues from Avista Advantage increased $3.6 million to $23.4 million primarily as a result of customer growth. Revenues from the Other business segment increased $3.5 million to $17.1 million primarily due to increased revenues from AM&D as well as revenues from entities consolidated in 2004 under Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised in December 2003 (collectively referred to as FIN 46).

Total resource costs increased $28.5 million for 2004 compared to 2003. Resource costs for Avista Utilities increased $30.5 million primarily due to an increase in purchased natural gas costs as well as the write-off of $12.0 million of deferred power costs resulting from the Idaho general rate case order. This increase in purchased natural gas costs was primarily due to an increase in prices and partially due to an increase in the volume purchased due to customer growth. Resource costs for Energy Marketing and Resource Management decreased $10.1 million primarily due to decreased resource costs for Avista Energy Canada and decreased resource costs under the Agency Agreement with Avista Utilities.

Intersegment eliminations, which decrease both operating revenues and resource costs, were $137.2 million for 2004 compared to $145.4 million for 2003, representing decreased purchases of natural gas under the Agency Agreement between Avista Utilities and Avista Energy.

Operations and maintenance expenses increased $17.9 million for 2004 compared to 2003 partially due to the disallowance in the Idaho general rate case of $2.4 million (net of $0.3 million of accumulated depreciation) of certain capitalized utility plant costs at Avista Utilities. The remaining increase for Avista Utilities was primarily due to a general increase in operations and maintenance expense primarily related to distribution and customer service expenses, partially reflecting an increase in labor costs. Operations and maintenance expense for the Other business segment increased $2.6 million due to the write-off of an investment in a natural gas storage project as well as the effects from entities consolidated under FIN 46.

Administrative and general expenses increased $6.8 million for 2004 compared to 2003 primarily due to increased expenses for Avista Utilities, Avista Advantage and the Other business segment, partially offset by decreased expenses for Energy Marketing and Resource Management. The decrease for Energy Marketing and Resource Management was primarily a result of decreased compensation expenses and professional fees. The increase for Avista Utilities primarily reflects an increase in labor costs and other employee related expenses, increased liability and damage claims insurance costs, as well as an increase in outside services. The increase for Avista Advantage was primarily due to the settlement of an employment contract. The increase for the Other business segment primarily reflects the impairment of goodwill at AM&D and the accrual of an environmental liability at Avista Development.

Depreciation and amortization increased $0.6 million for 2004 compared to 2003 primarily due to utility plant additions at Avista Utilities and the resulting increase in depreciation expense as well as the consolidation of WP Funding LP under FIN 46 and the resulting inclusion of depreciation expense of the Rathdrum Power Plant. This was partially offset by a correction at Avista Utilities for overstated depreciation expense in prior periods recorded during 2004. Coyote Springs 2 was placed into service in mid-2003 and increased depreciation expense for 2004 as compared to 2003.

Taxes other than income taxes increased $5.7 million for 2004 compared to 2003 primarily due to increased retail revenues and related taxes for Avista Utilities. An increase in property taxes at Avista Utilities also contributed to the increase in taxes other than income taxes.

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Interest expense (including interest expense to affiliated trusts) increased $0.1 million for 2004 compared to 2003 primarily due to the inclusion of the interest expense on $54.6 million of debt of WP Funding LP, which was consolidated for all of 2004 and only the fourth quarter of 2003 as required by FIN 46, as well as an increase in interest on short-term borrowings and the inclusion of preferred stock dividends as interest expense in accordance with SFAS No. 150, partially offset by a decrease in interest expense on long-term debt due to the repurchase of higher cost debt. Preferred stock dividends of $1.1 million, distributed prior to the adoption of SFAS No. 150 on July 1, 2003, were classified as a separate line item in the Consolidated Statement of Income for 2003.

Capitalized interest increased $0.3 million for 2004 compared to 2003. This was primarily due to increased construction activity at Avista Utilities and higher average construction work in progress balances.

Other income-net increased $2.2 million for 2004 compared to 2003 primarily due to increased income in 2004 on certain investments in the Other business segment and net gains on the disposition of non-operating assets in 2004 compared to net losses in 2003. This was partially offset by the premium paid on the repurchase of Avista Advantage preferred stock, as well as a decrease in interest income and interest on power and natural gas deferrals.

Income taxes decreased $13.7 million for 2004 compared to 2003, primarily due to decreased income before income taxes. The effective tax rate was 37.7 percent for 2004 compared to 41.1 percent for 2003.

During 2004, the Other business segment recorded as a cumulative effect of accounting change a charge of $0.5 million related to the implementation of FIN 46, which required Avista Ventures to consolidate several minor entities.

During 2003, Avista Energy recorded as a cumulative effect of accounting change a charge of $1.2 million (net of tax) related to Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which effectively required the transition of accounting for energy trading activities from EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” to SFAS No. 133.

2003 compared to 2002

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

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

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

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

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

Total revenues increased $60.5 million for 2003 compared to 2002. Avista Utilities’ revenues increased $34.2 million primarily due to increased electric revenues, partially offset by decreased natural gas revenues. The decrease in natural gas revenues was primarily due to natural gas rate decreases implemented during the fourth quarter of

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2002 and partially due to decreased therms sold as a result of warmer weather during the first quarter of 2003 as compared to the first quarter of 2002. Natural gas rate increases were implemented in September and October 2003 in response to increased natural gas costs. The increase in electric revenues reflects an increase in retail revenues, wholesale revenues and sales of fuel. Revenues from Energy Marketing and Resource Management increased $84.5 million primarily due to increased revenues on contracts that are not considered derivatives under SFAS No. 133 (primarily the Agency Agreement with Avista Utilities), non-trading derivative contracts and revenues from Avista Energy Canada. Avista Energy’s settlement of various positions with Enron affiliates and the resulting release by Avista Energy of amounts, which had been reserved against such positions, also had a positive impact of $8.4 million on operating revenues for 2003. Revenues from Avista Advantage increased 17 percent to $19.8 million primarily as a result of customer growth. Revenues from the Other business segment decreased $1.1 million primarily due to decreased revenues from AM&D.

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

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

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

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

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

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

Interest expense decreased $11.9 million for 2003 compared to 2002 primarily due to a decrease in the average balance of debt outstanding. This decrease was partially offset by the inclusion of $1.1 million of preferred stock dividends as interest expense for the second half of 2003 in accordance with SFAS No. 150. During 2003 and 2002, the Company repurchased $52.5 million and $203.6 million of long-term debt, respectively. In September 2003, the Company issued $45.0 million of 6.125 percent First Mortgage Bonds due in 2013. The proceeds were used to repay a portion of the borrowings under the then existing $245.0 million line of credit that was used on an interim basis to fund $46.0 million of maturing 9.125 percent Unsecured Medium-Term Notes.

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

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Other income-net decreased $11.1 million for 2003 compared to 2002 primarily due to reduced interest income (including accrued interest on power and natural gas deferrals) as well as losses in 2003 on certain investments in the Other business segment. The decrease in interest income primarily reflects the repayment of a note receivable in the Other business segment in the fourth quarter of 2002 and decreased earnings on short-term investments.

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

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

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

Avista Utilities

2004 compared to 2003

Net income for Avista Utilities was $32.5 million for 2004 compared to $36.2 million for 2003. Avista Utilities’ income from operations was $134.1 million for 2004 compared to $146.8 million for 2003. This decrease was primarily due to the Idaho general rate case write-offs of $14.4 million ($9.4 million, net of tax).

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

                                                 
    Electric     Natural Gas     Total  
    2004     2003     2004     2003     2004     2003  
 
Operating revenues
  $ 652,081     $ 650,922     $ 320,493     $ 277,289     $ 972,574     $ 928,211  
Resource costs
    291,388       294,031       214,003       180,896       505,391       474,927  
 
                                   
Gross margin
  $ 360,693     $ 356,891     $ 106,490     $ 96,393     $ 467,183     $ 453,284  
 
                                   

Avista Utilities’ operating revenues increased $44.4 million and resource costs increased $30.5 million, which resulted in an increase of $13.9 million in gross margin for 2004 as compared to 2003. The gross margin on natural gas sales increased $10.1 million and the gross margin on electric sales increased $3.8 million. The increase in the gross margin on natural gas sales was primarily due to the Idaho natural gas general rate increase implemented in September 2004, the Washington natural gas general rate increase implemented in November 2004 and the Oregon natural gas general rate increase implemented in the fourth quarter of 2003. The increase in electric gross margin was primarily due to the Idaho electric general rate increase implemented in September 2004 as well as customer growth. This was partially offset by the disallowance of $12.0 million of deferred power costs in the Idaho general rate case.

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

                                 
    Electric Operating     Electric Energy  
    Revenues     MWh sales  
    2004     2003     2004     2003  
 
Residential
  $ 209,518     $ 204,783       3,343       3,298  
Commercial
    201,775       201,339       2,919       2,919  
Industrial
    90,288       78,276       2,076       1,785  
Public street and highway lighting
    4,847       4,770       25       25  
 
                       
Total retail
    506,428       489,168       8,363       8,027  
Wholesale
    62,399       73,463       1,472       2,075  
Sales of fuel
    63,990       71,456              
Other
    19,264       16,835              
 
                       
Total
  $ 652,081     $ 650,922       9,835       10,102  
 
                       

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Retail electric revenues increased $17.3 million for 2004 from 2003. This increase was primarily due to an increase in total MWhs sold (increased revenues $20.4 million), partially offset by a decrease in revenue per MWh (decreased revenues $3.1 million). Although there were differences with respect to quarter-to-quarter comparisons, total heating and cooling degree days at Spokane, Washington for both 2004 and 2003 were similar with both warmer than normal heating and cooling seasons. As such, electric loads and revenues were not significantly affected by weather when comparing 2004 to 2003 results. The increase in total MWhs sold and corresponding revenues was primarily due to customer growth as well as the Potlatch Corporation contract, which was entered into during mid-2003. The decrease in revenue per MWh was primarily due to a slight change in revenue mix with a greater percentage of revenues from industrial sales. The increase in industrial revenues was primarily due to the Potlatch Corporation contract. In September 2004, a general electric rate increase was implemented in Idaho. However, this was almost entirely offset by a decrease in the PCA surcharge, such that the net increase in rates to Idaho customers was only 1.9 percent. Although the general rate case increased gross margin, income from operations and net income, it did not have a significant effect on operating revenues for 2004 as compared to 2003.

Wholesale electric revenues decreased $11.1 million primarily due to the implementation of EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as Defined in EITF Issue No. 02-3” which requires that wholesale revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) should be reported on a net basis as part of operating revenues effective October 1, 2003. The adoption of this EITF Issue resulted in a reduction in wholesale revenues of approximately $26.4 million for 2004 as compared to 2003. The remaining change in wholesale revenues reflects higher average sales prices and an increase in wholesale sales volumes.

Sales of fuel decreased $7.5 million as a result of the expiration of several higher priced fuel contracts. A greater percentage of fuel purchases were used in generation, which also contributed to the decrease in sales of fuel. Sales of fuel represents natural gas that was not used for generation because electric wholesale market prices were generally below the cost of operating the natural gas-fired thermal generating units.

Other electric revenues increased $2.4 million primarily due to increased transmission revenues.

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

                                 
    Natural Gas     Natural Gas  
    Operating Revenues     Therm Sales  
    2004     2003     2004     2003  
 
Residential
  $ 194,470     $ 166,925       201,696       198,471  
Commercial
    104,754       90,523       122,852       122,115  
Industrial
    9,423       7,475       13,274       12,737  
 
                       
Total retail
    308,647       264,923       337,822       333,323  
Wholesale
    152       280       305       675  
Transportation
    8,134       8,485       154,427       153,352  
Other
    3,560       3,601       3,030       3,124  
 
                       
Total
  $ 320,493     $ 277,289       495,584       490,474  
 
                       

Natural gas revenues increased $43.2 million for 2004 from 2003 primarily due to an increase in retail natural gas revenues, partially offset by a slight decrease in transportation and wholesale revenues. The $43.7 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $39.6 million) and partially due to an increase in volumes (increased revenues $4.1 million). During 2004 and 2003, retail rates for natural gas were increased in response to an increase in current and projected natural gas costs. In September 2004, a general natural gas rate increase was implemented in Idaho. In November 2004, a general natural gas rate increase was implemented in Washington. Also, during the fourth quarter of 2003, a general natural gas rate increase was implemented in Oregon. The increase in total therms sold was primarily a result of customer growth, as a colder first quarter of 2004 was offset by a warmer fourth quarter of 2004 as compared to 2003.

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

                                 
    Electric     Natural Gas  
    Customers     Customers  
    2004     2003     2004     2003  
 
Residential
    288,422       283,497       268,571       261,063  
Commercial
    36,728       36,279       31,886       31,312  
Industrial
    1,416       1,414       311       310  
Public street and highway lighting
    418       422              
 
                       
Total retail
    326,984       321,612       300,768       292,685  
Wholesale
    43       47       1       1  
Transportation
                81       84  
 
                       
Total customers
    327,027       321,659       300,850       292,770  
 
                       

The following table presents Avista Utilities heating and cooling degree days for the years ended December 31:

                 
    2004     2003  
 
Heating degree days (1):
               
Spokane, Washington actual
    6,314       6,351  
Spokane, Washington 30 year average (2)
    6,820       6,820  
Percentage of average
    93 %     93 %
Medford, Oregon actual
    3,933       4,046  
Medford, Oregon 30 year average (2)
    4,592       4,592  
Percentage of average
    86 %     88 %
Cooling degree days (3):
               
Spokane, Washington actual
    571       578  
Spokane, Washington 30 year average (2)
    394       394  
Percent of average
    145 %     147 %


(1)   Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
 
(2)   Computed for the period from 1971 through 2000.
 
(3)   Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of the high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures).

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

                 
    2004     2003  
 
Electric resource costs:
               
Power purchased
  $ 145,298     $ 147,743  
Power cost amortizations, net of deferrals
    22,950       7,165  
Fuel for generation
    38,406       35,581  
Other fuel costs
    72,602       96,765  
Other regulatory amortizations, net
    (10,095 )     (7,904 )
Other electric resource costs
    22,227       14,681  
 
           
Total electric resource costs
    291,388       294,031  
 
           
Natural gas resource costs:
               
Natural gas purchased
    225,908       184,014  
Natural gas deferrals, net of amortization
    (12,136 )     (3,336 )
Other regulatory amortizations, net
    231       218  
 
           
Total natural gas resource costs
    214,003       180,896  
 
           
Total resource costs
  $ 505,391     $ 474,927  
 
           

Power purchased for 2004 decreased $2.4 million compared to 2003 due to the effects of EITF Issue No. 03-11 (decreased costs by $26.4 million), partially offset by an increase in the price of power purchases (increased costs $15.1 million) and an increase in the volume of power purchases (increased costs $8.9 million).

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Net amortization of deferred power costs was $23.0 million for 2004 compared to $7.2 million for 2003. During 2004, Avista Utilities recovered (collected as revenue) $26.2 million of previously deferred power costs in Washington and $23.0 million in Idaho. There was a decrease in the recovery of previously deferred power costs in Idaho, which was primarily due to the reduction of the PCA rate surcharge in the Idaho general rate case. During 2004, Avista Utilities deferred $10.5 million of power costs in Washington and $15.3 million in Idaho. The total deferral of power costs decreased in 2004 as compared to 2003 due to an increase in hydroelectric generation and the expiration of higher priced natural gas fuel contracts.

Fuel for generation for 2004 increased $2.8 million compared to 2003 primarily due to an increase in fuel prices and partially due to a slight increase in thermal generation.

Other fuel costs for 2004 decreased $24.2 million compared to 2003. This natural gas fuel was sold with the associated revenues reflected as sales of fuel. Other fuel costs exceeded the revenues from selling the natural gas. This excess cost is accounted for under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to the expiration of higher-priced natural gas fuel contracts. The decrease was also due to a greater percentage of fuel used in generation.

Other electric resource costs for 2004 increased $7.5 million compared to 2003 primarily due to the disallowance of $12.0 million of deferred power costs in the Idaho general rate case. This was partially offset by the consolidation of WP Funding LP and the elimination of the Rathdrum Power Plant lease expense from resource costs. Costs associated with the Rathdrum Power Plant are primarily reflected as depreciation and interest expense in 2004.

The expense for natural gas purchased for 2004 increased $41.9 million compared to 2003 due to an increase in the cost of natural gas (increased costs $37.4 million) and an increase in total therms purchased (increased costs $4.5 million) consistent with an increase in natural gas sales from customer growth. During 2004, Avista Utilities had $12.1 million of net deferrals of natural gas costs compared to $3.3 million for 2003. The increase was primarily due to an increase in natural gas prices.

2003 compared to 2002

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

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

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

                                                 
    Electric     Natural Gas     Total  
    2003     2002     2003     2002     2003     2002  
 
Operating revenues
  $ 650,922     $ 584,141     $ 277,289     $ 309,823     $ 928,211     $ 893,964  
Resource costs
    294,031       240,380       180,896       213,145       474,927       453,525  
 
                                   
Gross margin
  $ 356,891     $ 343,761     $ 96,393     $ 96,678     $ 453,284     $ 440,439  
 
                                   

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

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

                                 
    Electric Operating     Electric Energy  
    Revenues     MWh sales  
    2003     2002     2003     2002  
 
Residential
  $ 204,783     $ 196,156       3,298       3,203  
Commercial
    201,339       194,732       2,919       2,837  
Industrial
    78,276       68,096       1,785       1,519  
Public street and highway lighting
    4,770       4,683       25       25  
 
                       
Total retail
    489,168       463,667       8,027       7,584  
Wholesale
    73,463       64,082       2,075       2,216  
Sales of fuel
    71,456       40,937              
Other
    16,835       15,455              
 
                       
Total
  $ 650,922     $ 584,141       10,102       9,800  
 
                       

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

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

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

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

                                 
    Natural Gas     Natural Gas  
    Operating Revenues     Therm Sales  
    2003     2002     2003     2002  
 
Residential
  $ 166,925     $ 183,964       198,471       199,686  
Commercial
    90,523       104,974       122,115       126,220  
Industrial
    7,475       7,127       12,737       11,243  
 
                       
Total retail
    264,923       296,065       333,323       337,149  
Wholesale
    280       695       675       2,306  
Transportation
    8,485       9,664       153,352       174,891  
Other
    3,601       3,399       3,124       2,145  
 
                       
Total
  $ 277,289     $ 309,823       490,474       516,491  
 
                       

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

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

                                 
    Electric     Natural Gas  
    Customers     Customers  
    2003     2002     2003     2002  
 
Residential
    283,497       279,735       261,063       254,700  
Commercial
    36,279       35,910       31,312       30,823  
Industrial
    1,414       1,420       310       315  
Public street and highway lighting
    422       413              
 
                       
Total retail
    321,612       317,478       292,685       285,838  
Wholesale
    47       46       1       1  
Transportation
                84       88  
 
                       
Total customers
    321,659       317,524       292,770       285,927  
 
                       

The following table presents Avista Utilities heating and cooling degree days for the years ended December 31:

                 
    2003     2002  
 
Heating degree days (1):
               
Spokane, Washington actual
    6,351       6,818  
Spokane, Washington 30 year average (2)
    6,820       6,842  
Percentage of average
    93 %     100 %
Medford, Oregon actual
    4,046       4,230  
Medford, Oregon 30 year average (2)
    4,592       4,611  
Percentage of average
    88 %     92 %
Cooling degree days (3):
               
Spokane, Washington actual
    578       405  
Spokane, Washington 30 year average (4)
    394       394  
Percent of average
    147 %     103 %


(1)   Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
 
(2)   For 2003, computed for the period from 1971 through 2000. For 2002, computed for the period from 1961 to 1990.
 
(3)   Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of the high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures).
 
(4)   Computed for the period 1971 through 2000.

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

                 
    2003     2002  
 
Electric resource costs:
               
Power purchased
  $ 147,743     $ 115,282  
Power cost amortizations, net of deferrals
    7,165       26,253  
Fuel for generation
    35,581       18,531  
Other fuel costs
    96,765       77,885  
Other regulatory amortizations, net
    (7,904 )     (15,411 )
Other electric resource costs
    14,681       17,840  
 
           
Total electric resource costs
    294,031       240,380  
 
           
Natural gas resource costs:
               
Natural gas purchased
    184,014       170,662  
Natural gas cost amortizations (deferrals), net
    (3,336 )     42,229  
Other regulatory amortizations, net
    218       254  
 
           
Total natural gas resource costs
    180,896       213,145  
 
           
Total resource costs
  $ 474,927     $ 453,525  
 
           

Power purchased for 2003 increased $32.5 million, or 28 percent, compared to 2002 primarily due to an increase in the price of power purchases (increased costs $31.3 million) and partially due to an increase in the volume of power

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purchases (increased costs $1.2 million). The increase in the price of power purchases reflects increases in the price of power in the western United States and the Pacific Northwest. This appears to be partially due to lower than normal precipitation and snowpack conditions during the fourth quarter of 2002 and the first two months of 2003 and the anticipated effects on hydroelectric generation in the region. Warm and dry conditions in the Pacific Northwest during the summer of 2003 as well as the increased cost of natural gas used to generate electricity appear to have increased the price of electricity during 2003 as compared to 2002. Reduced hydroelectric availability and increased demand due to weather also appear to have affected wholesale electric prices in the western United States and the Pacific Northwest during the second half of 2003 as compared to 2002.

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

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

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

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

Energy Marketing and Resource Management

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

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

•   Marketing and managing the output and availability of combustion turbines and hydroelectric assets owned by other entities.
 
•   Capturing price differences between commodities (spark spread) by converting natural gas into electricity through the power generation process.
 
•   Purchasing and storing natural gas for later sales to seek gains from seasonal price variations and demand peaks.
 
•   Transmitting electricity and transporting natural gas between locations, including moving energy from lower priced/demand regions to higher priced/demand markets and hub locations within the WECC.
 
•   Taking speculative positions on future price movements within established risk management policies.

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

Avista Energy trades electricity and natural gas, along with derivative commodity instruments including futures, options, swaps and other contractual arrangements. Most transactions are conducted on an “over-the-counter” basis. Avista Energy’s trading operations are affected by, among other things, volatility of prices within the electric energy and natural gas markets, the demand for and availability of energy, changing regulation of the electric and natural gas industries, the creditworthiness of counterparties and variations in liquidity in energy markets. See “Business Risk” for further information.

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

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

                         
    2004     2003     2002  
 
Net realized gains
  $ 39,520     $ 82,317     $ 141,610  
Net unrealized losses
    (678 )     (22,128 )     (87,403 )
 
                 
Total gross margin (operating revenues less resource costs)
  $ 38,842     $ 60,189     $ 54,207  
 
                 

2004 compared to 2003

Energy Marketing and Resource Management’s net income was $9.7 million for 2004, compared to net income before the cumulative effect of accounting change of $20.7 million for 2003. During 2003, Avista Energy’s earnings were positively impacted by the effects of accounting for energy contracts under SFAS No. 133 and a settlement with certain Enron affiliates. In addition, Avista Energy’s earnings were decreased due to lower natural gas trading margins in 2004 as compared to 2003. These decreases were partially offset by portfolio valuation adjustments at Avista Energy of approximately $2.9 million, net of tax, the most significant of which relates to increases in market liquidity in the Western power markets. Avista Energy’s commodity portfolio was historically valued using third-party broker market quotes for the first 24 months and using a model for the long-term portion of the portfolio. Increased market liquidity has resulted in the availability of reliable and transparent market prices for a longer time period than had previously been available. Based on this change in market liquidity, Avista Energy began utilizing third-party market price quotes for the first 36 months of the portfolio beginning in the fourth quarter of 2004. Avista Energy continues to use a model to estimate forward price curves for the longer-term portion of the portfolio. The Company believes this change in valuation methodology represents the most accurate valuation of the portfolio.

Avista Energy is impacted by earnings volatility associated with the natural gas storage cycle, which runs annually from April through March of the next year. Generally, injections of natural gas into storage inventory take place in the summer months and natural gas is withdrawn from storage in the winter months. Avista Energy hedges the value of natural gas storage with financial and physical sales, effectively locking in a margin on storage. However, accounting rules require the natural gas storage to be carried at the lower of cost or market, while the sales contracts (which are derivatives) are marked-to-market using forward price curves. Changes in forward price curves result in income or losses on the derivative sales contracts, but do not affect the booked values for gas inventory. Therefore, when the month-end forward price curves change disproportionately to the cost of natural gas inventory, Avista Energy experiences earnings volatility. During the third quarter of 2004, natural gas prices increased disproportionately to the prior months’ natural gas prices and negatively impacted Avista Energy’s earnings. This effect was partially reversed in the fourth quarter of 2004. The earnings volatility, as well as the mark-to-market losses associated with the 2004/2005 natural gas storage cycle and the applicable accounting rules discussed above, should fully reverse when the natural gas has been withdrawn from storage. Based on natural gas prices, Avista Energy may elect not to withdraw its natural gas inventory until the first quarter of 2006. As such, the timing difference created may increase during 2005. The accounting treatment does not impact the underlying cash flows or economics of these transactions.

Avista Energy controls natural gas-fired generation through a power purchase agreement with the Lancaster Project. The power purchase agreement gives Avista Energy the right to purchase natural gas for generation, and convert to electricity for a fixed fee. Avista Energy has economically hedged the value of this power purchase agreement by entering into contracts to buy and sell natural gas and electricity. Although the power purchase agreement is not a derivative and not marked-to-market, the contracts to buy and sell natural gas and electricity are derivatives and marked-to-market. Where possible, Avista Energy has designated the natural gas and electricity contracts as accounting hedges in accordance with SFAS No. 133 in order to reduce the earnings volatility associated with these derivative contracts. However, not all of these contracts qualify for hedge accounting. Avista Energy will continue to recognize changes in fair value of those contracts in earnings as unrealized gains and losses. In addition, the ineffective portion of the change in the forward value of qualifying hedges will continue to be recognized in earnings.

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Operating revenues decreased $31.5 million and resource costs decreased $10.1 million for 2004 as compared to 2003 resulting in a decrease in gross margin of $21.4 million. Avista Energy’s gross margin (operating revenues less resource costs) was $38.8 million for 2004 compared to $60.2 million for 2003. The decrease in gross margin was primarily due to the 2003 effects of the transition to SFAS No. 133 and the settlement with Enron affiliates. The transition to SFAS No. 133 resulted in certain contracts with net estimated unrecognized losses of $7.3 million for 2003 not being accounted for at market value. These contracts that are not accounted for at market value were economically hedged by certain other contracts with net unrealized gains for 2003 that are considered derivatives under SFAS No. 133, and as such were recorded at market value with a positive effect on gross margin. The positive effect of the transition to SFAS No. 133 is reversed in future periods as market values change or the contracts are settled and realized. During September 2003, Avista Energy implemented hedge accounting for certain transactions. This has partially mitigated the effects from the transition to SFAS No. 133 and reduced the volatility of reporting earnings on a prospective basis. Avista Energy’s settlement of various positions with Enron affiliates and the resulting release by Avista Energy of amounts, which had been reserved against such positions, also had a positive effect of $8.4 million on gross margin for 2003.

Net realized gains decreased to $39.5 million for 2004 from $82.3 million for 2003. Net realized gains represent the net gains on contracts that have settled. The decrease in net realized gains was due to an increase in the net losses on physical natural gas transactions, the settlement with Enron affiliates in the prior year, decreased net gains on settled financial transactions and decreased net gains on settled foreign currency transactions. This was partially offset by increased net gains on settled physical electric transactions and a change in the net gain on the valuation of natural gas inventory. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized loss of $0.7 million for 2004 compared to a net unrealized loss of $22.1 million for 2003. The change in the net unrealized loss was primarily due to the effects of the transition to SFAS No. 133 described above. The decrease in the net unrealized loss was also due to the settlement of contracts and the realization of previously unrealized gains during 2003. In 2004, portfolio valuation adjustments at Avista Energy resulting primarily from increases in market liquidity in the Western power markets decreased the net unrealized loss and increased gross margin by $4.5 million. During 2004, the change in the total net unrealized gain attributable to market prices and other market changes was $31.7 million, a decrease from $63.2 million for 2003.

2003 compared to 2002

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

Avista Energy’s gross margin (operating revenues less resource costs) was $60.2 million for 2003 compared to $54.2 million for 2002. The increase in gross margin was partially due to the effects of the transition to SFAS No. 133, which resulted in certain contracts with net estimated unrecognized losses of $7.3 million for 2003 not being accounted for at market value. These losses are recognized as the contracts are settled or realized. These contracts that are not accounted for at market value are economically hedged by certain other contracts with unrealized gains for 2003 that are considered derivatives under SFAS No. 133, and as such are recorded at market value with a positive impact on gross margin. The positive effects of the transition to SFAS No. 133 will be reversed in future periods as market values change or the contracts are settled and realized. Avista Energy’s settlement of various positions with Enron affiliates and the resulting release by Avista Energy of amounts, which had been reserved against such positions, also had a positive effect of $8.4 million on gross margin for 2003.

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

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Energy trading activities and positions

The following table summarizes information with respect to Avista Energy’s trading activities during 2004 (dollars in thousands):

                         
    Electric     Natural Gas     Total  
    Assets net of     Assets net of     Unrealized  
    Liabilities     Liabilities     Gain (Loss)  
 
Fair value of contracts as of December 31, 2003
  $ 63,573     $ 10,089     $ 73,662  
Less contracts settled during 2004 (1)
    (76,854 )     37,334       (39,520 )
Fair value of new contracts when entered into during 2004 (2)
                 
Change in fair value due to changes in valuation techniques (3) 
    4,471             4,471  
Change in fair value attributable to market prices and other market changes
    67,775       (36,082 )     31,693  
 
                 
Fair value of contracts as of December 31, 2004
  $ 58,965     $ 11,341     $ 70,306  
 
                 


(1)   Contracts settled during 2004 include those contracts that were open in 2003 but settled during 2004 as well as new contracts entered into and settled during 2004. Amount represents net realized gains associated with these settled transactions.
 
(2)   Avista Energy did not enter into any origination transactions during 2004 in which dealer profit or mark-to-market gain or loss was recorded at inception.
 
(3)   During the second quarter of 2004, Avista Energy refined its methodology used to discount forward settled contracts in order to reflect interest rate risk during varying settlement periods, which increased the fair value $1.1 million. During the fourth quarter of 2004, due to increased market liquidity, Avista Energy refined its electric portfolio valuation methodology to use an additional 12 months of market data, which increased the fair value $3.4 million.

The following table discloses summarized information with respect to valuation techniques and contractual maturities of Avista Energy’s energy commodity contracts outstanding as of December 31, 2004 (dollars in thousands):

                                         
            Greater     Greater                
            than one     than three     Greater          
    Less than     and less than     and less than     than          
    one year     three years     five years     five years     Total  
 
Electric assets (liabilities), net
                                       
Prices from other external sources (1)
  $ 23,455     $ 39,174     $     $     $ 62,629  
Fair value based on valuation models (2)
    (1,685 )     (2,667 )     11,302       (10,614 )     (3,664 )
 
                           
Total electric assets (liabilities), net
  $ 21,770     $ 36,507     $ 11,302     $ (10,614 )   $ 58,965  
 
                             
Natural gas assets (liabilities), net
                                       
Prices from other external sources (1)
  $ 11,395     $ 2,125     $     $     $ 13,520  
Fair value based on valuation models (3)
    (2,460 )     (865 )     1,146             (2,179 )
 
                             
Total natural gas assets (liabilities), net
  $ 8,935     $ 1,260     $ 1,146     $     $ 11,341  
 
                             


(1)   Fair value is determined based upon actively traded, “over-the-counter” market quotes received from third party brokers. These market quotes are used through 36 months.
 
(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 36 months, for which active quotes are not available. These internally developed market curves are determined using a production cost model with inputs for assumptions related to power prices (including, without limitation, natural gas prices, generation on- line, transmission constraints, future demand and weather). Avista Energy performs frequent stress tests on the valuation of the portfolio. While consistent valuation methodologies and updates to the assumptions are used to capture current market information, changes in these methodologies or underlying assumptions could result in significantly different fair values and income recognition. These same pricing techniques and stress tests are used to evaluate a contract prior to taking a position.
 
(3)   Represents contracts for delivery at basis locations not actively traded in the “over-the-counter” markets. In addition, this includes all contracts with a delivery period greater than 36 months, for which active quotes are not available. These internally developed market curves are based upon published New York Mercantile Exchange prices, as well as basis spreads using historical and broker estimates.

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Avista Power

In 2004 and 2003, the Company recorded impairment charges for a turbine and related equipment owned by Avista Power. This resulted in charges of $5.1 million and $4.9 million for 2004 and 2003, respectively, included in operations and maintenance expense. The impact on net income from these impairment charges was $3.3 million and $3.2 million, net of tax, for 2004 and 2003, respectively.

Avista Advantage

2004 compared to 2003

Avista Advantage had net income of $0.6 million for 2004 compared to a net loss of $1.3 million for 2003. Operating revenues for Avista Advantage increased $3.6 million and operating expenses increased $0.5 million as compared to 2003. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage had a 29 percent increase in the number of billed sites as of December 31, 2004 as compared to December 31, 2003. The increase in operating expenses reflects the settlement of an employment contract, partially offset by improved efficiencies and a focus on reducing operating expenses. Avista Advantage’s cost of processing a bill decreased by 11 percent for 2004 as compared to 2003.

2003 compared to 2002

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

Other

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

2004 compared to 2003

The net loss before the cumulative effect of accounting change from this business segment was $7.2 million for 2004 compared to a net loss of $4.9 million for 2003. The increase in the net loss was primarily due to the impairment of goodwill at AM&D, the write-off of an investment in a natural gas storage project, the accrual of an environmental liability at Avista Development and Avista Capital’s purchase of Avista Advantage preferred stock at a premium. This was partially offset by a decrease in the loss from AM&D (excluding the impairment of goodwill) as well as certain other investments of Avista Ventures. Operating revenues from this business segment increased $3.5 million and operating expenses increased $6.8 million, respectively, for 2004 as compared to 2003. The consolidation of several minor entities pursuant to FIN 46 contributed to the increase in operating revenues and operating expenses. The loss from AM&D decreased to $1.0 million for 2004 (excluding the impairment of goodwill), from $2.3 million for 2003.

2003 compared to 2002

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

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Discontinued Operations

In 2003, private equity investors made investments in a new entity, ReliOn, Inc. (formerly AVLB, Inc.), which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. As such, these operations are reported as a discontinued operation.

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

The decrease in the loss from discontinued operations to $4.9 million in 2003 from $6.7 million in 2002 was primarily due to the fact that only six months of operations for Avista Labs are included in 2003, partially offset by $1.1 million of net income for Avista Communications in 2002.

New Accounting Standards

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

Critical Accounting Policies and Estimates

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

Avista Utilities Operating Revenues

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

Regulatory Accounting

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

Avista Utilities Energy Commodity Derivative Assets and Liabilities

Avista Utilities enters into forward contracts to purchase or sell energy. Under these forward contracts, Avista Utilities commits to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. Certain of these forward contracts are considered derivative instruments. Avista Utilities also records derivative commodity assets and liabilities for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered into as part of Avista Utilities’ management of its loads and resources. In conjunction with the issuance of SFAS No. 133, the WUTC and the IPUC issued accounting

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orders authorizing Avista Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The order provides for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM and the PCA mechanism. Quoted market prices and forward price curves are used to estimate the fair value of Avista Utilities’ derivative commodity instruments.

Avista Energy Revenues and Trading Activities

Avista Energy’s derivative commodity instruments accounted for under SFAS No. 133 are marked to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as unrealized gains or losses in the Consolidated Statements of Income in the period of change. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments, which are reported as assets and liabilities on the Consolidated Balance Sheets. These market prices are used through 36 months. Prior to the fourth quarter of 2004, market prices for electric commodity prices were used through 24 months. Increased market liquidity has resulted in the availability of reliable and transparent market prices for a longer time period than had been previously available. For longer-term positions and certain short-term positions for which market prices are not available, models are used to estimate market values. These models incorporate a variety of estimates and assumptions, the ultimate outcomes of which are beyond Avista Energy’s control including, among others, estimates and assumptions as to demand growth, fuel price escalation, availability of existing generation and costs of new generation. Actual experience can vary significantly from these estimates and assumptions.

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

Pension Plans and Other Postretirement Benefit Plans

The Company has a defined benefit pension plan covering substantially all of its regular full-time employees at Avista Utilities and Avista Energy. Individual benefits under this plan are based upon the employee’s years of service and average compensation as specified in the plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company made $15 million in cash contributions to the pension plan in 2004 and $12 million in each of 2003 and 2002. The Company expects to contribute approximately $15 million to the pension plan in 2005. As of December 31, 2004, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. In 2004, the pension plan funding deficit increased as compared to the end of 2003 primarily as a result of a decrease in the discount rate used to measure pension plan liabilities. As such, the Company increased the additional minimum liability for the unfunded accumulated benefit obligation by $9.2 million and decreased the intangible asset by $0.7 million (representing the amount of unrecognized prior service cost) related to the pension plan. This resulted in a charge to other comprehensive income of $6.4 million, net of tax, for 2004.

The Finance Committee of the Company’s Board of Directors establishes investment policies, objectives and strategies to seek optimum return for the pension plan, while also keeping with the assumption of prudent risk and the Finance Committee’s composite return objectives. The Finance Committee reviews and approves changes to the investment policy. The Company has contracted with an investment manager who is responsible for managing the individual investment managers. The investment manager’s performance and related individual fund performance is periodically reviewed by the Finance Committee to ensure compliance with investment policy objectives and

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strategies. Pension plan assets are invested primarily in marketable debt and equity securities. Pension plan assets may also be invested in real estate and other investments, including hedge funds and venture capital funds. In seeking to obtain the desired return to fund the pension plan, the Finance Committee has established investment allocation percentages by asset classes as disclosed in “Note 11 of the Notes to Consolidated Financial Statements.”

The Company’s pension costs (including its Supplemental Executive Retirement Plan (SERP)) were $14.9 million, $16.1 million and $10.3 million for 2004, 2003 and 2002, respectively. Of these pension costs, approximately 70 percent are expensed and approximately 30 percent are capitalized. The Company’s costs for the pension plan are determined in part by actuarial formulas and are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. Pension costs are affected by actual employee demographics (including age, compensation and length of service by employees), the amount of cash contributions the Company makes to the pension plan and the return on pension plan assets. Changes made to the provisions of the pension plan may also impact current and future pension costs. Pension plan costs may also be significantly affected by changes in key actuarial assumptions, including the expected return on pension plan assets, the discount rate used in determining the projected benefit obligation and pension costs, as well as the assumed rate of increase in employee compensation. The change in pension plan obligations associated with these factors may not be immediately recognized as pension costs in the Consolidated Statement of Income, but generally are recognized in future years over the remaining average service period of pension plan participants. As such, costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.

The Company has not made any changes to pension plan provisions in 2004, 2003 and 2002 that have had any significant effect on recorded pension plan amounts. The Company has revised the key assumption of the discount rate in 2004 and 2003. Such change had an effect on reported pension costs in 2004 and 2003 and may have an impact on future years given the cost recognition approach described above. However, in determining pension obligation and cost amounts, assumptions can change from period to period, and such changes could result in material changes to future pension costs and funding requirements.

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

                                 
Actuarial   Change in     Impact on Projected     Impact on     Impact on  
Assumption   Assumption     Benefit Obligation     Pension Liability     Pension Cost  
 
Expected long-term return on plan assets
    -0.5 %   $     $ *   $ 839  
Expected long-term return on plan assets
    +0.5 %           *     (839 )
Discount rate
    -0.5 %     17,817       13,069       1,541  
Discount rate
    +0.5 %     (16,099 )     (11,893 )     (1,409 )


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

In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits. The Company reduced the discount rate in 2004 to 5.75 percent from 6.25 percent. The Company reduced the discount rate in 2003 to 6.25 percent from 6.75 percent. These decreases in discount rates have increased the projected benefit obligation, pension liability and pension costs.

The assumed long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. The assumed long-term rate of return was 8 percent in both 2004 and 2003. For 2004 and 2003, the actual return on plan assets, net of fees, was a gain of $16.1 million (or 10.4 percent) and $32.3 million (or 23.3 percent), respectively. The actual return on plan assets, net of fees, was a loss of $17.4 million (or 11.3 percent) in 2002.

The Company also has a SERP that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $1.8 million, $0.3 million and $0.7 million related to the SERP in 2004, 2003 and 2002, respectively. This resulted in a charge to other comprehensive income of $1.2 million, $0.2 million and $0.5 million, net of tax, for 2004, 2003 and 2002, respectively.

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The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2004 by $2.3 million and the service and interest cost by $0.2 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2004 by $2.0 million and the service and interest cost by $0.2 million.

Contingencies

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

For all material contingencies, the Company has made a judgment as to the probability of the loss occurring and as to whether or not the amount of the loss can be estimated, and, if the loss recognition criteria have been met, liabilities have been accrued or assets have been written down. However, no assurance can be given with respect to the ultimate outcome of any particular contingency.

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Liquidity and Capital Resources

Review of Cash Flow Statement

Continuing Operating Activities Net cash provided by continuing operating activities was $108.3 million for 2004 compared to $122.6 million for 2003. The primary reason for the decrease in net cash provided by continuing operating activities was an increase in net cash used in working capital components, a change in energy commodity assets and liabilities as well as a decrease in net income. This was partially offset by net sales of securities held for trading in 2004 as compared to purchases in 2003 and the fact that non-cash write-offs and impairments were a primary cause for the decrease in net income. Power and natural gas cost amortizations, net of deferrals, were $11.1 million for 2004 compared to $3.8 million for 2003. This was primarily due to decreased deferrals (and a corresponding decrease in cash paid for electric resources) of deferred power costs, partially offset by increased deferrals (and a corresponding increase in cash paid for natural gas purchases) of natural gas costs. The amortization of deferred power and natural gas costs is substantially matched by an increase in cash revenues collected from customers. Increases in cash resource costs paid for power and natural gas costs are substantially matched by additions to deferred power and natural gas costs. Net cash used in working capital components was $89.6 million for 2004, compared to net cash used of $43.0 million for 2003. The net cash used in 2004 primarily reflects a decrease in deposits from counterparties (representing funds returned), which have substituted cash collateral with letters of credit, and an increase in restricted cash (representing cash deposits as collateral for letters of credit). This was partially offset by an increase in accounts payable. The net cash used in 2003 primarily reflects a net decrease in accounts payable. Significant changes in non-cash items included a $21.4 million change in energy commodity assets and liabilities, representing the change from an unrealized loss of $22.1 million on energy trading activities for Avista Energy for 2003 to an unrealized loss of $0.7 million for 2004. This decrease reflects a decrease in realized gains and cash receipts on settled energy commodity transactions at Avista Energy. Significant non-cash items for 2004 also included the write-off and impairment of assets totaling $22.0 million, which is comprised of $12.0 million of deferred power costs, $2.4 million of utility plant costs pursuant to the Idaho general rate case order, asset impairment charges of $5.1 million at Avista Power, goodwill impairment of $1.4 million at AM&D (Other business segment) and $1.1 million representing the write-off of an investment in a natural gas storage project in the Other business segment. The net sales of securities held for trading of $18.9 million (sales of $34.2 million and purchases of $15.3 million) for 2004 represents the investment of cash held at Avista Energy in short-term instruments.

Continuing Investing Activities Net cash used in continuing investing activities was $119.4 million for 2004, an increase compared to $109.8 million for 2003. The increase was primarily due to an increase in utility property capital expenditures and a $5.0 million deposit for the purchase of Coyote Springs 2 in 2004, partially offset by changes in property and investments and an increase in proceeds from the sale of assets.

Continuing Financing Activities Net cash used in continuing financing activities was $28.7 million for 2004 compared to $54.5 million for 2003. During 2004, short-term borrowings decreased $12.0 million, which primarily reflects a decrease in the amount of debt outstanding under Avista Corp.’s line of credit. During 2004, the Company repurchased $36.6 million of long-term debt scheduled to mature in future years at a total premium of $6.7 million, and $30.3 million of debt matured. In November 2004, the Company issued $90.0 million (net proceeds of $89.8 million) of 5.45 percent First Mortgage Bonds due in 2019. During 2004, the Company had $61.9 million of cash inflows and outflows related to the issuance and redemption of long-term debt to affiliated trusts. In 2004, Avista Capital purchased the preferred stock of Avista Advantage at a total price of $4.3 million (including a premium of $0.9 million).

During 2003, short-term borrowings increased $50.5 million, the Company repurchased $52.5 million of long-term debt scheduled to mature in future years at a premium of $1.7 million, and $72.4 million of long-term debt matured. In September 2003, the Company issued $45.0 million (net proceeds of $44.8 million) of 6.125 percent First Mortgage Bonds due in 2013. The increase in short-term borrowings primarily reflects an increase in the amount of debt outstanding under Avista Corp.’s line of credit. The increase in the amount of short-term borrowings reflects decreased cash flows from operations and increased funding needed for capital expenditures, maturing long-term debt and discretionary repurchases of long-term debt scheduled to mature in future years.

Overall Liquidity

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

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The primary source and use of operating cash flows for Avista Energy is revenues and costs from realized energy commodity transactions as well as cash collateral deposited to or held from counterparties. Significant operating cash outflows for Avista Energy also include other operating expenses and taxes.

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

Since 2002, the Company’s overall liquidity has improved compared to 2001. The general rate increases that became effective in 2002, 2003 and 2004 are allowing the Company to continue to improve its liquidity. The 2002 general electric rate increase in Washington provided for the restructuring and continuation of previously approved temporary rate increases totaling 31.2 percent. In 2003, the Company received a general rate increase, designed to increase annual revenues by $6.3 million in Oregon. In September 2004, the Company received general rate increases, designed to increase base annual revenues by $24.7 million for electric and $3.3 million for natural gas service in Idaho. The Idaho base electric rate increase was substantially offset by a decrease in the PCA surcharge and other minor adjustments such that the net increase in revenues is designed to be $3.2 million. However, the increase in base electric rates will have a significant effect on recurring retail revenues and liquidity. In November 2004, a natural gas general rate increase, designed to increase annual revenues by $5.4 million, was implemented in Washington. See further details in the section “Avista Utilities — Regulatory Matters.”

The Company designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, the Company has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities. In 2001, the Company incurred substantial levels of indebtedness, both short and long-term, to fund high power and natural gas costs in addition to these continuing requirements and to otherwise maintain adequate levels of working capital. As a result of improved operating cash flow and other sources of funds, since 2002 through 2004, the Company has repurchased $292.7 million of long-term debt.

When Avista Utilities’ power and natural gas costs exceed the levels currently recovered from retail customers, its net cash flows are negatively affected. Factors that could cause purchased power costs to exceed the levels currently recovered from customers include, but are not limited to, higher prices in wholesale markets combined with an increased need to purchase power in the wholesale markets. Factors beyond the Company’s control that could result in an increased need to purchase power in the wholesale markets include, but are not limited to, increases in demand (either due to weather or customer growth), low availability of hydroelectric resources, outages at generating facilities and failure of third parties to deliver on energy or capacity contracts. Based on forecasts as of March 1, 2005, Avista Utilities expects hydroelectric generation will be approximately 84 percent of normal in 2005 assuming normal precipitation for the remainder of the year. This expectation may change based upon precipitation, temperatures and other variables. The earnings impact of below normal hydroelectric generation is mitigated through power cost deferral and recovery mechanisms in Washington and Idaho. The expected reduction in hydroelectric generation is estimated to have a negative effect on operating cash flows of approximately $25 million from the amount originally forecasted, with approximately $2.5 million impacting pre-tax earnings. Avista Utilities believes that it has adequate liquidity through cash flows generated from operations and funds available under its committed line of credit to meet increased cash requirements for purchased power or fuel as a result of reduced hydroelectric generation.

Capital Resources

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

                                 
    2004     2003  
            Percent             Percent  
    Amount     of total     Amount     of total  
 
Current portion of long-term debt
  $ 85,432       4.4 %   $ 29,711       1.5 %
Short-term borrowings
    68,517       3.5       80,525       4.2  
Long-term debt to affiliated trusts
    113,403       5.8       113,403       5.9  
Long-term debt
    901,556       46.2       925,012       47.9  
 
                       
Total debt
    1,168,908       59.9       1,148,651       59.5  
Preferred stock-cumulative (including current portion)
    29,750       1.5       31,500       1.6  
 
                       
Total liabilities
    1,198,658       61.4       1,180,151       61.1  
Common equity
    753,205       38.6       751,252       38.9  
 
                       
Total
  $ 1,951,863       100.0 %   $ 1,931,403       100.0 %
 
                       

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The Company’s total debt increased from December 31, 2003 to December 31, 2004 due to the issuance of long-term debt, partially offset by a decrease in short-term borrowings and the repurchase and maturity of long-term debt. The Company needs to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund working capital, purchased power and natural gas costs, capital expenditures, dividends and other corporate requirements. The Company’s consolidated common equity increased $2.0 million during 2004 primarily due to net income and the issuance of common stock through the Dividend Reinvestment Plan, partially offset by dividends and other comprehensive loss.

The Company generally funds capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by utility operating activities and cash generated by Avista Energy are expected to be the Company’s primary sources of funds for operating needs, dividends and capital expenditures for 2005. Borrowings under Avista Corp.’s committed line of credit may supplement these funds to the extent necessary.

In April 2004, the Company issued Junior Subordinated Debt Securities, with a principal amount of $61.9 million to AVA Capital Trust III, an affiliated business trust formed by the Company. Concurrently, AVA Capital Trust III issued $60.0 million of Preferred Trust Securities to third parties and $1.9 million of Common Trust Securities to the Company. All of these securities have a fixed interest rate of 6.50 percent for five years (through March 31, 2009). Subsequent to the initial five-year fixed rate period, the securities will either have a new fixed rate or an adjustable rate. These debt securities may be redeemed by the Company on or after March 31, 2009 and will mature on April 1, 2034.

The Company used the proceeds from the Junior Subordinated Debt Securities to redeem $61.9 million of 7.875 percent Junior Subordinated Deferrable Interest Debentures, Series A, originally issued in 1997 to Avista Capital I, an affiliated business trust formed by the Company. Avista Capital I used these proceeds to redeem $60.0 million of Preferred Trust Securities issued to third parties and $1.9 million of Common Trust Securities issued to the Company.

In November 2004, the Company issued $90.0 million of 5.45 percent First Mortgage Bonds due in 2019. The Company used the proceeds to repay a portion of the borrowings outstanding under its committed line of credit.

On December 17, 2004, the Company entered into a five-year committed line of credit with various banks in the amount of $350.0 million with an expiration date of December 16, 2009. This committed line of credit replaced a $350.0 million committed line of credit with a 364-day term that had an expiration date of May 5, 2005. The Company can request the issuance of up to $150.0 million in letters of credit under the committed line of credit. As of December 31, 2004 and 2003, the Company had $68.0 million and $80.0 million, respectively, of borrowings outstanding. As of December 31, 2004 and 2003, there were $32.8 million and $10.7 million in letters of credit outstanding, respectively. The committed line of credit is secured by $350.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit. However, if the Company obtains an investment grade senior unsecured rating with a stable outlook from two nationally recognized rating agencies, it has the option to release such security.

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 greater than 70 percent at the end of any fiscal quarter. As of December 31, 2004, the Company was in compliance with this covenant with a ratio of 59.9 percent. The committed line of credit also has a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the twelve-month period ending December 31, 2004 to be greater than 1.6 to 1. As of December 31, 2004, the Company was in compliance with this covenant with a ratio of 2.27 to 1.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of its significant subsidiaries could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities, and could induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for the Company to obtain financing on reasonable terms to pay creditors or fund operations, and the Company would likely be prohibited from paying dividends on its common stock. Avista Corp. does not guarantee the indebtedness of any of its subsidiaries. As of December 31, 2004, Avista Corp. and its subsidiaries were in compliance with the covenants of all of their financing agreements.

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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, 2004, approximately $304.0 million of additional preferred stock could be issued at an assumed dividend rate of 6.95 percent with a maturity date later than June 1, 2008.

The Mortgage and Deed of Trust securing the Company’s First Mortgage Bonds (including Secured Medium-Term Notes) contains limitations on the amount of First Mortgage Bonds that may be issued based on, among other things, a 70 percent debt-to-collateral ratio, and/or retired First Mortgage Bonds, and a 2 to 1 net earnings to First Mortgage Bond interest ratio. As of December 31, 2004, the Company could issue $400.0 million of additional First Mortgage Bonds under the Mortgage and Deed of Trust.

In April 2004, the Company filed an amended registration statement on Form S-3 with the Securities and Exchange Commission, which would allow for the issuance of up to $349.6 million of securities (either debt or common stock). This filing amended and combined three previous registration statements filed by the Company. As of December 31, 2004, the Company had remaining availability of $259.6 million under this registration statement.

In July, August and December 2004, Avista Corp. entered into three forward-starting interest rate swap agreements, totaling $200.0 million, to manage the risk that changes in interest rates may affect the amount of future interest payments. These interest rate swap agreements relate to the anticipated issuances of debt to fund debt that matures in 2007 and 2008. Under the terms of these agreements, the value of the interest rate swaps are determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of seven years beginning in 2007 and a term of ten years beginning in 2008. The interest rate swap agreements provide for mandatory cash settlement of these contracts in 2008 and 2009. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133. As of December 31, 2004, Avista Corp. had a derivative liability of $6.5 million. An unrealized loss of $4.2 million (net of taxes of $2.3 million) was recorded in other comprehensive loss for 2004, which is reflected as component of accumulated other comprehensive loss on the Consolidated Balance Sheet. The Company may request regulatory accounting orders to defer the impact of unrealized gains and losses. If such accounting orders were obtained, the Company would record a regulatory asset or liability, which would eliminate the effect of any unrealized gains and losses on these interest rate swap agreements in the Consolidated Statements of Comprehensive Income.

In January and February 2005, Avista Corp. redeemed a total of $26.0 million of medium-term notes scheduled to mature in future years.

Inter-Company Debt; Subordination

As part of its on-going cash management practices and operations, Avista Corp. from time to time makes unsecured short-term loans to, and obtains borrowings from, Avista Capital. In turn, Avista Capital from time to time makes unsecured short-term loans to, and obtains borrowings from, its subsidiaries. As of December 31, 2004, Avista Corp. held a short-term subordinated note receivable from Avista Capital in the principal amount of $42.0 million. In addition, Avista Capital from time to time guarantees the indebtedness and other obligations of its subsidiaries. See “Energy Marketing and Resource Management Operations” for further information.

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

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

Pension Plan

As of December 31, 2004, the Company’s pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. The Company does not expect the current pension plan funding deficit to have a material adverse impact on its financial condition, results of operations or cash flows. The

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Company made $15 million in cash contributions to the pension plan in 2004 and $12 million in 2003. The Company expects to make pension plan contributions of $15 million in 2005.

Off-Balance Sheet Arrangements

Avista Receivables Corp. (ARC) is a wholly owned, bankruptcy-remote subsidiary of the Company formed in 1997 for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On May 29, 2002, ARC, the Company and a third-party financial institution entered into a three-year agreement whereby ARC can sell without recourse, on a revolving basis, up to $100.0 million of those receivables. In April 2004, the revolving amount available for sale was reduced to $85.0 million. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. As of December 31, 2004, $72.0 million in receivables were sold pursuant to the revolving agreement. This agreement provides the Company with cost-effective funds for working capital requirements, capital expenditures and other general corporate needs. The Company expects to renew this facility before the May 2005 expiration.

Spokane Energy, LLC

In December 1998, the Company received cash proceeds of $143.4 million from a transaction in which the Company assigned and transferred certain rights under a long-term power sales contract with Portland General Electric Corporation (PGE) to a funding trust. Pursuant to orders from the WUTC and IPUC, this amount was fully amortized by the end of 2002.

Under this power exchange arrangement, Peaker, LLC (Peaker) purchases capacity from Avista Corp. and sells capacity to Spokane Energy LLC (Spokane Energy), an unconsolidated subsidiary of Avista Corp., formed in 1998 solely for the purpose of facilitating a long-term capacity contract between PGE and Avista Corp. Spokane Energy sells the related capacity to PGE. Peaker acts as an intermediary to fulfill certain regulatory requirements between Spokane Energy and Avista Corp. from dealing directly with each other. The transaction is structured such that Spokane Energy bears full recourse risk for a loan (balance of $113.6 million as of December 31, 2004) that matures in January 2015 with no recourse to Avista Corp. related to the loan. Peaker is obligated to pay approximately $150,000 per month to Avista Corp. for its capacity purchase. Peaker was formed solely for the purpose of assuming all rights and obligations from Enron Power Marketing, Inc. (EPMI), which assigned the transactions to Peaker in November 2003 as part of its bankruptcy proceedings. Peaker is not affiliated with EPMI.

Credit Ratings

The following table summarizes the Company’s credit ratings as of February 28, 2005:

                         
    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 II (1)
                       
Preferred Trust Securities
  BB-   Ba2   BB
AVA Capital Trust III (1)
                       
Preferred Trust Securities
  BB-   Ba2   BB
Rating outlook
  Stable   Stable (2)   Stable


(1)   Only assets are subordinated debentures of Avista Corporation.
 
(2)   Changed to stable from negative in March 2004.

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 ratings.

Dividends

The Board of Directors considers the level of dividends on the Company’s common stock on a regular basis, taking into account numerous factors including, without limitation, the Company’s results of operations, cash flows and financial condition, as well as the success of the Company’s strategies and general economic and competitive

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conditions. The Company’s net income available for dividends is derived primarily from the operations of Avista Utilities and Avista Energy.

Covenants under the Company’s 9.75 percent Senior Notes that mature in 2008 limit the Company’s ability to increase its common stock cash dividend to no more than 5 percent over the previous quarter.

On February 11, 2005, the Board of Directors declared a quarterly dividend of $0.135 per common share payable on March 15, 2005 to shareholders of record on February 25, 2005. This is an increase of $0.005 per common share over the previous quarterly dividend declared in November 2004 and the third such increase authorized by the Board of Directors in the last 18 months.

Avista Energy holds a significant portion of cash and cash equivalents reflected on the Consolidated Balance Sheets. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limiting the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. During 2004, Avista Energy paid $2.5 million of dividends to Avista Capital. In March 2005, Avista Energy paid $10.0 million in dividends to Avista Capital.

Avista Utilities Operations

Capital expenditures for Avista Utilities were $281.8 million for the years 2002 through 2004. This excludes Coyote Springs 2, which was included in Energy Marketing and Resource Management for 2002. During the years 2005 through 2007, utility capital expenditures are currently expected to be in the range of $135 million to $150 million per year (excluding the $62.5 million purchase of Coyote Springs 2 in 2005). Long-term debt maturities, mandatory redemptions of preferred stock and sinking fund requirements are expected to total approximately $322 million. During 2005, internally generated funds and short-term borrowing arrangements are expected to be sufficient to fund these requirements with the exception of the maturing $54.6 million of debt for WP Funding LP, which is expected to be refinanced on a long-term basis. In years subsequent to 2005, the Company will most likely need to issue additional long-term debt to fund these obligations. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates due to factors such as changes in business conditions, construction schedules and environmental requirements. Avista Utilities’ planned capital expenditures include an expansion and enhancement of its 230 kV transmission system with estimated remaining costs of approximately $77 million that Avista Utilities expects will be completed by the end of 2007.

Cash deposits from other parties in the net amount of $19.0 million were returned during 2004 because of continuing portfolio value fluctuations with those parties or substitution of collateral. The decrease was primarily the result of the substitution of letters of credit in place of cash collateral.

In January 2005, the Company completed the purchase of Mirant Oregon’s 50 percent ownership interest in Coyote Springs 2 at a price of $62.5 million. See “Note 28 of the Notes to Consolidated Financial Statements” for further information.

In July 2004, Avista Corp. reached an agreement to sell its South Lake Tahoe natural gas distribution properties to Southwest Gas Corporation. The agreed upon cash purchase price for the properties is approximately $15 million, subject to closing adjustments. The Company expects that the transaction will close during the first half of 2005. See “Note 27 of the Notes to Consolidated Financial Statements” for further information.

As of December 31, 2004, Avista Utilities had $2.0 million in cash and temporary investments. Avista Utilities also had $0.6 million of restricted cash as of December 31, 2004 related to Avista Corp.’s interest rate swap agreements.

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

Energy Marketing and Resource Management Operations

On July 23, 2004, Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, amended its committed credit agreement with a group of banks in the aggregate amount of $110.0 million to extend the expiration date to July 22, 2005. This committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties. This facility is guaranteed by Avista Capital and secured by the assets of Avista Energy and Avista Energy Canada. The maximum amount of credit extended by the banks for the issuance of letters of credit is the

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subscribed amount of the facility less the amount of outstanding cash advances, if any. The maximum amount of credit extended by the banks for cash advances is $30.0 million. No cash advances were outstanding as of December 31, 2004. Letters of credit in the aggregate amount of $91.3 million were outstanding as of December 31, 2004. The cash deposits of Avista Energy at the respective banks collateralize $21.5 million of these letters of credit, which is reflected as restricted cash on the Consolidated Balance Sheet.

The Avista Energy credit agreement contains customary covenants and default provisions, including covenants to maintain “minimum net working capital” and “minimum net worth,” as well as a covenant limiting the amount of indebtedness that the co-borrowers may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including VAR limits, restrictions with respect to changes in risk management policies or volumetric limits, and limits on exposure related to hourly and daily trading of electricity. Also, a reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement. These covenants, certain counterparty agreements and current market liquidity conditions result in Avista Energy maintaining certain levels of cash and therefore effectively limit the amount of cash dividends that are available for distribution to Avista Capital and ultimately to Avista Corp. Avista Energy was in compliance with the covenants of its credit agreement as of December 31, 2004.

Avista Capital provides guarantees for Avista Energy’s credit agreement (see discussion above) and, in the course of business, may provide performance guarantees to other parties with whom Avista Energy may be doing business. At any point in time, Avista Capital is only liable for the outstanding portion of the performance guarantee, which was $24.5 million as of December 31, 2004. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $391.7 million as of December 31, 2004.

As part of its cash management practices and operations, Avista Energy from time to time makes unsecured short-term loans to its parent, Avista Capital. Avista Capital’s Board of Directors has limited the total outstanding indebtedness to no more than $45.0 million. Further, as required under Avista Energy’s credit facility, such loans cannot be outstanding longer than 90 days without being repaid. During 2004, Avista Energy’s maximum total outstanding short-term loan to Avista Capital was $40.1 million including accrued interest. As of December 31, 2004, all outstanding loans including accrued interest had been repaid.

Avista Energy manages collateral requirements with counterparties by providing letters of credit, providing guarantees from Avista Capital, depositing cash with counterparties and offsetting transactions with counterparties. Cash deposited with counterparties totaled $30.7 million as of December 31, 2004, which is included in prepayments and other current assets on the Consolidated Balance Sheet. Avista Energy held cash deposits from other parties in the amount of $6.0 million as of December 31, 2004, which is included in cash and cash equivalents with a corresponding amount in deposits from counterparties on the Consolidated Balance Sheet. This is a significant decrease from $78.8 million held at December 31, 2003. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral. The decrease was primarily the result of the substitution of letters of credit in place of cash collateral.

As of December 31, 2004, Avista Energy had $110.3 million in cash, including $25.6 million of restricted cash and $6.0 million of cash deposits from other parties.

During 2004, Avista Energy paid $2.5 million of dividends to Avista Capital. In March 2005, Avista Energy paid $10.0 million in dividends to Avista Capital.

Capital expenditures for the Energy Marketing and Resource Management companies were $21.0 million for the years 2002 through 2004. Capital expenditures in 2002 of $17.5 million were primarily related to Avista Power’s construction of Coyote Springs 2, which was subsequently transferred to Avista Utilities. Capital expenditures are expected to be less than $2.0 million per year in this business segment during the years 2005 through 2007.

Avista Advantage Operations

Capital expenditures for Avista Advantage were $2.4 million for the years 2002 through 2004. Capital expenditures for the years 2005 through 2007 are expected to total approximately $6.5 million and should be funded by Avista Advantage’s cash flows from operations.

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As of December 31, 2004, Avista Advantage had $0.3 million of cash and cash equivalents and $1.7 million in debt was outstanding. Avista Advantage’s outstanding debt is related to capital leases.

Other Operations

Capital expenditures for these companies were $2.0 million for the years 2002 through 2004. Capital expenditures for the years 2005 through 2007 are expected to be less than $1.0 million per year. As of December 31, 2004, this business segment had $1.4 million of cash and cash equivalents and $7.8 million in debt was outstanding. The outstanding debt includes long-term debt, short-term borrowings and capital leases.

Contractual Obligations

The following table provides a summary of the Company’s future contractual obligations as of December 31, 2004 (dollars in millions):

                                                 
    2005     2006     2007     2008     2009     Thereafter  
 
Avista Utilities:
                                               
Long-term debt maturities (1)
  $ 84     $ 38     $ 176     $ 326     $     $ 352  
Long-term debt to affiliated trusts (1)
                                  113  
Interest on debt (2)
    89       87       83       77       72        
Short-term borrowings (3)
    68                                
Accounts receivable sales (4)
    72                                
Preferred stock redemptions (1)
    2       2       26                    
Energy purchase contracts (5)
    270       143       151       141       136       750  
Public Utility District contracts (5)
    4       3       3       3       3       20  
Operating lease obligations (6)
    4       4       3       3       3       7  
Capital lease obligations (6)
    1       1       1       1              
Other obligations (7)
    15       15       15       15       15       177  
Information services contracts
    12       12       11       11       11       32  
Pension plan funding (9)
    15       15       15       12              
Avista Capital (consolidated):
                                               
Long-term debt
                                  7  
Short-term borrowings
    1                                
Energy purchase contracts (8)
    650       283       179       191       180       523  
Operating lease obligations (6)
    2       2       2       2       2        
Capital lease obligations (6)
          1       1                    
     
 
                                               
Total contractual obligations
  $ 1,289     $ 606     $ 666     $ 782     $ 422     $ 1,981  
     


(1)   For 2005, the Company expects that cash flows from operations and short-term debt will provide sufficient funds for maturing long-term debt and preferred stock redemptions, with the exception of the maturing $54.6 million of debt for WP Funding LP, which the Company expects to refinance on a long-term basis. However, if market conditions warrant during 2005, the Company may issue long-term debt to fund these obligations and potentially repurchase long-term debt scheduled to mature in future years to reduce its overall debt service costs. In years subsequent to 2005, the Company will most likely need to issue additional long-term debt to fund these obligations.
 
(2)   Represents the Company’s estimate of interest payments on debt. The Company will make interest payments beyond 2009; however, the Company has not made an estimate of such payments at this time.
 
(3)   Represents $68 million outstanding under a $350 million five-year revolving line of credit. Although the Company is not contractually obligated to repay the amount borrowed until 2009, it is expected that borrowings outstanding as of December 31, 2004 will be repaid in 2005. However, additional borrowings will be made on the revolving line of credit during 2005 as well.
 
(4)   Represents $72 million outstanding under a revolving $85 million accounts receivable sales financing facility.
 
(5)   Energy purchase contracts were entered into as part of Avista Utilities’ obligation to serve its retail natural gas and electric customers’ energy requirements. As a result, these costs are generally recovered either through base retail rates or adjustments to retail rates as part of the power and natural gas cost adjustment mechanisms.
 
(6)   Includes the interest component of the lease obligation.
 
(7)   Represents operational agreements, settlements and other contractual obligations with respect to generation, transmission and distribution facilities. These costs are generally recovered through base retail rates.

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(8)   Represents Avista Energy’s contractual commitments to purchase energy commodities as well as commitments related to transmission, transportation and other energy-related contracts in future periods. Avista Energy also has sales commitments related to these contractual obligations in future periods.
 
(9)   Represents the Company’s estimated cash contributions to the pension plan through 2008. The Company cannot reasonably estimate pension plan contributions beyond 2008 at this time.

As of December 31, 2004, Avista Corp. did not have any commitments outstanding with equity triggers. Avista Corp. does not expect any material impact from rating triggers; although there are certain rating triggers for Avista Corp. primarily related to changes in pricing under certain financing agreements. A reduction in the credit rating of Avista Corp. would represent an event of default under Avista Energy’s credit agreement.

Competition

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

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

Participants in the wholesale market include other utilities, federal power marketing agencies, energy marketing and trading companies, and independent power producers. The electric wholesale market continues to change with respect to the number and types of market participants involved, volume of buying and selling activity, price volatility, market liquidity, regulatory initiatives and challenges in regulatory and legal arenas, and credit strength by market participants. Starting in 2000 and the first half of 2001, the electric wholesale market in the WECC region was marked by significant volatility, service disruptions and defaults by certain participants. During the second half of 2001 and 2002, wholesale market prices decreased to levels similar to those experienced before 2000. Wholesale market prices increased in 2003 and 2004 compared to 2002; however, prices have not increased to levels experienced during 2000 and the first half of 2001. Although market conditions generally improved during 2004, many energy companies are facing liquidity issues, and counterparty credit exposure is of concern to market participants. Multiple legal and regulatory challenges have been initiated particularly with respect to the turbulence of 2000 and 2001; several of these legal and regulatory matters remain unresolved (see “Note 25 of the Notes to Consolidated Financial Statements”). Avista Corp. actively monitors and participates as appropriate in energy industry developments to maintain and enhance its ability to effectively participate in electric wholesale markets consistent with its business goals.

The subsidiaries in the non-energy businesses, particularly Avista Advantage, are subject to competition as they develop products and services and enter new markets. It is also a challenge for Avista Advantage to maintain its current customer base. Competition from other companies in these non-energy businesses may mean challenges for a company to be the first to market a new product or service to gain the advantage in market share. Challenges for these businesses include the availability of funding and resources to meet capital needs, rapidly advancing technologies, possibly making some of the current technology quickly obsolete, and requiring continual product enhancement.

Business Risk

The Company’s operations are exposed to risks including, but not limited to, the price and supply of purchased power, fuel and natural gas, regulatory allowance of the recovery of power and natural gas costs, operating costs and capital investments, streamflow and weather conditions, the effects of changes in legislative and governmental regulations, changes in regulatory requirements, availability of generation facilities, competition, technology and availability of

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funding. Also, like other utilities, the Company’s facilities and operations may be exposed to terrorism risks or other malicious acts. See further reference to risks and uncertainties under “Forward-Looking Statements.”

Avista Utilities has mechanisms in each regulatory jurisdiction, which provide for the recovery of the majority of the changes in its power and natural gas costs. The majority of power and natural gas costs that exceed the amount currently recovered through retail rates, excluding the $9.0 million threshold for power costs in Washington, are deferred on the Consolidated Balance Sheets for the opportunity of recovery through future retail rates. These deferred power and natural gas costs are subject to review for prudence and recoverability and as such certain deferred costs may be disallowed by the respective regulatory agencies.

Hydroelectric generation was 95 percent of normal in 2004 and 89 percent of normal in 2003. Forecasts as of March 1, 2005 indicate that hydroelectric generation will be approximately 84 percent of normal in 2005 assuming normal precipitation for the remainder of the year. This forecast may change based upon precipitation, temperatures and other variables. The earnings impact of these factors is mitigated by regulatory mechanisms that are intended to defer increased power supply costs for recovery in future periods. Avista Utilities is not able to predict how the combination of energy resources, energy loads, prices, rate recovery and other factors will ultimately drive deferred power costs and the timing of recovery of these costs in future periods. See further information at “Avista Utilities — Regulatory Matters.”

Challenges facing Avista Utilities’ electric operations include, among other things, the timing and approval of the recovery of deferred power costs, changes in the availability of and volatility in the prices of power and fuel, generating unit availability, legislative and governmental regulations, potential tax law changes, customer response to price increases and surcharges, streamflows and weather conditions.

During recent years, natural gas prices have been volatile with a general upward trend. Avista Utilities’ average prices per dekatherm were $6.62, $5.50 and $4.95 in 2004, 2003 and 2002, respectively. Market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. Avista Utilities believes that natural gas should sustain its market advantage over competing energy sources based on the levels of existing reserves and the potential for natural gas development in the future. Growth has occurred in the natural gas business in recent years due to increased demand for natural gas in new construction, as well as conversions from competing space and water heating energy sources to natural gas.

Challenges facing Avista Utilities’ natural gas operations include, among other things, volatility in the price of natural gas, changes in the availability of natural gas, legislative and governmental regulations, weather conditions and the timing and approval of recovery for increased commodity costs. Avista Utilities’ natural gas business also faces the potential for certain natural gas customers to by-pass its natural gas system. To reduce the potential for such by-pass, Avista Utilities prices its natural gas services, including transportation contracts, competitively and has varying degrees of flexibility to price its transportation and delivery rates by means of individual contracts, subject to state regulatory review and approval. Avista Utilities has long-term transportation contracts with several of its largest industrial customers, which reduces the risk of these customers by-passing the system in the foreseeable future.

In addition to its asset management activities, Avista Energy trades electricity and natural gas, along with derivative commodity instruments, including futures, options, swaps and other contractual arrangements. As a result of these trading activities, Avista Energy is subject to various risks including commodity price risk and credit risk, as well as possible risks resulting from the imposition of market controls by federal and state agencies. The FERC is conducting proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds. As a result, certain parties have asserted claims for significant refunds from Avista Energy and lesser refunds from Avista Utilities, which could result in liabilities for refunding revenues recognized in prior periods. Avista Energy and Avista Utilities have joined other parties in opposing these proposals. The refund proceedings provide that any refunds owed could be offset against unpaid energy debts due to the same party. As of December 31, 2004, Avista Energy’s accounts receivable outstanding related to defaulting parties in California are fully offset by reserves for uncollected amounts and funds collected from defaulting parties. Avista Energy is pursuing recovery of the defaulted obligations. See “Counterparty Defaults,” “California Refund Proceeding” and “Pacific Northwest Refund Proceeding” in “Note 25 of the Notes to Consolidated Financial Statements” for further information with respect to the refund proceedings.

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

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Commodity Price Risk. Both Avista Utilities and Avista Energy are subject to energy commodity price risk. Price risk is, in general, the risk of fluctuation in the market price of the commodity needed, held or traded. The price of energy in wholesale markets is affected primarily by fundamental factors related to production costs and by other factors including weather and the resulting retail loads. In the case of electricity, prices can be affected by the adequacy of generating reserve margins, scheduled and unscheduled outages of generating facilities, availability of streamflows for hydroelectric generation, the price of thermal generating plant fuel, and disruptions or constraints to transmission facilities, among other things. Natural gas prices are affected by a number of factors, including, but not limited to, the adequacy of North American production, the level of imports, the level of inventories, global energy markets, and the availability of pipeline capacity to transport natural gas from region to region. In addition, oil prices can influence natural gas prices, because of fuel-switching capabilities of certain energy users. Demand changes caused by variations in the weather and other factors can also affect market prices. Any combination of these factors that results in a shortage of energy generally causes the market price of power to move upward. In addition to these factors, wholesale power markets are subject to regulatory constraints including price controls. The FERC imposed a price mitigation plan in the western United States in June 2001 and has subsequently modified various price and market control regulations.

Price risk 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 since the second half of 2001 relative to 2000 and the first half of 2001.

Credit Risk. Credit risk relates to the risk of loss that Avista Utilities and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. Avista Utilities and Avista Energy often extend credit to counterparties and customers. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it and the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, Avista Utilities or Avista Energy may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.

Avista Utilities and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by actively monitoring current credit exposures. These policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees, and the use of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty. However, despite mitigation efforts, defaults by counterparties periodically occur. Avista Energy experienced payment receipt defaults from certain parties impacted by the California energy crisis. Both Avista Corp. and Avista Energy engaged in considerable business and had short-term and long-term contracts with entities that have filed for bankruptcy protection. These bankruptcies and other changes, uncertainties and regulatory proceedings have resulted in reduced liquidity in the energy markets.

A trend of declining credit quality was evident during 2002 and continued into 2003 and 2004, particularly throughout the energy industry. Rating agencies have downgraded the credit ratings of several of the counterparties of Avista Energy and Avista Utilities. Avista Energy and Avista Utilities regularly evaluate counterparties’ credit exposure for future settlements and delivery obligations. Avista Energy and Avista Utilities have taken a conservative position by reducing or eliminating open (unsecured) credit limits and implemented other credit risk reduction measures for parties perceived to have increased default risk. Counterparty collateral is used to offset the Company’s credit risk where unsettled net positions and future obligations by counterparties to pay Avista Utilities and/or Avista Energy or deliver to Avista Utilities and/or Avista Energy warrant.

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

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

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

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

Interest Rate Risk. The Company is subject to the risk of fluctuating interest rates in the normal course of business. The Company manages interest rate risk by taking advantage of market conditions when timing the issuance of long-term financings and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market conditions. Additionally, amounts borrowed under the Company’s $350.0 million five-year committed line of credit have a variable interest rate.

In 2004, Avista Corp. entered into three forward-starting interest rate swap agreements, totaling $200.0 million, to manage the risk that changes in interest rates may affect the amount of future interest payments. These interest rate swap agreements relate to the anticipated issuances of debt to fund maturing debt in 2007 and 2008. Under the terms of these agreements, the value of the interest rate swaps are determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133. As of December 31, 2004, Avista Corp. had a derivative liability of $6.5 million and provided cash collateral of $0.6 million to the interest rate swap counterparties related to these interest rate swaps. The Company estimates that a 10 basis point increase in forward LIBOR interest rates as of December 31, 2004 would have decreased this derivative liability by approximately $1.3 million, while a 10 basis point decrease would have increased the liability by approximately $1.3 million.

Foreign Currency Risk. Avista Energy has investments in Canadian companies through Avista Energy Canada and its subsidiary, CoPac Management, Inc. In addition, Avista Energy enters into Canadian dollar denominated transactions in Canada for gas commodity and related services. These transactions in aggregate expose Avista Energy to foreign currency risk. Avista Energy attempts to limit its exposure to changing foreign exchange rates through both operational and financial market actions. This includes entering into forward and swap contracts to hedge existing exposures, firm commitments and anticipated transactions. These arrangements are carried at fair value and were not significant as of December 31, 2004. Also, Avista Utilities will begin to have foreign currency risk as natural gas procurement operations are implemented. This is not expected to have a material effect on Avista Utilities’ financial condition, results of operations or cash flows.

Risk Management

Risk Policies and Oversight. Avista Utilities and Avista Energy use a variety of techniques to manage risks for their energy resources and wholesale energy market activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative, for Avista Utilities and Avista Energy. The Company’s Risk Management Committee establishes the Company’s risk management policies and procedures and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other individuals and is

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overseen by the Audit Committee of the Company’s Board of Directors. The Company’s Risk Management Committee reviews the status of risk exposures through regular reports and meetings and it monitors compliance with the Company’s risk management policies and procedures on a regular basis. Nonetheless, adverse changes in commodity prices, generating capacity, customer loads, regulation and other factors may result in losses in earnings, cash flows and/or fair values.

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

Quantitative Risk Measurements. Avista Utilities measures the monthly, quarterly and annual energy volume of its imbalance between projected power loads and resources. Normal operations result in seasonal mismatches between power loads and available resources. Avista Utilities is able to vary the operation of its generating resources to match parts of its hourly, daily and weekly load fluctuations. Avista Utilities uses the wholesale power markets to sell projected resource surpluses and obtain resources when deficits are projected. Avista Utilities buys and sells fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating its available generating facilities.

Load/resource imbalances within a rolling 18-month planning horizon are compared against established volumetric guidelines and management determines the timing and specific actions to manage the imbalances. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods. Expected load and resource volumes for forward periods are based on monthly and quarterly averages that may vary materially from the actual loads and resources within any individual month or operating day. Future projections of resources are updated as forecasted streamflows and other factors differ from prior estimates. Forward power markets may be illiquid, and market products available may not match Avista Utilities’ desired transaction size and shape. Therefore, open imbalance positions exist at any given time.

Avista Utilities’ natural gas loads and resources are regularly reviewed by operating management and the Risk Management Committee. The balancing of loads and resources is accomplished through commodity purchases and the use of natural gas storage facilities owned by, or contracted with, Avista Utilities. Timing, pricing and volume decisions are subject to the Avista Utilities’ hedging practices that include a cross-departmental oversight group.

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

As of December 31, 2004, Avista Energy’s estimated potential one-day unfavorable impact on gross margin as measured by VAR was $0.4 million, compared to $0.7 million as of December 31, 2003. The average daily VAR for 2004 was $0.5 million. The high daily VAR was $0.8 million and the low daily VAR was $0.4 million during 2004. Avista Energy was in compliance with its one-day VAR limits during 2004. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

As of December 31, 2004, 88 percent of Avista Corp.’s credit exposure was to investment grade counterparties or noninvestment grade counterparties whose exposure was mitigated by collateral posted to Avista Corp. Of the remaining unmitigated exposure to non-investment grade counterparties, 10 percent represents settlements that were made within thirty days after December 31, 2004.

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As of December 31, 2004, 94 percent of Avista Energy’s credit exposure was to investment grade counterparties or noninvestment grade counterparties whose exposure was mitigated through collateral posted to Avista Energy. Of the remaining unmitigated exposure to non-investment grade counterparties, approximately 84 percent represents settlements that were made within thirty days after December 31, 2004.

Economic and Load Growth

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

Avista Utilities anticipates retail electric load growth to average between 2.0 and 3.0 percent annually for the next four years, primarily due to expected population increases and business growth in its service territory. While the number of electric customers is expected to increase, the average annual usage by each residential customer is not expected to change significantly. For the next four years, Avista Utilities expects natural gas load growth to average between 4.0 and 4.5 percent annually in its Washington and Idaho service territory and 2.5 and 3.0 percent in its Oregon service territory. The natural gas load growth is primarily expected through conversions to natural gas from competing space and water heating energy sources, and population increases and business growth in Avista Utilities’ service territories. Natural gas loads for space heating vary significantly with annual fluctuations in weather within Avista Utilities’ service territories.

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 actual experience can vary significantly from forward-looking projections.

Management Succession and Employee Issues

Protecting the Company’s culture, mission, and long-term strategy by having a strong succession planning and management development process is one of the key strategic initiatives at Avista Corp. The Company’s executive officer team continues to work towards ensuring that an effective succession planning process is in place for the best interests of the Company’s future. The Company has implemented bench strength analysis in its management group as well as in key technical and craft areas. The focus is on organizational leadership capability as well as technical proficiency in complex jobs. The Company has implemented development plans for its future successors that identify areas of strengths and weaknesses. Development plans provide action steps that provide new opportunities to work towards ensuring that successor candidates have the needed experience for running the Company. The Company believes that its succession planning process is providing the right structure to assure that the Company has the ability to fill vacancies with personnel having adequate training and experience.

Environmental Issues and Other Contingencies

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

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

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

Item 8. Financial Statements and Supplementary Data

The Report of Independent Registered Public Accounting Firm and Financial Statements begin on the next page.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Avista Corporation and subsidiaries
Spokane, Washington

We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, 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, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Avista Corporation and subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As described in Note 2 to the consolidated financial statements (“Note 2”), during 2004, the Company was required to consolidate a partnership as well as several low-income housing project investments related to the adoption of Financial Accounting Standards Board (“FASB”) Interpretation No. 46(R). Additionally, during 2003, as described in Note 1 to the consolidated financial statements (“Note 1”), the Company changed its method of accounting for energy trading activities related to the transition from Emerging Issues Task Force Issue No. 98-10 to Statement of Financial Accounting Standards (“SFAS”) No. 133, and, as described in Note 2, was required to consolidate WP Funding LP, and deconsolidate the capital trusts related to the adoption of FASB Interpretation No. 46. Additionally, as described in Note 2, during 2003, the Company changed its classification of preferred stock to conform to the requirements of SFAS No. 150. Additionally, as described in Note 1 to the consolidated financial statements, during 2002, the Company changed its method of accounting for goodwill to conform to SFAS No. 142.

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We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Seattle, Washington
March 9, 2005

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CONSOLIDATED STATEMENTS OF INCOME
Avista Corporation


For the Years Ended December 31
Dollars in thousands, except per share amounts
                         
    2004     2003     2002  
OPERATING REVENUES
  $ 1,151,580     $ 1,123,385     $ 1,062,916  
 
                 
OPERATING EXPENSES:
                       
Resource costs
    604,984       576,492       536,714  
Operations and maintenance
    155,944       138,058       125,930  
Administrative and general
    104,266       97,494       105,647  
Depreciation and amortization
    78,425       77,811       71,867  
Taxes other than income taxes
    67,491       61,827       65,616  
 
                 
Total operating expenses
    1,011,110       951,682       905,774  
 
                 
INCOME FROM OPERATIONS
    140,470       171,703       157,142  
 
                 
OTHER INCOME (EXPENSE):
                       
Interest expense
    (87,265 )     (91,505 )     (104,866 )
Interest expense to affiliated trusts
    (5,782 )     (1,480 )      
Capitalized interest
    1,393       1,092       7,486  
 
                 
Net interest expense
    (91,654 )     (91,893 )     (97,380 )
Other income — net
    8,390       6,173       17,261  
 
                 
Total other income (expense)-net
    (83,264 )     (85,720 )     (80,119 )
 
                 
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
    57,206       85,983       77,023  
INCOME TAXES
    21,592       35,340       34,849  
 
                 
INCOME FROM CONTINUING OPERATIONS
    35,614       50,643       42,174  
 
                 
DISCONTINUED OPERATIONS (Note 3):
                       
Loss before asset impairment charges, minority interest and income taxes
          (4,029 )     (10,461 )
Asset impairment charges
          (3,905 )      
Minority interest
                241  
Income tax benefit
          2,985       3,501  
 
                 
LOSS FROM DISCONTINUED OPERATIONS
          (4,949 )     (6,719 )
 
                 
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE
    35,614       45,694       35,455  
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (net of tax)
    (460 )     (1,190 )     (4,148 )
 
                 
NET INCOME
    35,154       44,504       31,307  
DEDUCT-Preferred stock dividend requirements
          1,125       2,402  
 
                 
INCOME AVAILABLE FOR COMMON STOCK
  $ 35,154     $ 43,379     $ 28,905  
 
                 
Weighted-average common shares outstanding (thousands), Basic
    48,400       48,232       47,823  
Weighted-average common shares outstanding (thousands), Diluted
    48,886       48,630       47,874  
EARNINGS PER COMMON SHARE, BASIC (Note 23):
                       
Earnings per common share from continuing operations
  $ 0.74     $ 1.03     $ 0.83  
Loss per common share from discontinued operations
          (0.10 )     (0.14 )
 
                 
Earnings per common share before cumulative effect of accounting change
    0.74       0.93       0.69  
Loss per common share from cumulative effect of accounting change
    (0.01 )     (0.03 )     (0.09 )
 
                 
Total earnings per common share, basic
  $ 0.73     $ 0.90     $ 0.60  
 
                 
EARNINGS PER COMMON SHARE, DILUTED (Note 23):
                       
Earnings per common share from continuing operations
  $ 0.73     $ 1.02     $ 0.83  
Loss per common share from discontinued operations
          (0.10 )     (0.14 )
 
                 
Earnings per common share before cumulative effect of accounting change
    0.73       0.92       0.69  
Loss per common share from cumulative effect of accounting change
    (0.01 )     (0.03 )     (0.09 )
 
                 
Total earnings per common share, diluted
  $ 0.72     $ 0.89     $ 0.60  
 
                 
Dividends paid per common share
  $ 0.515     $ 0.490     $ 0.480  
 
                 

The Accompanying Notes are an Integral Part of These Statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Avista Corporation


For the Years Ended December 31
Dollars in thousands
                         
    2004     2003     2002  
NET INCOME
  $ 35,154     $ 44,504     $ 31,307  
 
                 
OTHER COMPREHENSIVE INCOME (LOSS):
                       
Foreign currency translation adjustment
    493       931       8  
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $(1,969), $51 and $(677), respectively
    (3,656 )     94       (1,258 )
Unfunded accumulated benefit obligation - net of taxes of $(4,086), $5,097 and $(9,736), respectively
    (7,589 )     9,466       (18,081 )
Unrealized gains (losses) on derivative commodity instruments - net of taxes of $(681) and $1,245, respectively
    (1,264 )     2,313        
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(257) and $(258), respectively
    (477 )     (480 )      
Unrealized investment losses - net of taxes of $(655)
                (1,217 )
Reclassification adjustment for net realized losses on investments - net of taxes of $152
                283  
 
                 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
    (12,493 )     12,324       (20,265 )
 
                 
COMPREHENSIVE INCOME
  $ 22,661     $ 56,828     $ 11,042  
 
                 

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
                 
    2004     2003  
 
               
ASSETS:
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 88,317     $ 128,126  
Restricted cash
    26,175       16,472  
Securities held for trading
          18,903  
Accounts and notes receivable-less allowances of $44,193 and $46,382, respectively
    325,755       318,848  
Energy commodity assets
    284,231       253,676  
Materials and supplies, fuel stock and natural gas stored
    26,108       22,428  
Deferred income taxes
    12,288       11,455  
Assets held for sale
    28,479        
Other current assets
    108,989       93,671  
 
           
Total current assets
    900,342       863,579  
 
           
 
               
NET UTILITY PROPERTY:
               
Utility plant in service
    2,666,445       2,606,012  
Construction work in progress
    51,260       49,615  
 
           
Total
    2,717,705       2,655,627  
Less: Accumulated depreciation and amortization
    761,642       741,626  
 
           
Total net utility property
    1,956,063       1,914,001  
 
           
 
               
OTHER PROPERTY AND INVESTMENTS:
               
Investment in exchange power-net
    35,933       38,383  
Non-utility properties and investments-net
    78,564       89,133  
Non-current energy commodity assets
    254,657       242,359  
Investment in affiliated trusts
    13,403       13,403  
Other property and investments-net
    19,721       17,958  
 
           
Total other property and investments
    402,278       401,236  
 
           
 
               
DEFERRED CHARGES:
               
Regulatory assets for deferred income tax
    123,159       131,763  
Other regulatory assets
    39,044       44,381  
Non-current utility energy commodity derivative assets
    55,825       34,517  
Power and natural gas deferrals
    148,206       171,342  
Unamortized debt expense
    53,413       48,825  
Other deferred charges
    25,493       30,431  
 
           
Total deferred charges
    445,140       461,259  
 
           
 
               
TOTAL ASSETS
  $ 3,703,823     $ 3,640,075  
 
           

The Accompanying Notes are an Integral Part of These Statements.

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CONSOLIDATED BALANCE SHEETS (continued)
Avista Corporation

 
As of December 31
Dollars in thousands
                 
    2004     2003  
LIABILITIES AND STOCKHOLDERS’ EQUITY:
               
CURRENT LIABILITIES:
               
Accounts payable
  $ 325,194     $ 298,285  
Energy commodity liabilities
    253,527       229,642  
Deposits from counterparties
    6,015       97,811  
Current portion of long-term debt
    85,432       29,711  
Current portion of preferred stock-cumulative (17,500 shares outstanding)
    1,750       1,750  
Short-term borrowings
    68,517       80,525  
Interest accrued
    18,632       18,504  
Other current liabilities
    114,973       96,324  
 
           
Total current liabilities
    874,040       852,552  
 
           
 
               
 
           
LONG-TERM DEBT
    901,556       925,012  
 
           
 
               
 
           
LONG-TERM DEBT TO AFFILIATED TRUSTS
    113,403       113,403  
 
           
 
               
PREFERRED STOCK-CUMULATIVE (subject to mandatory redemption):
               
10,000,000 shares authorized: $6.95 Series K
               
 
           
280,000 and 297,500 shares outstanding ($100 stated value), respectively
    28,000       29,750  
 
           
 
               
OTHER NON-CURRENT LIABILITIES AND DEFERRED CREDITS:
               
Non-current energy commodity liabilities
    215,055       192,731  
Regulatory liability for utility plant retirement costs
    175,575       167,061  
Non-current utility energy commodity derivative liabilities
    33,490       33,060  
Deferred income taxes
    488,471       492,799  
Other non-current liabilities and deferred credits
    121,028       82,455  
 
           
Total other non-current liabilities and deferred credits
    1,033,619       968,106  
 
           
 
               
 
           
TOTAL LIABILITIES
    2,950,618       2,888,823  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (See Notes to Consolidated Financial Statements)
               
 
               
STOCKHOLDERS’ EQUITY:
               
Common stock, no par value; 200,000,000 shares authorized; 48,471,511 and 48,344,009 shares outstanding
    629,056       626,788  
Note receivable from employee stock ownership plan
    (495 )     (2,424 )
Capital stock expense and other paid in capital
    (10,677 )     (10,950 )
Accumulated other comprehensive loss
    (20,533 )     (8,040 )
Retained earnings
    155,854       145,878  
 
           
TOTAL STOCKHOLDERS’ EQUITY
    753,205       751,252  
 
           
 
               
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 3,703,823     $ 3,640,075  
 
           

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
                         
    2004     2003     2002  
CONTINUING OPERATING ACTIVITIES:
                       
Net income
  $ 35,154     $ 44,504     $ 31,307  
Loss from discontinued operations
          4,949       6,719  
Cumulative effect of accounting change
    460       1,190       4,148  
Purchases of securities held for trading
    (15,260 )     (18,865 )      
Sales of securities held for trading
    34,192              
Non-cash items included in net income:
                       
Depreciation and amortization
    78,425       77,811       71,867  
Provision for deferred income taxes
    19,168       28,395       (40,287 )
Power and natural gas cost amortizations, net of deferrals
    11,087       3,829       68,481  
Amortization of debt expense
    8,301       7,972       8,861  
Write-offs and impairments of assets
    21,990       4,900        
Energy commodity assets and liabilities
    678       22,128       87,403  
Other
    3,770       (11,214 )     (10,763 )
Changes in working capital components:
                       
Restricted cash
    (9,703 )     (3,489 )     (11,783 )
Sale of customer accounts receivable under revolving agreement-net
          7,000       (10,000 )
Accounts and notes receivable
    (6,904 )     (4,485 )     80,342  
Materials and supplies, fuel stock and natural gas stored
    (4,023 )     (682 )     (717 )
Other current assets
    (10,102 )     (15,251 )     (21,906 )
Accounts payable
    26,909       (41,352 )     (27,770 )
Deposits from counterparties
    (91,796 )     5,137       76,954  
Other current liabilities
    5,996       10,087       14,004  
 
                 
NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES
    108,342       122,564       326,860  
 
                 
 
                       
CONTINUING INVESTING ACTIVITIES:
                       
Utility property capital expenditures (excluding AFUDC)
    (115,346 )     (102,271 )     (64,207 )
Other capital expenditures
    (3,126 )     (3,388 )     (18,873 )
Deposit for utility property acquisition
    (5,000 )            
Changes in other property and investments
    1,041       (5,724 )     1,418  
Repayments received on notes receivable
    1,062       1,214       33,752  
Proceeds from property sales and sale of subsidiary investments
    2,466       549       586  
Assets acquired and investments in subsidiaries
    (524 )     (229 )     (461 )
 
                 
NET CASH USED IN CONTINUING INVESTING ACTIVITIES
    (119,427 )     (109,849 )     (47,785 )
 
                 

The Accompanying Notes are an Integral Part of These Statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Increase (Decrease) in Cash and Cash Equivalents
Avista Corporation

 
For the Years Ended December 31
Dollars in thousands
                         
    2004     2003     2002  
CONTINUING FINANCING ACTIVITIES:
                       
Increase (decrease) in short-term borrowings
  $ (12,008 )   $ 50,525     $ (45,099 )
Proceeds from issuance of long-term debt
    89,761       44,795       621  
Redemption and maturity of long-term debt
    (66,857 )     (124,859 )     (204,014 )
Proceeds from issuance of long-term debt to affiliated trusts
    61,856              
Redemption of long-term debt to affiliated trusts
    (61,856 )            
Premiums paid for the redemption of long-term debt
    (6,710 )     (1,709 )     (9,456 )
Long-term debt and short-term borrowing issuance costs
    (6,024 )     (2,430 )     (6,534 )
Redemption of preferred stock
    (1,750 )     (1,575 )     (1,750 )
Issuance of common stock
    4,061       5,497       7,035  
Repurchase of subsidiary preferred stock
    (4,285 )            
Cash dividends paid
    (24,912 )     (24,777 )     (25,456 )
 
                 
NET CASH USED IN CONTINUING FINANCING ACTIVITIES
    (28,724 )     (54,533 )     (284,653 )
 
                 
 
                       
NET CASH USED IN CONTINUING OPERATIONS
    (39,809 )     (41,818 )     (5,578 )
 
                       
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS
          (3,342 )     8,967  
 
                 
 
                       
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (39,809 )     (45,160 )     3,389  
 
                       
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
    128,126       173,286       169,897  
 
                 
 
                       
CASH AND CASH EQUIVALENTS AT END OF PERIOD
  $ 88,317     $ 128,126     $ 173,286  
 
                 
 
                       
SUPPLEMENTAL CASH FLOW INFORMATION:
                       
Cash paid during the period:
                       
Interest
  $ 84,220     $ 86,755     $ 95,801  
Income taxes
    11,321       11,476       7,428  
Non-cash financing and investing activities:
                       
Property and equipment purchased under capital leases
    1,365       5,312        
Unrealized gain (loss) on interest rate swap agreements
    (5,625 )     145       (1,936 )
Intangible asset related to pension plan
    (654 )     (654 )     6,366  
Unfunded accumulated benefit obligation
    (11,022 )     15,198       (34,164 )
Unrealized gain (loss) on derivative commodity instruments
    (2,677 )     2,819        
Unrealized investment losses
                (1,436 )

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
                                                                         
                                    Note                          
                                    Receivable     Capital     Accumulated              
    Preferred Stock                     from Employee     Stock Expense     Other              
    Series K     Common Stock     Stock     and Other     Comprehensive     Retained        
    Shares     Amount     Shares     Amount     Ownership Plan     Paid-in Capital     Income (Loss)     Earnings     Total  
 
Balance as of December 31, 2001
    350,000     $ 35,000       47,632,678     $ 617,737     $ (5,679 )   $ (11,924 )   $ (99 )   $ 120,028     $ 755,063  
 
Net income
                                                            31,307       31,307  
Equity compensation plan transactions
                    2,730       74               (4 )                     70  
Employee Investment Plan (401-K)
                    227,585       3,046                                       3,046  
Dividend Reinvestment Plan
                    181,215       2,235                                       2,235  
Redemption of preferred stock
    (17,500 )     (1,750 )                                                     (1,750 )
Repayments of note receivable
                                    1,533                               1,533  
Other comprehensive loss
                                                    (20,265 )             (20,265 )
Cash dividends paid (common stock)
                                                            (22,955 )     (22,955 )
Cash dividends paid (preferred stock)
                                                            (2,402 )     (2,402 )
ESOP dividend tax savings
                                                            159       159  
 
Balance as of December 31, 2002
    332,500     $ 33,250       48,044,208     $ 623,092     $ (4,146 )   $ (11,928 )   $ (20,364 )   $ 126,137     $ 746,041  
 
Net income
                                                            44,504       44,504  
Equity compensation plan transactions
                            (147 )             219               (145 )     (73 )
Employee Investment Plan (401-K)
                    130,603       1,462                                       1,462  
Dividend Reinvestment Plan
                    169,198       2,381                                       2,381  
Redemption of preferred stock
    (17,500 )     (1,750 )                             175                       (1,575 )
Repayments of note receivable
                                    1,722                               1,722  
Other comprehensive income
                                                    12,324               12,324  
Cash dividends paid (common stock)
                                                            (23,634 )     (23,634 )
Cash dividends paid (preferred stock)
                                                            (1,125 )     (1,125 )
ESOP dividend tax savings
                                                            141       141  
Cumulative effect of accounting change
    (315,000 )     (31,500 )                             584                       (30,916 )
 
Balance as of December 31, 2003
                48,344,009     $ 626,788     $ (2,424 )   $ (10,950 )   $ (8,040 )   $ 145,878     $ 751,252  
 
Net income
                                                            35,154       35,154  
Equity compensation plan transactions
                            316               273               (409 )     180  
Dividend Reinvestment Plan
                    127,502       1,952                                       1,952  
Repayments of note receivable
                                    1,929                               1,929  
Other comprehensive loss
                                                    (12,493 )             (12,493 )
Cash dividends paid (common stock)
                                                            (24,912 )     (24,912 )
ESOP dividend tax savings
                                                            143       143  
 
Balance as of December 31, 2004
                48,471,511     $ 629,056     $ (495 )   $ (10,677 )   $ (20,533 )   $ 155,854     $ 753,205  
 

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
                         
    2004     2003     2002  
OPERATING REVENUES:
                       
Avista Utilities
  $ 972,574     $ 928,211     $ 893,964  
Energy Marketing and Resource Management
    275,646       307,141       222,634  
Avista Advantage
    23,444       19,839       16,911  
Other
    17,127       13,581       14,645  
Intersegment eliminations
    (137,211 )     (145,387 )     (85,238 )
 
                 
Total operating revenues
  $ 1,151,580     $ 1,123,385     $ 1,062,916  
 
                 
 
                       
RESOURCE COSTS:
                       
Avista Utilities
  $ 505,391     $ 474,927     $ 453,525  
Energy Marketing and Resource Management
    236,804       246,952       168,427  
Intersegment eliminations
    (137,211 )     (145,387 )     (85,238 )
 
                 
Total resource costs
  $ 604,984     $ 576,492     $ 536,714  
 
                 
 
                       
GROSS MARGINS (operating revenues less resource costs):
                       
Avista Utilities
  $ 467,183     $ 453,284     $ 440,439  
Energy Marketing and Resource Management
    38,842       60,189       54,207  
 
                 
Total gross margins (operating revenues less resource costs)
  $ 506,025     $ 513,473     $ 494,646  
 
                 
 
                       
OPERATIONS AND MAINTENANCE EXPENSES:
                       
Avista Utilities
  $ 123,223     $ 107,697     $ 97,668  
Energy Marketing and Resource Management
    5,067       4,900        
Avista Advantage
    11,374       11,813       13,569  
Other
    16,280       13,648       14,693  
 
                 
Total operations and maintenance expenses
  $ 155,944     $ 138,058     $ 125,930  
 
                 
 
                       
ADMINISTRATIVE AND GENERAL EXPENSES:
                       
Avista Utilities
  $ 70,806     $ 65,951     $ 63,751  
Energy Marketing and Resource Management
    19,676       22,950       21,820  
Avista Advantage
    8,426       6,705       6,736  
Other
    5,358       1,888       13,340  
 
                 
Total administrative and general expenses
  $ 104,266     $ 97,494     $ 105,647  
 
                 
 
                       
DEPRECIATION AND AMORTIZATION EXPENSES:
                       
Avista Utilities
  $ 72,787     $ 72,068     $ 66,243  
Energy Marketing and Resource Management
    1,364       1,259       1,227  
Avista Advantage
    1,902       2,652       2,968  
Other
    2,372       1,832       1,429  
 
                 
Total depreciation and amortization expenses
  $ 78,425     $ 77,811     $ 71,867  
 
                 
 
                       
INCOME FROM OPERATIONS:
                       
Avista Utilities
  $ 134,073     $ 146,777     $ 149,180  
Energy Marketing and Resource Management
    11,681       30,078       29,211  
Avista Advantage
    1,742       (1,331 )     (6,363 )
Other
    (7,026 )     (3,821 )     (14,886 )
 
                 
Total income from operations
  $ 140,470     $ 171,703     $ 157,142  
 
                 

The Accompanying Notes are an Integral Part of These Statements.

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SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS (continued)
Avista Corporation

 
For the Years Ended December 31
Dollars in thousands
                         
    2004     2003     2002  
INTEREST EXPENSE (INCLUDING INTEREST EXPENSE TO AFFILIATED TRUSTS):
                       
Avista Utilities
  $ 92,068     $ 91,908     $ 103,597  
Energy Marketing and Resource Management
    528       1,009       7,126  
Avista Advantage
    874       742       763  
Other
    1,008       1,025       5,403  
Intersegment eliminations
    (1,431 )     (1,699 )     (12,023 )
 
                 
Total interest expense (including interest expense to affiliated trusts)
  $ 93,047     $ 92,985     $ 104,866  
 
                 
 
                       
INCOME TAXES:
                       
Avista Utilities
  $ 18,383     $ 26,884     $ 32,137  
Energy Marketing and Resource Management
    5,421       11,457       12,311  
Avista Advantage
    334       (718 )     (2,289 )
Other
    (2,546 )     (2,283 )     (7,310 )
 
                 
Total income taxes
  $ 21,592     $ 35,340     $ 34,849  
 
                 
 
                       
INCOME FROM CONTINUING OPERATIONS:
                       
Avista Utilities
  $ 32,467     $ 36,241     $ 36,382  
Energy Marketing and Resource Management
    9,733       20,672       22,425  
Avista Advantage
    577       (1,334 )     (4,253 )
Other
    (7,163 )     (4,936 )     (12,380 )
 
                 
Total income from continuing operations
  $ 35,614     $ 50,643     $ 42,174  
 
                 
 
                       
ASSETS:
                       
Avista Utilities
  $ 2,600,357     $ 2,532,936     $ 2,369,418  
Energy Marketing and Resource Management
    1,002,843       1,013,213       1,349,626  
Avista Advantage
    47,318       45,621       31,733  
Other
    53,305       48,305       42,866  
Discontinued Operations
                5,900  
 
                 
Total assets
  $ 3,703,823     $ 3,640,075     $ 3,799,543  
 
                 
 
                       
CAPITAL EXPENDITURES:
                       
Avista Utilities (excluding AFUDC)
  $ 115,346     $ 102,271     $ 64,207  
Energy Marketing and Resource Management
    1,455       2,013       17,531  
Avista Advantage
    840       459       1,109  
Other
    831       916       233  
 
                 
Total capital expenditures
  $ 118,472     $ 105,659     $ 83,080  
 
                 

The Accompanying Notes are an Integral Part of These Statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in western Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington, northern Idaho, northeast and southwest Oregon and in the South Lake Tahoe region of California. In July 2004, the Company entered into an agreement to sell its South Lake Tahoe natural gas distribution properties (see Note 27 for further information), which is subject to regulatory approval. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments.

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

Basis of Reporting

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

Use of Estimates

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

System of Accounts

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

Regulation

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

Business Segments

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

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Avista Utilities Operating Revenues

Operating revenues for Avista Utilities related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is estimated and the corresponding unbilled revenue is estimated and recorded. Accounts receivable includes unbilled energy revenues of $13.0 million (net of $48.9 million of unbilled receivables sold) and $9.0 million (net of $47.0 million of unbilled receivables sold) as of December 31, 2004 and 2003, respectively. See Note 5 for information with respect to the sale of accounts receivable.

Avista Energy Operating Revenues

Avista Energy follows Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, with respect to the majority of its contracts. Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts that are not derivatives under SFAS No. 133, as well as derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Revenues derived from Canadian contracts through Avista Energy Canada, which are not held for trading, and are reported on gross basis in operating revenues, totaled $116.0 million, $107.1 million and $78.2 million in 2004, 2003 and 2002, respectively. During 2003, Avista Energy recorded as a cumulative effect of accounting change a charge of $1.2 million (net of tax) related to Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which effectively required the transition of accounting for energy trading activities from EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” to SFAS No. 133.

Research and Development Expenses

Company-sponsored research and development expenditures are expensed as incurred. Research and development expenses did not exceed $0.1 million for 2004 and totaled $0.4 million and $3.8 million in 2003 and 2002, respectively. The expenses for 2003 and 2002 primarily related to the activities of Avista Labs and are included in discontinued operations.

Advertising Expenses

The Company expenses advertising costs as incurred. Advertising expenses totaled $1.9 million, $1.4 million and $1.3 million in 2004, 2003 and 2002, respectively.

Taxes other than income taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers are recorded as both operating revenue and expense and totaled $35.0 million, $31.7 million and $33.1 million in 2004, 2003 and 2002, respectively.

Other Income-Net

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

                         
    2004     2003     2002  
 
Interest income
  $ 4,313     $ 4,810     $ 7,716  
Interest on power and natural gas deferrals
    7,855       8,361       9,597  
Net gain (loss) on the disposition of non-operating assets
    785       (334 )     (33 )
Net gain (loss) on investments
    434       (1,207 )     2,084  
Premium on repurchase of subsidiary preferred stock
    (892 )            
Other expense
    (6,854 )     (7,063 )     (6,570 )
Other income
    2,749       1,606       4,467  
 
                 
Total
  $ 8,390     $ 6,173     $ 17,261  
 
                 

Income Taxes

The Company and its eligible subsidiaries file consolidated federal income tax returns. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Company’s federal income tax returns were examined with all issues resolved, and all payments made, through the 2000 return. The Internal Revenue Service is currently examining the Company’s 2001, 2002 and 2003 federal income tax returns.

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The Company accounts for income taxes under SFAS No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, 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. Deferred tax liabilities and regulatory assets have been established for tax benefits flowed through to customers as prescribed by the respective regulatory commissions.

Stock-Based Compensation

The Company follows the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, employee stock options are accounted for under Accounting Principle Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Stock options are granted at exercise prices not less than the fair value of common stock on the date of grant. Under APB No. 25, no compensation expense is recognized pursuant to the Company’s stock option plans. See Note 2 with respect to the revision of SFAS No. 123, which will result in the recognition of compensation expense beginning in the third quarter of 2005.

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

                         
    2004     2003     2002  
 
Net income (dollars in thousands):
                       
As reported
  $ 35,154     $ 44,504     $ 31,307  
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of tax
    2,033       2,186       3,051  
 
                 
Pro forma
  $ 33,121     $ 42,318     $ 28,256  
 
                 
Basic earnings per common share:
                       
As reported
  $ 0.73     $ 0.90     $ 0.60  
Pro forma
  $ 0.68     $ 0.85     $ 0.54  
Diluted earnings per common share:
                       
As reported
  $ 0.72     $ 0.89     $ 0.60  
Pro forma
  $ 0.68     $ 0.85     $ 0.54  

Comprehensive Income (Loss)

The Company’s comprehensive income (loss), which is reported net of tax, is comprised of net income, foreign currency translation adjustments, changes in the unfunded accumulated benefit obligation for the pension plan, unrealized gains and losses on interest rate swap agreements, unrealized gains and losses on derivative commodity instruments and unrealized gains and losses on investments available-for-sale. Accumulated other comprehensive income (loss), net of tax, consisted of the following as of December 31 (dollars in thousands):

                 
    2004     2003  
 
Foreign currency translation adjustment
  $ 1,139     $ 646  
Unfunded accumulated benefit obligation for the pension plan
    (16,944 )     (9,355 )
Unrealized loss on interest rate swap agreements
    (4,820 )     (1,164 )
Unrealized gain on derivative commodity instruments
    92       1,833  
 
           
Total accumulated other comprehensive loss
  $ (20,533 )   $ (8,040 )
 
           

Foreign Currency Translation Adjustment

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

Earnings Per Common Share

Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share is calculated by dividing income available for common stock by diluted weighted average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares

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are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options, contingently issuable shares and restricted stock. See Note 23 for earnings per common share calculations.

Cash and Cash Equivalents

For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity when purchased of three months or less to be cash equivalents. Cash and cash equivalents include cash deposits from counterparties. See Note 8 for further information with respect to cash deposits from counterparties.

Restricted Cash

Restricted cash includes bank deposits of $21.5 million and $15.0 million as collateral for letters of credit issued under Avista Energy’s credit agreement as of December 31, 2004 and 2003, respectively. See Note 16 for further information with respect to Avista Energy’s credit agreement. Restricted cash also includes deposits held in trust of $1.6 million and $1.5 million for certain employees of Avista Energy as part of a bonus retention plan as of December 31, 2004 and 2003, respectively. In addition, restricted cash as of December 31, 2004, includes $2.5 million of deposits related to forward contracts at Avista Energy and $0.6 million of deposits related to Avista Corp.’s interest rate swap agreements. See Note 17 for further information with respect to Avista Corp.’s interest rate swap agreements.

Securities held for trading

Securities held for trading represent the investment of cash held at Avista Energy in short-term instruments and are recorded at fair value on the Consolidated Balance Sheets with realized and unrealized gains and losses included in the Consolidated Statements of Income. Realized gains, realized losses and net unrealized gains were not material for 2004 and 2003. The Company did not have any securities held for trading as of December 31, 2004. The cost basis of such securities approximated the fair value of $18.9 million as of December 31, 2003. The Company did not have any securities held for trading during 2002.

Allowance for Doubtful Accounts

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

                         
    2004     2003     2002  
 
Allowance as of the beginning of the year
  $ 46,382     $ 46,909     $ 50,211  
Additions expensed during the year
    3,367       1,912       3,469  
Net deductions
    (5,556 )     (2,439 )     (6,771 )
 
                 
Allowance as of the end of the year
  $ 44,193     $ 46,382     $ 46,909  
 
                 

Materials and supplies, fuel stock and natural gas stored

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

Assets held for sale

Assets held for sale are recorded at the lower of cost or estimated fair value less selling costs. As of December 31, 2004, assets held for sale included $15.2 million of assets related to Avista Utilities’ South Lake Tahoe natural gas distribution properties and $13.3 million of turbines and related equipment. Liabilities held for sale were not significant as of December 31, 2004.

Utility Plant in Service

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

Allowance for Funds Used During Construction

The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. In accordance with the uniform system of accounts prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt

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related portion is credited currently as a non-cash item in the Consolidated Statements of Income in the line item capitalized interest. The Company generally is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a fair return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC generally does not occur until the related utility plant is placed in service and included in rate base.

The effective AFUDC rate was 9.72 percent for 2004, 2003 and the second half of 2002 and 9.03 percent for the first half of 2002. The Company’s AFUDC rates do not exceed the maximum allowable rates as determined in accordance with the requirements of regulatory authorities.

Depreciation

For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing unit rates for generation plants and composite rates for other utility plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. The rates for hydroelectric plants include annuity and interest components, in which the interest component is 9 percent. For utility operations, the ratio of depreciation provisions to average depreciable property was 2.92 percent in 2004, 2.98 percent in 2003 and 2.92 percent in 2002.

The average service lives for the following broad categories of utility property are: electric thermal production — 30 years; hydroelectric production — 77 years; electric transmission — 43 years; electric distribution — 47 years; and natural gas distribution property — 35 years.

The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense. The Company had estimated retirement costs of $175.6 million and $167.1 million included as a regulatory liability on the Consolidated Balance Sheets as of December 31, 2004 and 2003, respectively. These costs do not represent legal or contractual obligations.

Goodwill

Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a discounted cash flow model on at least an annual basis or more frequently if impairment indicators arise. Goodwill is included in non-utility properties and investments-net on the Consolidated Balance Sheets and totaled $6.2 million ($5.2 million in the Other business segment and $1.0 million in Energy Marketing and Resource Management) and $7.5 million ($6.6 million in the Other business segment and $0.9 million in Energy Marketing and Resource Management) as of December 31, 2004 and 2003, respectively. The Company completed its annual evaluation of goodwill for potential impairment during the first quarter of 2004 and determined that goodwill was not impaired at that time.

Based on a revised financial forecast, which indicated in a decline in the performance and value of a reporting unit in the Other business segment, the Company performed an evaluation of goodwill for that reporting unit in December 2004. The Company determined that $1.4 million of goodwill was impaired, which is included in administrative and general expense in the Consolidated Statement of Income. The Company used a discounted cash flow model based on a multiple of earnings before interest, taxes, depreciation and amortization to estimate the fair value of this business unit.

On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that goodwill no longer be amortized. Accordingly, the Company determined that $4.1 million (net of tax) of goodwill was impaired and recorded this as a cumulative effect of accounting change for 2002.

Regulatory Deferred Charges and Credits

The Company prepares its consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The Company prepares its financial statements in accordance with SFAS No. 71 because (i) the Company’s rates for regulated services are established by or subject to approval by an independent third-party regulator; (ii) the regulated rates are designed to recover the Company’s cost of providing the regulated services; and (iii) in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover the Company’s costs. SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its financial statements. SFAS No. 71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) are reflected as deferred charges on the Consolidated Balance Sheets. These costs and/or obligations are not reflected in the statement of income until the period during which matching revenues are recognized. If at some point in the future the Company

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determines that it no longer meets the criteria for continued application of SFAS No. 71 with respect to all or a portion of the Company’s regulated operations, the Company could be required to write-off its regulatory assets. The Company could also be precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the Company expected to recover such costs in the future.

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

                 
    2004     2003  
 
Regulatory asset for consolidation of variable interest entity
  $ 19,167     $ 16,707  
Regulatory asset for postretirement benefit obligation
    3,782       4,255  
Demand side management and conservation programs
    13,792       19,683  
Other
    2,303       3,736  
 
           
Total
  $ 39,044     $ 44,381  
 
           

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

Regulatory assets that are not currently included in rate base, being recovered in current rates or earning a return (accruing interest), totaled $22.4 million as of December 31, 2004. The most significant of these assets was the $19.2 million regulatory asset for the consolidation of a variable interest entity (WP Funding LP). Avista Utilities’ lease payments to WP Funding LP of $4.5 million are being recovered in current rates; the regulatory asset primarily represents the accumulated difference between depreciation expense on the plant and the principal payments made on the debt obligation (see Note 2), which will be reversed in future periods as debt principal payments are made.

Investment in Exchange Power-Net

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

Unamortized Debt Expense

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

Natural Gas Benchmark Mechanism

The Idaho Public Utilities Commission (IPUC), WUTC and Oregon Public Utility Commission (OPUC) approved Avista Utilities’ Natural Gas Benchmark Mechanism in 1999. The mechanism eliminated the majority of natural gas procurement operations within Avista Utilities and placed responsibility for natural gas procurement operations with Avista Energy, the Company’s non-regulated subsidiary. The ownership of the natural gas assets remains with Avista Utilities; however, the assets have been managed by Avista Energy through an Agency Agreement. Avista Utilities has continued to manage natural gas procurement for its California operations, which the Company has entered into an agreement to sell (see Note 27).

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In the first quarter of 2002, the IPUC and the OPUC approved the continuation of the Natural Gas Benchmark Mechanism and related Agency Agreement through March 31, 2005. In February 2004, the WUTC ordered that the Natural Gas Benchmark Mechanism and related Agency Agreement be terminated for Washington customers and ordered Avista Utilities to file a transition plan to move management of these functions back into Avista Utilities. In April 2004, the WUTC approved Avista Utilities’ transition plan, which provides for the movement of these functions back into Avista Utilities to be completed by March 31, 2005. Effective April 1, 2005, the Company will also be moving these functions from Avista Energy to Avista Utilities for Idaho and Oregon natural gas customers with the expiration of the current agreements.

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

Power Cost Deferrals and Recovery Mechanisms

Avista Utilities defers the recognition in the income statement of certain power supply costs as approved by the WUTC. Deferred power supply costs are recorded as a deferred charge on the Consolidated Balance Sheets for future review and the opportunity for recovery through retail rates. The power supply costs deferred include certain differences between actual power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in power supply costs primarily results from changes in short-term wholesale market prices, changes in the level of hydroelectric generation and changes in the level of thermal generation (including changes in fuel prices). Avista Utilities accrues interest on deferred power costs in the Washington jurisdiction at a rate, which is adjusted semi-annually, of 8.4 percent as of December 31, 2004. Total deferred power costs for Washington customers were $113.2 million and $125.7 million as of December 31, 2004 and 2003, respectively.

In Washington, the Energy Recovery Mechanism (ERM) allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM provides for Avista Utilities to incur the cost of, or receive the benefit from, the first $9.0 million in annual power supply costs above or below the amount included in base retail rates. Under the ERM, 90 percent of annual power supply costs exceeding or below the initial $9.0 million are deferred for future surcharge or rebate to Avista Utilities’ customers. The remaining 10 percent of power supply costs are an expense of, or benefit to, the Company.

Under the ERM, Avista Utilities makes an annual filing to provide the opportunity for the WUTC and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. In August 2004, the WUTC issued an order, which approved the recovery of $22.8 million of deferred power costs incurred in 2003.

Avista Utilities has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the authorized level of net power supply expense approved in the last Idaho general rate case. Avista Utilities accrues interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 1.0 percent on current year deferrals and 3.0 percent on carryover balances as of December 31, 2004. In October 2004, the IPUC issued its final order with respect to general electric and natural gas rate cases filed by Avista Utilities in Idaho. The final order required Avista Utilities to write off a total of $12.0 million (recorded as resource costs in the Consolidated Statements of Income) of certain deferred power costs, including associated accrued interest, related to natural gas contracts entered into by Avista Utilities to provide fuel for its generating facilities. The IPUC authorized the recovery of the remaining deferred power costs over a two-year period through a PCA rate surcharge to customers. Total deferred power costs for Idaho customers were $9.5 million and $30.3 million as of December 31, 2004 and 2003, respectively.

Natural Gas Cost Deferrals and Recovery Mechanisms

Under established regulatory practices in each respective state, Avista Utilities is allowed to adjust its natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs already included in retail rates are deferred and charged or credited to expense when regulators approve inclusion of the cost changes in rates. Total deferred natural gas costs were $28.6 million (including $3.1 million related to California operations, which is classified as an asset held for sale) and $15.4 million as of December 31, 2004 and 2003, respectively.

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Intersegment Eliminations

Intersegment eliminations are reported in operating revenues, resource costs and interest expense in the Schedule of Information by Business Segments. Intersegment eliminations reported as operating revenues and resource costs represent the transactions between Avista Utilities and Avista Energy for energy commodities and services, primarily natural gas purchased by Avista Utilities under the Agency Agreement. Intersegment eliminations reported as interest expense represent intercompany interest.

Reclassifications

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

NOTE 2. NEW ACCOUNTING STANDARDS

In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This statement requires the Company to classify certain financial instruments as liabilities that have historically been classified as equity. This statement requires the Company to classify as a liability financial instruments that are subject to mandatory redemption at a specified or determinable date or upon an event that is certain to occur. This statement was effective for financial instruments entered into or modified after May 31, 2003, and otherwise was effective at the beginning of the first interim period beginning after June 15, 2003. The restatement of financial statements for prior periods was not permitted. The adoption of this statement required the Company to classify preferred stock subject to mandatory redemption as a liability on the Consolidated Balance Sheets. The adoption of this statement also required the Company to classify preferred stock dividends subsequent to July 1, 2003 as interest expense in the Consolidated Statements of Income.

In July 2003, the EITF reached consensus on Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as Defined in EITF Issue No. 02-3.” This EITF Issue requires that revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) should be reported on a net basis as part of operating revenues effective October 1, 2003. Derivatives not held for trading purposes at Avista Energy are reported gross, unless they are “booked out” or the economic substance indicates that net reporting is appropriate. The adoption of this EITF Issue resulted in a reduction in operating revenues and resource costs of approximately $26.4 million for 2004 as compared to 2003 for Avista Utilities.

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

FIN 46 required the Company to consolidate WP Funding LP effective for the period ended December 31, 2003 and thereafter. WP Funding LP is an entity that was formed in 1993 for the purpose of acquiring the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT). WP Funding LP purchased the Rathdrum CT from the Company with funds provided by unrelated investors of which 97 percent represented debt and 3 percent represented equity. The Company operates the Rathdrum CT and leases it from WP Funding LP. The total amount of WP Funding LP debt outstanding was $54.6 million as of December 31, 2004 and 2003. The lease term expires in February 2020; however, the current debt matures in October 2005 and will need to be refinanced at that time. As of December 31, 2004, the book value of the debt and equity of WP Funding LP exceeded the book value of the Rathdrum CT by $19.2 million. In accordance with regulatory accounting practices, the Company recorded this amount as a regulatory asset upon the consolidation of WP Funding LP. The addition of the Rathdrum CT, which entered commercial operation in 1995, to Avista Utilities’ generation resource base was reviewed in

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previous state regulatory filings with the WUTC and IPUC.

FIN 46 also resulted in the Company no longer including the capital trusts formed for the purpose of issuing preferred trust securities in its consolidated financial statements for the period ended December 31, 2003 and thereafter. The capital trusts are considered variable interest entities under the provisions of FIN 46. As Avista Corp. is not the primary beneficiary, these entities are no longer included in Avista Corp.’s consolidated financial statements. The sole assets of the capital trusts are $113.4 million of junior subordinated deferrable interest debentures of Avista Corp. and the deconsolidation of these entities resulted in these debentures being reflected on the Consolidated Balance Sheets. Interest expense to affiliated trusts in the Consolidated Statements of Income represents interest expense on these debentures.

Additionally, the implementation of FIN 46, as revised in December 2003, resulted in the Company including a partnership as well as several low-income housing project investments held in the Other business segment in its consolidated financial statements for 2004. This resulted in a charge of $0.5 million recorded as a cumulative effect of accounting change for 2004.

See Note 11 for a discussion of a FASB Staff Position with respect to postretirement medical benefit obligations.

In December 2004, the FASB issued SFAS No. 123R, “Accounting for Stock-Based Compensation,” which supersedes APB No. 25 and its related implementation guidance. This statement establishes standards for the accounting for transactions in which the Company exchanges its equity instruments for goods or services with a primary focus on transactions in which the Company obtains employee services in share-based payment transactions. The statement requires that the compensation cost relating to share-based payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. The Company will be required to implement the provisions of this statement beginning in the third quarter of 2005. The Company expects to record compensation expense (net of tax) of approximately $0.5 million in 2005 and $0.3 million in 2006 related to the periodic vesting of stock options granted to employees in prior years. As the Company is not currently granting stock options to employees, the prospective provisions of this statement are not expected to have a material effect on the Company’s future financial condition, results of operations or cash flows.

NOTE 3. DISCONTINUED OPERATIONS

In 2003, private equity investors made investments in a new entity, ReliOn, Inc. (formerly AVLB, Inc.), which acquired the assets previously held by Avista Corp.’s fuel cell manufacturing and development subsidiary, Avista Labs. Avista Corp.’s investment in ReliOn, Inc. is accounted for under the cost method. Revenues for Avista Labs were $0.7 million and $0.7 million in 2003 (through June 30) and 2002, respectively.

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

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

                         
    Avista Labs     Avista Communications     Total  
 
Income (loss) before income taxes
  $ (12,960 )   $ 2,499     $ (10,461 )
Minority interest
    241             241  
Income tax benefit (expense)
    4,855       (1,354 )     3,501  
 
                 
Income (loss) from discontinued operations
  $ (7,864 )   $ 1,145     $ (6,719 )
 
                 

NOTE 4. IMPAIRMENT OF ASSETS

During the third quarter of 2004, the Company recorded an impairment charge for a turbine and related equipment owned by Avista Power (Energy Marketing and Resource Management segment). This charge of $5.1 million is included in operations and maintenance expense in the Consolidated Statements of Income. The Company originally planned to use four turbines in a non-regulated generation project. Due to changing market conditions during 2001, the Company decided to no longer pursue the development of this project and reached an agreement to sell three of the turbines. During 2002, 2003 and the first three quarters of 2004, the Company explored various options for use of the fourth turbine. At the end of the third quarter of 2004, the Company reached a conclusion to

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sell the turbine and related equipment, which are classified as assets held for sale on the Consolidated Balance Sheet as of December 31, 2004. The Company evaluated the carrying value of the turbine and related equipment and recorded an impairment charge to adjust the book value of these assets to estimated fair value less selling costs.

During the fourth quarter of 2003, the Company recorded an impairment charge for the turbine owned by Avista Power (see discussion above). This charge of $4.9 million for 2003 is included in operations and maintenance expense in the Consolidated Statements of Income.

NOTE 5. ACCOUNTS RECEIVABLE SALE

Avista Receivables Corp. (ARC) 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. On May 29, 2002, ARC, the Company and a third-party financial institution entered into a three-year agreement whereby ARC can sell without recourse, on a revolving basis, up to $100.0 million of those receivables. In April 2004, the revolving amount available for sale was reduced to $85.0 million. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in operating expenses of the Company. As of December 31, 2004 and 2003, $72.0 million in accounts receivables were sold under this revolving agreement.

NOTE 6. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

SFAS No. 133, as amended by SFAS No. 138 and SFAS No. 149, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recording of all derivatives as either assets or liabilities on the balance sheet measured at estimated fair value and the recognition of the unrealized gains and losses. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.

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

Prior to the adoption of SFAS No. 149 on July 1, 2003, Avista Utilities elected the normal purchases and sales exception for substantially all of its contracts for both capacity and energy under SFAS No. 133. As such, Avista Utilities was not required to record these contracts as derivative commodity assets and liabilities. Under SFAS No. 149, substantially all new forward contracts to purchase or sell power and natural gas used for generation, which were entered into on or after July 1, 2003, are recorded as assets or liabilities at market value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for at cost until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary. Utility energy commodity derivatives consisted of the following as of December 31 (dollars in thousands):

                 
    2004     2003  
 
Current utility energy commodity derivative asset
  $ 10,199     $ 4,983  
Current utility energy commodity derivative liability
    5,713       2,997  
Net current regulatory liability
    4,486       1,986  
Non-current utility energy commodity derivative asset
    55,825       34,517  
Non-current utility energy commodity derivative liability
    33,490       33,060  
Net non-current regulatory liability
    22,335       1,457  

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Current utility energy commodity derivative assets are included in other current assets on the Consolidated Balance Sheets. Current utility energy commodity derivative liabilities and the offsetting net current regulatory liability are included in other current liabilities on the Consolidated Balance Sheets. The offsetting net non-current regulatory liability is included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets.

NOTE 7. ENERGY COMMODITY TRADING

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

Avista Utilities

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

Avista Utilities manages the impact of fluctuations in electric energy prices by measuring and controlling the volume of energy imbalance between projected loads and resources and through the use of derivative commodity instruments for hedging purposes. Load/resource imbalances within a rolling 18-month planning horizon are compared against established volumetric guidelines and management determines the timing and specific actions to manage the imbalances. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods. Avista Energy is responsible for the daily management of natural gas supplies to meet the requirements of Avista Utilities’ customers in the states of Washington, Idaho and Oregon. In February 2004, the WUTC ordered that these functions be moved back to Avista Utilities for Washington customers, and in April 2004, the WUTC approved Avista Utilities’ transition plan to move these functions back into Avista Utilities by March 31, 2005. Effective April 1, 2005, the Company will also be moving these functions back to Avista Utilities for Idaho and Oregon customers with the expiration of current agreements. As part of the transition plan, Avista Utilities has begun procuring natural gas for load service. This procurement process includes entering into financial and physical hedging transactions as a means of managing risks. See description of Natural Gas Benchmark Mechanism in Note 1 for further information. Avista Utilities has continued to manage natural gas procurement for its California operations, which the Company has entered into an agreement to sell (see Note 27 for further information).

Avista Energy

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

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

Avista Energy measures the risk in its electric and natural gas portfolio daily utilizing a Value-at-Risk (VAR) model, which monitors its risk in comparison to established thresholds. VAR measures the expected portfolio loss under hypothetical adverse price movements over a given time interval within a given confidence level. Avista Energy also measures its open positions in terms of volumes at each delivery location for each forward time period. The permissible extent of open positions is included in the risk management policy and is measured with stress tests and VAR modeling.

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

Avista Energy’s derivative commodity instruments accounted for under SFAS No. 133 are subject to mark-to-market accounting, under which changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as unrealized gains or losses in the Consolidated Statements of Income in the period of change. Market prices are utilized in determining the value of electric, natural gas and related derivative commodity instruments, which are reported as assets and liabilities on the Consolidated Balance Sheets. These market prices are used through 36 months. Prior to the fourth quarter of 2004, market prices for electric commodity prices were used through 24 months. Increased market liquidity has resulted in the availability of reliable and transparent market prices for a longer time period than had been previously available. For longer-term positions and certain short-term positions for which market prices are not available, a model to estimate forward price curves is utilized. Avista Energy reports the net margin on derivative commodity instruments held for trading as operating revenues. Revenues from contracts, which are not derivatives under SFAS No. 133 and derivative commodity instruments not held for trading, are reported on a gross basis in operating revenues. Costs from contracts, which are not derivatives under SFAS No. 133 and derivative instruments not held for trading, are reported on a gross basis in resource costs. Contracts in a receivable position, as well as the options held, are reported as assets. Similarly, contracts in a payable position, as well as options written, are reported as liabilities. Net cash flows are recognized in the period of settlement.

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

During 2004, a gain of $1.0 million related to hedge ineffectiveness was recorded in earnings as operating revenues. Of this $1.0 million, $0.7 million is related to portions of hedging relationships that have settled during 2004. As of

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December 31, 2004, there was a net gain of $0.1 million (net of tax) in accumulated other comprehensive income (loss) related to designated cash flow hedges, while a gain of $0.5 million (net of tax) was reclassified from accumulated comprehensive income (loss) and recognized in earnings during 2004. During 2003, a gain of less than $0.1 million related to hedge ineffectiveness was recorded in earnings as operating revenues. As of December 31, 2003, there was a gain of $1.8 million (net of tax) in accumulated other comprehensive income (loss) related to designated cash flow hedges, while a gain of $0.5 million (net of tax) was reclassified from accumulated comprehensive income (loss) and recognized in earnings during 2003. Of the amount in accumulated other comprehensive income (loss) as of December 31, 2004, there was a gain of $1.6 million (net of tax) related to natural gas derivatives and a loss of $1.5 million (net of tax) related to electricity derivatives. Avista Energy expects to recognize a gain of $0.1 million in earnings during the next 12 months, related to amounts currently in accumulated other comprehensive income (loss). The actual amounts that will be recognized in earnings during the next 12 months will vary from the expected amounts as a result of changes in market prices. The maximum term of the designated hedging instruments was 12 months.

Contract Amounts and Terms Under Avista Energy’s derivative instruments, Avista Energy either (i) as “fixed price payor,” is obligated to pay a fixed price or a fixed amount and is entitled to receive the commodity or a fixed amount, (ii) as “fixed price receiver,” is entitled to receive a fixed price or a fixed amount and is obligated to deliver the commodity or pay a fixed amount, (iii) as “index price payor,” is obligated to pay an indexed price or an indexed amount and is entitled to receive the commodity or a variable amount or (iv) as “index price receiver,” is entitled to receive an indexed price or amount and is obligated to deliver the commodity or pay a variable amount. The contract or notional amounts and terms of Avista Energy’s derivative commodity instruments outstanding as of December 31, 2004 are set forth below (in thousands of mmBTUs and MWhs):

                                                 
    Fixed     Fixed     Maximum     Index     Index     Maximum  
    Price     Price     Terms in     Price     Price     Terms in  
    Payor     Receiver     Years     Payor     Receiver     Years  
 
Energy commodities (volumes)
                                               
Electric
    32,562       34,105       13       1,382       1,500       2  
Natural gas
    259,003       257,752       5       1,814,707       1,796,044       3  

The weighted average term of Avista Energy’s electric derivative commodity instruments as of December 31, 2004 was approximately 7 months. The weighted average term of Avista Energy’s natural gas derivative commodity instruments as of December 31, 2004 was approximately 4 months.

Estimated Fair Value The estimated fair value of Avista Energy’s derivative commodity instruments outstanding as of December 31, 2004, and the average estimated fair value of those instruments held during the year ended December 31, 2004, are set forth below (dollars in thousands):

                                                                 
    Estimated Fair Value     Average Estimated Fair Value for the  
    as of December 31, 2004     year ended December 31, 2004  
    Current     Long-term     Current     Long-term     Current     Long-term     Current     Long-term  
    Assets     Assets     Liabilities     Liabilities     Assets     Assets     Liabilities     Liabilities  
Electric
  $ 156,580     $ 234,225     $ 134,810     $ 197,030     $ 178,794     $ 229,522     $ 159,780     $ 191,275  
Natural gas
    127,651       20,432       118,717       18,025       120,747       21,125       115,166       13,917  
 
                                               
Total
  $ 284,231     $ 254,657     $ 253,527     $ 215,055     $ 299,541     $ 250,647     $ 274,946     $ 205,192  
 
                                               

The change in the estimated fair value position of Avista Energy’s energy commodity portfolio, net of reserves for credit and market risk for 2004 was an unrealized loss of $0.7 million and is included in the Consolidated Statements of Income in operating revenues. The change in the fair value position for 2003 was an unrealized loss of $22.1 million. In 2002, the unrealized loss was $91.9 million.

Market Risk

Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Market risk is influenced to the extent that the performance or nonperformance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity. Avista Utilities and Avista Energy manage the market risks inherent in their activities according to risk policies established by the Company’s Risk Management Committee.

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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 or make financial settlements. Avista Utilities and Avista Energy often extend credit to counterparties and customers. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it and the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, Avista Utilities or Avista Energy may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment. Avista Utilities and Avista Energy seek to mitigate credit risk by applying specific eligibility criteria to existing and prospective counterparties and by actively monitoring current credit exposures. These policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees, and the use of standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty.

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

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

Other Operating Risks

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

NOTE 8. CASH DEPOSITS WITH AND FROM COUNTERPARTIES

Cash deposits from counterparties totaled $6.0 million and $97.8 million as of December 31, 2004 and 2003, respectively. These funds are held by Avista Utilities and Avista Energy to mitigate the potential impact of counterparty default risk. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of non-cash collateral. Cash deposited with counterparties totaled $30.7 million and $36.8 million as of December 31, 2004 and 2003, respectively, and is included in other current assets on the Consolidated Balance Sheets.

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

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NOTE 9. JOINTLY OWNED ELECTRIC FACILITIES

As of December 31, 2004, the Company had a 50 percent ownership interest in a combined cycle natural gas-fired turbine power plant, the Coyote Springs 2 Generation Plant (Coyote Springs 2) located in north-central Oregon, which was placed into operation in 2003. The Company’s share of related fuel costs as well as operating and maintenance expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Coyote Springs 2 was $108.8 million and accumulated depreciation was $6.7 million as of December 31, 2004. In January 2005, the Company acquired the remaining 50 percent ownership interest in Coyote Springs 2 at a price of $62.5 million. See Note 28 for further information.

The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, the Colstrip Generating Project (Colstrip) located in southeastern Montana, and provides financing for its ownership interest in the project. The Company’s share of related fuel costs as well as operating and maintenance expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Colstrip was $320.2 million and accumulated depreciation was $172.4 million as of December 31, 2004.

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

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