SEC Filing | Avista Corporation

View:

Download DOC

Download PDF

Download XLS

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005

¨	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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.

Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:

Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

Yes ¨ No x

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 $902,211,367 based on the last reported sale price thereof on the consolidated tape on June 30, 2005.

As of February 28, 2006, 48,617,354 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-Prospectus to be filed in

connection with the annual meeting

of shareholders to be held May 11, 2006

Part III, Items 10, 11,

12, 13 and 14

AVISTA CORPORATION

INDEX


Item No.		Page No.
	Acronyms and Terms	iii

	Part I

	Available Information	1
1.	Business	1
	Company Overview	1
	Avista Utilities	3
	General	3
	Electric Operations	3
	Electric Requirements	4
	Electric Resources	4
	Hydroelectric Relicensing	5
	Future Resource Needs	6
	Natural Gas Operations	7
	Regulatory Issues	8
	Industry Restructuring	9
	Environmental Issues	10
	Avista Utilities Operating Statistics	12
	Energy Marketing and Resource Management	14
	Avista Energy	14
	Avista Power	15
	Avista Advantage	15
	Other	15
1A.	Risk Factors	16
1B.	Unresolved Staff Comments	20
2.	Properties	21
	Avista Utilities	21
3.	Legal Proceedings	22
4.	Submission of Matters to a Vote of Security Holders	22

	Part II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
6.	Selected Financial Data	23
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	Forward-Looking Statements	24
	Potential Holding Company Formation	25
	Avista Corp. Business Segments	26
	Executive Level Summary	27
	Avista Utilities – Electric Resources	29
	Avista Utilities – Regulatory Matters	29
	Power Market Issues	31
	Energy Policy Act of 2005	32
	Results of Operations	33
	Overall Operations	33
	Avista Utilities	35
	Energy Marketing and Resource Management	42
	Avista Advantage	46
	Other Business Segment	46
	New Accounting Standards	46
	Critical Accounting Policies and Estimates	47
	Liquidity and Capital Resources	50
	Review of Cash Flow Statement	50
	Overall Liquidity	50

AVISTA CORPORATION


	Capital Resources	51
	Inter-Company Debt; Subordination	53
	Pension Plan	53
	Off-Balance Sheet Arrangements	53
	Spokane Energy, LLC	54
	WP Funding LP	54
	Credit Ratings	54
	Dividends	54
	Avista Utilities Operations	55
	Energy Marketing and Resource Management Operations	55
	Avista Advantage Operations	56
	Other Operations	57
	Contractual Obligations	57
	Competition	58
	Business Risk	58
	Risk Management	61
	Economic and Load Growth	63
	Succession Planning	63
	Environmental Issues and Other Contingencies	63
7A.	Quantitative and Qualitative Disclosures about Market Risk	63
8.	Financial Statements and Supplementary Data	63
	Report of Independent Registered Public Accounting Firm	64
	Financial Statements	65-71
	Consolidated Statements of Income	65
	Consolidated Statements of Comprehensive Income	66
	Consolidated Balance Sheets	67-68
	Consolidated Statements of Cash Flows	69-70
	Consolidated Statements of Stockholders’ Equity	71
	Notes to Consolidated Financial Statements	72
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	113	*
9A.	Controls and Procedures	113
9B.	Other Information	115

	Part III

10.	Directors and Executive Officers of the Registrant	115
11.	Executive Compensation	116
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	117
13.	Certain Relationships and Related Transactions	117
14.	Principal Accountant Fees and Services	117

	Part IV

15.	Exhibits, Financial Statement Schedules	118
	Signatures	119
	Exhibit Index	120

* = not an applicable item in the 2005 calendar year for the Company

AVISTA CORPORATION

ACRONYMS AND TERMS

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


Acronym/Term		Meaning

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

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

AM&D		- Advanced Manufacturing and Development

APB		- Accounting Principles Board

Avista Advantage		- Avista Advantage, Inc., provider of facility information and cost management services for multi-site customers throughout 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

CT		- Combustion turbine

Dead band or ERM dead band		- the first $9.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the Energy Recovery Mechanism in the state of Washington

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

iii

AVISTA CORPORATION



FASB		- Financial Accounting Standards Board

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

PUHCA		- the Public Utility Holding Company Act of 1935

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

AVISTA CORPORATION

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,” “forecasts,” “projects,” “predicts,” and similar expressions. All forward-looking 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 effect 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, 2005, the Company employed approximately 1,435 people in its utility operations and approximately 550 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 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. The Company’s total common stockholders’ equity was $771.1 million as of December 31, 2005 of which $237.7 million represented its investment in Avista Capital.

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 electricity and natural gas. Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Based on Avista Utilities’ forecast for electric customer growth of 2.5 percent and natural gas customer growth of 4 percent within its service area, Avista Utilities anticipates retail electric and natural gas load growth will average between 3 and 3.5 percent annually for the next four years. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas properties in South Lake Tahoe, California (see “Note 28 of the Notes to Consolidated Financial Statements”). This was the Company’s only regulated utility operation in California.

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 generation 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 end-user industrial and commercial customers in British Columbia, Canada. In addition to earnings and resulting cash flows from settled or realized transactions, Avista Energy records unrealized or mark-to-market adjustments for the change in the value of derivative commodity instruments. Avista Energy continues to seek opportunities to expand its business of optimizing generation assets

AVISTA CORPORATION

owned by other entities and has expanded its natural gas end-user business to industrial and commercial customers in Montana. Avista Power’s primary asset is its 49 percent interest in a 270 megawatt (MW) natural gas-fired combined cycle combustion turbine plant in northern Idaho (Lancaster Project).

Avista Advantage, Inc. (Avista Advantage) is a provider of facility information and cost management services for 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 in a competitive market. During the first quarter of 2005, Avista Advantage acquired TelAssess, Inc. Although not a significant financial transaction, this acquisition provides Avista Advantage a foundation on which to expand beyond utility bill information services to provide similar services relating to telecom expense management.

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.

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

LOGO

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

0	- denotes business segment.

See “Item 6. Selected Financial Data” and “Note 29 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment.

In February 2006, the Board of Directors of Avista Corp. made the decision to ask shareholders to approve a change in the Company’s organization, which would result in the formation of a holding company. See further information at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Potential Holding Company Formation.”

AVISTA CORPORATION

Avista Utilities

General

Avista Utilities generates, transmits and distributes electricity and distributes natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. Avista Utilities also engages in wholesale purchases and sales of electricity and natural gas 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 parts of eastern Washington and northern Idaho with a population of approximately 865,000. It also provides natural gas distribution service in parts of northeast and southwest Oregon with a population of approximately 470,000. At the end of 2005, Avista Utilities supplied retail electric service to a total of 338,000 customers and retail natural gas service to a total of 297,000 customers across its entire service territory. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas properties in South Lake Tahoe, California (see “Note 28 of the Notes to Consolidated Financial Statements”). This was the Company’s only regulated utility operation in California. 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.

Electric Operations

In addition to providing electric distribution and transmission services, Avista Utilities generates electricity from facilities that it owns. 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. 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.

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 United States. Transmission revenues, which are included in Other Electric Revenues at “Avista Utilities Operating Statistics – Electric Operations,” totaled $11.0 million, $13.9 million and $11.6 million for 2005, 2004 and 2003, respectively. Avista Utilities is currently in the process of enhancing its transmission system. The transmission system project is expected to cost approximately $115 million, of which $67 million has been incurred as of December 31, 2005.

Challenges facing Avista Utilities’ electric operations include, among other things, streamflows to hydroelectric generating facilities, weather conditions, changes in the availability of and volatility in the prices of power and fuel, the timing and approval of the recovery of deferred power costs, generating unit availability, legislative and governmental regulations, potential tax law changes, and customer response to price increases and surcharges. See “Industry Restructuring,” “Item 1A. Risk Factors,” “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.

AVISTA CORPORATION

Electric Requirements

The peak electric native load requirement for 2005 occurred on December 8, 2005 at which time native load was 1,660 MW, long-term wholesale obligations were 172 MW and short-term wholesale obligations were 110 MW. At that time the maximum resource capacity available from Avista Utilities was 2,556 MW, which included 1,816 MW of company-owned electric generation, 70 MW of long-term hydroelectric contracts, 316 MW of other long-term wholesale purchases and 354 MW of short-term wholesale purchases. Variations in energy usage by Avista Utilities’ customers occur as a result of varying weather conditions and other energy usage behaviors. This necessitates a continual balancing of loads and resources, and requires both wholesale 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 2005, Avista Utilities’ owned facilities had a total net capability of approximately 1,800 MW, of which 54 percent was hydroelectric and 46 percent was thermal. See “Item 2. Properties” for detailed information with respect to generating facilities.

Hydroelectric Resources Avista Utilities owns and operates six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. 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. Avista Utilities estimates that normal annual hydroelectric generation (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 538 average megawatts (aMW) (or 4.7 million MWhs). This is a decrease from previous estimates of normal annual hydroelectric generation of 550 aMW (or 4.8 million MWhs) primarily due to changes in long-term hydroelectric contracts with certain PUDs during 2005. Hydroelectric resources generated 511 aMW, 523 aMW and 492 aMW during 2005, 2004 and 2003, respectively. Hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. Avista Utilities cannot determine if this trend of lower than normal hydroelectric generation will continue in future years.

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


	2005	2004	2003
Noxon Rapids	1,589	1,595	1,543
Cabinet Gorge	1,004	1,062	975
Post Falls	87	96	80
Upper Falls	71	71	67
Monroe Street	101	107	99
Nine Mile	107	135	122
Long Lake	460	511	465
Little Falls	192	212	189

Total company-owned hydroelectric generation	3,611	3,789	3,540
Long-term hydroelectric contracts with PUDs	864	794	775

Total hydroelectric generation	4,475	4,583	4,315

Thermal Resources Since January 2005, Avista Utilities has owned 100 percent of the combined cycle natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) located near Boardman, Oregon. Prior to January 2005, Avista Utilities owned 50 percent of Coyote Springs 2. 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 GS) in northeastern Washington and a two-unit natural gas-fired CT generating facility, located in northeast Spokane (Northeast CT). Avista Utilities also owns a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT). In 2005, Avista Utilities acquired the Rathdrum CT from WP Funding LP, an entity that was included in Avista Corp.’s consolidated financial statements and included in the Avista Utilities business segment. In addition, Avista Utilities owns two small generating facilities (Boulder Park and Kettle Falls CT).

AVISTA CORPORATION

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

The primary fuel for the Kettle Falls GS 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 the Kettle Falls GS.

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 units have not been operated significantly in 2005, 2004 and 2003. 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:


	2005	2004	2003
Coyote Springs 2 (1)	1,528	407	397
Colstrip	1,771	1,605	1,593
Kettle Falls GS	338	366	366
Northeast CT and Rathdrum CT	6	6	20
Boulder Park and Kettle Falls CT	23	24	22

Total thermal generation	3,666	2,408	2,398

(1)	The Company owned 50 percent of Coyote Springs 2 prior to January 2005. In January 2005, the Company acquired the remaining 50 percent ownership interest in Coyote Springs 2 from Mirant Oregon, LLC.

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. In February 2006, the PURPA was amended by the Federal Energy Regulatory Commission (FERC) as required by the Energy Policy Act of 2005. These amendments are not expected to have an effect on Avista Utilities’ current PURPA-related contracts.

See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2005, 2004 and 2003.

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 to 50 year periods. Avista Corp.’s licensed projects are subject to the provisions of Part I of the Federal Power Act. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages.

In March 2001, Avista Utilities received a 45-year operating license from the FERC for the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) and the Noxon Rapids Hydroelectric Generating Project (Noxon Rapids). The Clark Fork Settlement Agreement that was entered into during 1999 and incorporated into the FERC license preserved the projects’ economic peaking and load following operations. Also, as part of the Clark Fork Settlement Agreement, Avista Utilities initiated implementation of protection, mitigation and enhancement measures in March 1999. Measures in the

AVISTA CORPORATION

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 26 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 owns and 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 are referred to, collectively, 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 on August 1, 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 filed its license application with the FERC in July 2005. The Company has requested the FERC to consider a license for Post Falls that is separate from the other four hydroelectric plants. This is due to the fact that Post Falls presents more complex issues that may take longer to resolve than those dealing with the rest of the Spokane River Project. If granted, new licenses would have a term of 30 to 50 years. In the license application, the Company has proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River. Currently, certain environmental measures in the Company’s license application have estimated costs of $3.2 million per year. For certain items, costs cannot be reasonably estimated at this time. The total annual operating and capitalized costs associated with the relicensing of the Spokane River Project will become better known and estimable as the process continues through July 2007. 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 2006, 2007, 2008 and 2009:

Forecasted Electric Energy Requirements and Resources

(aMW)


	2006	2007	2008	2009
Requirements:
System load	1,086	1,121	1,155	1,194
Contracts for power sales	61	61	61	61

Total requirements	1,147	1,182	1,216	1,255

Resources:
Company-owned and contract hydro generation (1)	538	538	538	535
Company-owned base load thermal generation	226	229	243	228
Company-owned other thermal generation	284	294	279	294
Contracts for power purchases	293	295	294	295

Total resources	1,341	1,356	1,354	1,352

Surplus resources	194	174	138	97
Additional available energy (2)	142	145	145	145

Total surplus resources	336	319	283	242

(1)	The forecasts assume normal hydroelectric generation of 538 aMW for 2006, 2007 and 2008, and 535 aMW for 2009 (due to changes in certain contracts with PUDs).

(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.

AVISTA CORPORATION

In October 2005, Avista Utilities submitted its 2005 Electric Integrated Resource Plan (IRP) to the WUTC and the IPUC. The IRP identifies a strategic resource portfolio that meets future electric load requirements, promotes environmental stewardship and meets Avista Utilities’ obligation to provide reliable electric service to customers at rates, terms and conditions that are fair, just and reasonable and sufficient. Avista Utilities regards the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. Based on the assumptions in the IRP, Avista Utilities forecasts that quarterly energy deficits will begin in 2007 and annual energy deficits will begin in 2010. In order to meet these increased demands, Avista Utilities’ preferred resource plan, which is part of the IRP, includes 400 MW of wind power, 250 MW of coal-based generation, 80 MW of biomass, 52 MW of generation plant upgrades and 69 MW of conservation by 2016. In January 2006, Avista Utilities issued a request for proposals (RFP) to consider adding approximately 35 average megawatts of long-term renewable energy supplies. It is expected that deliveries of any energy supplies from this RFP would begin in the fourth quarter of 2007. In early 2006, Avista Utilities has also entered into an agreement with Idaho Power to jointly investigate possible future coal-based generation resources.

Natural Gas Operations

General Avista Utilities provides natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, as well as parts of northeast and southwest Oregon. 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 $8.13, $6.62 and $5.50 in 2005, 2004 and 2003, respectively. This continued upward price trend has resulted in increased rates for customers and lengthened the recovery period for deferred natural gas costs. Market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers, and 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. In order to maintain that competitive advantage and to offset increasing demand, natural gas must be used more efficiently. Avista Utilities is committed to encouraging efficient use of natural gas and has several incentive programs available to its customers.

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 2005, 2004 and 2003 was 153.0, 154.4 and 153.4 million therms, which represented approximately 27 percent, 31 percent and 31 percent of Avista Utilities’ total system deliveries, respectively.

As part of the process of balancing natural gas retail load requirements and resources obtained through wholesale purchases, Avista Utilities engages in wholesale sales of natural gas. This activity has increased significantly in 2005 due to the transition of natural gas procurement activities from Avista Energy to Avista Utilities with the termination of the Agency Agreement (see discussion below).

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. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Avista Utilities has capacity delivery rights on six 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.

From 1999 through March 31, 2005, the Company’s energy marketing, trading and resource management subsidiary, Avista Energy, was responsible for natural gas procurement functions, including the daily management and optimization of these natural gas resources for the requirements of customers in the states of Washington, Idaho and Oregon under the Natural Gas Benchmark Mechanism and related Agency Agreement with Avista Utilities. Effective April 1, 2005, the Natural Gas Benchmark Mechanism and related Agency Agreement were terminated and the management of natural gas

AVISTA CORPORATION

procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

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

Regulatory Issues

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), and the Public Service Commission of the State of Montana (Montana Commission). Approval of the issuance of securities is not required from the Montana Commission. The Company is also subject to the jurisdiction of the FERC for its wholesale natural gas rates charged for the release of capacity from Jackson Prairie, licensing of hydroelectric generation resources, and for electric transmission service and wholesale 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 and write-offs as determined by the utility commissions. Rates for wholesale electric and natural gas transmission services are based on either “cost of service” principles or market-based rates as set forth by 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Energy Policy Act of 2005” for information on the Energy Policy Act.

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.

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.

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 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.

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. Avista Corp. has executed an agreement with the BPA in settlement of each party’s rights and obligations related to the Residential Exchange Program for the period

AVISTA CORPORATION

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. These challenges could possibly affect the amount of benefits paid by the BPA to Avista Corp. 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

Energy Policy Act of 2005 In August 2005, the Energy Policy Act of 2005 (Energy Policy Act) was passed into law. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Energy Policy Act of 2005” for information on the Energy Policy Act.

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 (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-1990s 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-1990s, 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 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.

AVISTA CORPORATION

In February 2005, the NERC Board of Trustees approved reliability standards with the goal of restating existing standards in a manner that is clear, unambiguous, measurable and enforceable. These reliability standards became effective April 1, 2005. Also 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. To comply with applicable standards, Avista Utilities submits annual reliability compliance reports to the NERC.

In February 2006, the FERC issued its final rule on the certification rules for a single Electric Reliability Organization (ERO). This organization, once certified, will have the authority to establish and enforce reliability standards, and will have the ability to delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. The FERC intends to provide adequate time to transition from the current system of voluntary reliability standards to mandatory standards under the ERO. The Company continues with its involvement in the NERC compliance process and expects to be involved in the transition to the ERO or regional compliance process.

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. While it has not formally withdrawn Order No. 2000, the FERC has issued orders and made public policy statements indicating its support for the development and formation of regional independently-governed transmission organizations that is developed by the region and that does not necessarily meet all of the functions and characteristics of an RTO outlined in Order No. 2000.

Since prior to the FERC’s Order No. 2000, Avista Utilities has been participating in discussions with utilities and others in the Pacific Northwest to develop the structure of an independently-governed transmission organization for the region. Interim bylaws governing continuing developmental activities for a non-profit membership corporation, Grid West, were adopted in December 2004. During 2005, certain regional parties explored an alternative structure that did not involve creation of an independently-governed organization. In September 2005, a proposal to converge the two alternatives under the Grid West organization emerged; however, a consensus was not achieved. As a result, Grid West was restructured into a non-member organization in November of 2005, with fewer participating transmission owners, and has been evaluating alternative implementation plans, which work is now in progress. Avista Utilities continues in these discussions regarding a reduced set of initial functions and geographical scope for Grid West, and will participate in discussions regarding other structural approaches that include those regional transmission provider systems currently not participating in the Grid West organization.

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 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 process. The Company cannot predict these implications.

State Level While the 1992 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. 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

AVISTA CORPORATION

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 key part 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 in 2006 and the Company has applied for renewal) and the operating permit for the Kettle Falls GS was renewed in 2002 (expires in 2007). The Northeast CT was issued a Title V permit in February 2004 (expires in 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 made against 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.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies “ for further information.

Water Quality See “Clark Fork Settlement Agreement” in “Note 26 of the Notes to Consolidated Financial Statements” regarding dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge.

Other Environmental Issues See “Colstrip Generating Project Complaint,” “Environmental Protection Agency Administrative Compliance Order,” “Hamilton Street Bridge,” “Spokane River,” “Harbor Oil Inc. Site,” “Northeast Combustion Turbine Site” and “Other Contingencies” in “Note 26 of the Notes to Consolidated Financial Statements” for information with respect to additional environmental issues.

AVISTA CORPORATION

AVISTA UTILITIES OPERATING STATISTICS


	Years Ended December 31,
	2005			2004			2003
ELECTRIC OPERATIONS
ELECTRIC OPERATING REVENUES (Dollars in Thousands):
Residential	$	211,934		$	209,518		$	204,783
Commercial		203,480			201,775			201,339
Industrial		91,552			90,288			78,276
Public street and highway lighting		4,898			4,847			4,770

Total retail revenues		511,864			506,428			489,168
Wholesale revenues		151,429			62,399			73,463
Revenues from sales of fuel		41,831			63,990			71,456
Other revenues		17,988			19,264			16,835

Total electric operating revenues	$	723,112		$	652,081		$	650,922

ELECTRIC ENERGY SALES (Thousands of MWhs):
Residential		3,420			3,343			3,298
Commercial		2,994			2,919			2,919
Industrial		2,091			2,076			1,785
Public street and highway lighting		25			25			25

Total retail energy sales		8,530			8,363			8,027
Wholesale energy sales		2,508			1,472			2,075

Total electric energy sales		11,038			9,835			10,102

ELECTRIC ENERGY RESOURCES (Thousands of MWhs):
Hydro generation (from Company facilities)		3,611			3,789			3,540
Thermal generation (from Company facilities)		3,666			2,408			2,398
Purchased power - long-term hydroelectric contracts with PUDs		864			794			775
Purchased power - wholesale		3,519			3,422			3,909
Power exchanges		10			38			36

Total power resources		11,670			10,451			10,658
Energy losses and Company use		(632	)		(616	)		(556	)

Total energy resources (net of losses)		11,038			9,835			10,102

NUMBER OF ELECTRIC CUSTOMERS (Average for Period):
Residential		294,036			288,422			283,497
Commercial		37,282			36,728			36,279
Industrial		1,408			1,416			1,414
Public street and highway lighting		421			418			422

Total electric retail customers		333,147			326,984			321,612
Wholesale		46			43			47

Total electric customers		333,193			327,027			321,659

ELECTRIC RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWh)		11,630			11,591			11,633
Revenue per KWh (in cents)		6.20			6.27			6.21
Annual revenue per customer	$	720.78		$	726.43		$	722.35
ELECTRIC AVERAGE HOURLY LOAD (aMW)		1,046			1,025			984

RESOURCE AVAILABILITY at time of system peak (MW):
Total requirements (winter):
Retail native load		1,660			1,766			1,509
Wholesale obligations		282			454			417

Total requirements (winter)		1,942			2,220			1,926
Total resource availability (winter)		2,556			2,552			2,557
Total requirements (summer):
Retail native load		1,498			1,488			1,487
Wholesale obligations		575			294			449

Total requirements (summer)		2,073			1,782			1,936
Total resource availability (summer)		2,519			2,409			2,365
COOLING DEGREE DAYS: (1)
Spokane, WA
Actual		409			571			578
30-year average		394			394			394
% of average		104	%		145	%		147	%

(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).

AVISTA CORPORATION

AVISTA UTILITIES OPERATING STATISTICS


	Years Ended December 31,
	2005			2004			2003
NATURAL GAS OPERATIONS
NATURAL GAS OPERATING REVENUES (Dollars in Thousands):
Residential	$	229,737		$	194,470		$	166,925
Commercial		126,648			104,754			90,523
Industrial		11,867			9,423			7,475

Total retail natural gas revenues		368,252			308,647			264,923
Wholesale revenues		58,074			152			280
Transportation revenues		7,601			8,134			8,485
Other revenues		4,278			3,560			3,601

Total natural gas operating revenues	$	438,205		$	320,493		$	277,289

THERMS DELIVERED (Thousands of Therms):
Residential		199,433			201,696			198,471
Commercial		122,981			122,852			122,115
Industrial		13,534			13,274			12,737

Total retail		335,948			337,822			333,323
Wholesale		72,903			305			675
Transportation		152,990			154,427			153,352
Interdepartmental and Company use		466			3,030			3,124

Total therms delivered		562,307			495,584			490,474

SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):
Purchases		434,239			341,398			334,609
Storage - injections		(26,359	)		(60	)		(74	)
Storage - withdrawals		5,314			52			76
Natural gas for transportation		152,990			154,427			153,352
Interdepartmental transportation		—			2,551			2,607
Distribution system losses		(3,877	)		(2,784	)		(96	)

Total natural gas supply		562,307			495,584			490,474

NUMBER OF NATURAL GAS CUSTOMERS (Average for Period):
Residential		265,294			268,571			261,063
Commercial		31,652			31,886			31,312
Industrial		307			311			310

Total natural gas retail customers		297,253			300,768			292,685
Wholesale		12			1			1
Transportation		93			81			84

Total natural gas customers		297,358			300,850			292,770

NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (therms)		752			751			760
Revenue per therm (in dollars)	$	1.15		$	0.96		$	0.84
Annual revenue per customer	$	865.97		$	724.09		$	639.41
NET SYSTEM MAXIMUM CAPABILITY (Thousands of Therms):
Net system maximum demand (winter)		2,698			3,098			2,270
Net system maximum firm contractual capacity (winter)		4,340			4,340			4,340
HEATING DEGREE DAYS: (1)
Spokane, WA
Actual		6,538			6,314			6,351
30-year average		6,820			6,820			6,820
% of average		96	%		93	%		93	%
Medford, OR
Actual		4,185			3,933			4,046
30-year average		4,533			4,533			4,533
% of average		92	%		87	%		89	%

(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 below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).

AVISTA CORPORATION

Energy Marketing and Resource Management

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

Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business, operating primarily within the WECC. Avista Energy’s headquarters are in Spokane, Washington, and it also has natural gas marketing offices in Vancouver, British Columbia, Canada and Great Falls, Montana (which opened in early 2006). Avista Energy focuses on optimization of generation 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 200 end-user industrial and commercial customers that represent approximately 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 continues to seek opportunities to expand its business of optimizing generation assets owned by other entities and has expanded its natural gas end-user business to industrial and commercial customers in Montana. Avista Energy’s earnings are primarily derived from the following activities:

•

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

•

Optimization of generation 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.

•

Marketing natural gas to end-user industrial and commercial customers.

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 1A. Risk Factors,” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Business Risk and – Risk Management” for further information.

In addition to its trading activities, a fundamental component of Avista Energy’s business strategy is having asset management and optimization agreements with other entities, which helps create synergies within its entire portfolio. Under this strategy, Avista Energy does not have ownership of the physical energy assets, which allows Avista Energy to focus on commodity management while minimizing responsibilities and risks associated with actual ownership. Avista Energy assists the asset owner with decisions regarding the operation of their generation assets to capture available economic value and shares in the benefits derived from optimization. This process includes transactions such as purchasing fuel to run thermal generation and, when economic, selling fuel and substituting market purchases for the operation of the generating asset. Optimization also includes other transactions to capture the value of available generation, transmission and transportation resources. This optimization process is combined with other portions of Avista Energy’s business, including electric and natural gas trading, to maximize the value of Avista Energy’s entire portfolio, within established risk management policies.

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


	2005	2004	2003
Gross Physical Realized Sales Volume:
Electricity (thousands of MWhs)	28,377	32,629	41,579
Natural gas (thousands of dekatherms)	182,874	219,719	228,397

AVISTA CORPORATION

Avista Energy managed Avista Utilities’ natural gas storage assets, transportation contracts and natural gas purchasing operations from 1999 through March 31, 2005 under an Agency Agreement. Under that agreement, Avista Energy served as the natural gas supply agent for Avista Utilities, including purchasing natural gas for Avista Utilities’ retail customers. Effective April 1, 2005, the Agency Agreement was terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. The termination of the Agency Agreement was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan was approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

Avista Power

Avista Power’s primary asset is its 49 percent ownership interest in the Lancaster Project. 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 facility information and cost management services for multi-site customers throughout North America. Through invoice processing, auditing, payment services and comprehensive reporting, Avista Advantage’s solutions are designed to provide companies with critical and easy-to-access information that enables them to proactively manage and reduce their utility, telecom and waste management expenses.

As part of their process, Avista Advantage analyzes and audits invoices, then presents consolidated bills on-line, as well as processes payments for these expenses. Information gathered from invoices, providers and other customer-specific data allows Avista Advantage to provide its clients with in-depth analytical support, real-time reporting and consulting services.

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

As of December 31, 2005, Avista Advantage serviced 348 customers, having 174,910 billed sites throughout North America. This is an increase from 323 customers and 141,442 billed sites as of December 31, 2004. As of December 31, 2003, Avista Advantage serviced 292 customers and 109,583 billed sites. During 2005, Avista Advantage processed $9.3 billion of bills, an increase from $7.6 billion in 2004 and $6.4 billion in 2003.

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 fabrication of electronic enclosures, parts and systems for the computer, telecom and medical industries. AM&D also performs contract assembly for radiant floor heating systems. 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. However, the Company may, from time to time, invest incremental funds in these businesses to protect its existing investments.

AVISTA CORPORATION

Item 1A.

Risk Factors

The following are factors that could have a significant impact on the operations, results of operations, financial condition or cash flows of Avista Corp. and could cause actual results or outcomes to differ materially from those discussed in Avista Corp.’s reports filed with the Securities and Exchange Commission (including this Annual Report on Form 10-K), and elsewhere. In addition to these risk factors, please also see the “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” for additional factors 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.

Avista Corp.’s results of operations, financial condition and cash flows can be significantly affected by weather.

Weather has a significant effect on Avista Utilities’ operations, both with respect to customer demand and resulting operating revenues (primarily heating requirements in the winter and cooling requirements in the summer) and electric resource costs (primarily the availability of hydroelectric generation and the tendency for high demand to increase the cost of fuel for electric generation and wholesale electric market prices). Avista Utilities normally experiences its highest retail (electric and natural gas) energy sales during the heating season in the first and fourth quarters of the year. Avista Utilities also experiences high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and colder weather in the cooling season will have a negative effect on Avista Utilities’ operating revenues. In addition, a reduction in precipitation (particularly snowpack) will decrease hydroelectric generation capability and increase resource costs and cash outflows to purchase electric resources. Hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. Avista Corp. has no way to predict whether this trend of lower than normal hydroelectric generation will continue in the future. Regional precipitation and snowpack conditions can also have a significant effect on the wholesale price of electricity.

Avista Corp. is subject to commodity price risk.

Both Avista Utilities and Avista Energy are subject to electric and natural gas commodity price risk. Price risk is, in general, the risk of fluctuation in the market price of the commodity needed, held or traded. Changes in wholesale energy prices can affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations, as well as the market value of derivative assets and liabilities and unrealized gains and losses. 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 on a regional basis, the price and availability of fuel for thermal generating plants, and disruptions of or constraints on 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, the demand for natural gas as fuel for electric generation, 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 and electricity prices, because of the fuel-switching capabilities of certain energy users. Demand changes caused by variations in the weather and other factors can also affect market prices for electricity and natural gas. Any combination of these factors that results in a shortage of energy generally causes the market price to move upward.

Increasing energy commodity prices have a significant effect on liquidity for both Avista Utilities and Avista Energy. Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of its power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect Avista Corp.’s operating cash flow and liquidity until such costs, with interest, are recovered from customers.

Avista Utilities’ deferred power and natural gas costs are subject to regulatory review; costs in excess of levels recovered in base rates reduce cash flows and it may take several years to recover current balances of deferred costs.

Avista Utilities defers the recognition in the income statement of certain power and natural gas costs that are in excess of the level currently recovered from its retail customers as authorized by the WUTC, the IPUC and the OPUC. These excess power and natural gas costs are recorded as deferred charges on the Consolidated Balance Sheet with the opportunity for recovery through future retail rates. These deferred power and natural gas costs are

AVISTA CORPORATION

subject to review by the WUTC, IPUC and OPUC, as applicable, for prudence and as such certain deferred costs may be disallowed by the respective regulatory agencies.

Despite the opportunity to eventually recover a substantial portion of power and natural gas costs in excess of the levels currently recovered from retail customers, Avista Utilities’ operating cash flows are negatively affected in the periods in which these costs are paid. Factors that could cause costs to exceed the levels currently recovered from Avista Utilities’ customers include, but are not limited to, higher prices in wholesale markets combined with an increased need to purchase energy in the wholesale markets. Factors beyond Avista Utilities’ control that could result in an increased need to purchase energy 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.

Avista Utilities currently expects that the recovery of current balances of deferred power and natural gas costs may take several years.

Avista Utilities is subject to the risk that regulators will not grant sufficient recovery of its costs and not provide a reasonable rate of return for Avista Corp.’s shareholders.

Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. General rate increases granted since 2002 have been important steps in Avista Corp.’s financial recovery primarily through increased operating revenues and operating cash flows. Avista Utilities anticipates that it will continue to periodically file for general rate increases with regulatory agencies to recover its costs and provide a reasonable return to Avista Corp.’s shareholders. If regulators were to grant substantially lower rate increases than Avista Utilities requests in the future, it could have a negative effect on operating revenues and cash flows, which could result in future downgrades to its credit ratings or prevent Avista Corp. from improving its credit ratings.

Avista Corp. is subject to credit risk.

Avista Utilities and Avista Energy are subject to credit risk. Credit risk relates to the losses 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 and are exposed to the risk that they may not be able to collect amounts owed to them. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits have been established. Credit risk includes the risk that a counterparty may default due to circumstances relating directly to it, circumstances caused by market price changes and also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. Should a counterparty, customer or supplier fail to perform, Avista Utilities and/or Avista Energy may be required to replace existing contracts with contracts at then-current market prices or to honor the underlying commitment.

Avista Energy has concentrations of suppliers and customers in the electric and natural gas industries including but not limited to, 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 negatively affect Avista Energy’s overall exposure to credit risk, 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 CORPORATION

Avista Corp.’s commodity trading, marketing and resource management activities may increase the volatility in its results of operations; Avista Corp. cannot, and does not attempt to, fully hedge its assets or positions against changes in commodity prices, and its hedging procedures may not fully match the corresponding purchase or sale.

Avista Energy engages in commodity trading and marketing, as well as resource management activities. These activities include entering into financial and physical derivative transactions, and taking speculative positions on future price movements, within established risk management policies. Avista Energy is required by applicable accounting principles to record all derivatives on the Consolidated Balance Sheet at estimated fair value. Changes in the estimated fair value of derivatives are immediately recognized in earnings unless they are designated as cash flow hedges of forecasted transactions. Changes in the estimated fair value of derivatives accounted for as cash flow hedges of forecasted transactions are deferred and recorded as a component of accumulated other comprehensive income (loss) until the hedged transactions occur and are recognized in earnings. Most of Avista Energy’s derivative contracts are marked-to-market and changes in their value caused by fluctuations in the underlying commodity prices, flow through Avista Corp.’s Consolidated Statements of Income. As a result, fluctuations in commodity prices and the corresponding effect on the market value of derivative instruments could have a significant effect on Avista Corp.’s operating revenues, resource costs, derivative assets and liabilities, and operating cash flows.

To reduce financial and economic exposure related to commodity price fluctuations, Avista Utilities and Avista Energy routinely enter into contracts to hedge a portion of their purchase and sale commitments for electricity and natural gas, as well as inventories of natural gas. As part of this strategy, Avista Utilities and Avista Energy routinely utilize derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. However, Avista Utilities and Avista Energy do not always cover the entire exposure of assets or positions to market price volatility and the coverage will vary over time. To the extent Avista Utilities or Avista Energy have unhedged positions, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material adverse effect on Avista Corp.’s operating revenues, resource costs, derivative assets and liabilities, and operating cash flows.

Avista Corp.’s risk management procedures may not prevent losses.

Avista Utilities and Avista Energy have risk management policies and control procedures designed to measure and mitigate energy market risks. However, these policies and procedures cannot prevent material losses in all possible situations or from all potential causes. Included in Avista Energy’s risk management policies are value-at-risk (VAR) limits and systematic measurement procedures derived from historic price behavior. VAR measures the expected portfolio loss under hypothetical adverse price movements over a given time interval within a given confidence level. Losses could exceed the VAR predictive amounts if prices deviate significantly from their historic patterns and in cases when actual events fall into the extreme end of the VAR confidence interval. In addition, continuing trends of small losses that may be individually less than VAR limits may cumulatively become significant. As a result of these and other factors, there can be no assurance that Avista Utilities’ and Avista Energy’s risk management procedures will prevent losses that could negatively affect its operating revenues, resource costs, derivative assets and liabilities, and operating cash flows.

Avista Corp. relies on access to credit from banks.

Avista Corp. needs to maintain access to adequate levels of credit with its banks. Avista Corp. has in place a committed line of credit in the amount of $350 million, which is scheduled to expire in December 2009. Avista Corp. cannot predict whether it will have access to credit beyond the expiration date. The line of credit contains customary covenants and default provisions. In the event of default, it would be difficult for Avista Corp. to obtain financing on any reasonable terms to pay creditors or fund operations, and Avista Corp. would likely be prohibited from paying dividends on its common stock.

Avista Energy also needs access to adequate levels of credit from banks and currently has a $145 million committed line of credit, which is scheduled to expire in July 2007. Avista Corp. cannot predict whether Avista Energy will have access to credit after the expiration of its current line of credit. Avista Energy’s credit agreement contains customary covenants and default provisions, including but not limited to, 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 (Avista Energy and Avista Energy Canada) may incur. The credit agreement also contains covenants and other restrictions related to Avista Energy’s trading limits and positions, including but not limited to, 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. These covenants, certain counterparty agreements and 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 Avista Corp. If Avista Energy were

AVISTA CORPORATION

unable to continue to obtain credit from banks or other lenders, Avista Energy would likely not have sufficient liquidity to meet its obligations.

A downgrade in Avista Corp.’s credit rating could limit its ability to obtain financing or adversely affect the terms of financing.

Avista Corp.’s credit ratings were downgraded during the fourth quarter of 2001 resulting in an overall corporate credit rating that is below investment grade. The downgrades were due to liquidity concerns primarily related to the significant amount of purchased power and natural gas costs incurred and the resulting increase in debt levels and debt service costs. Avista Corp. continues to work towards restoring an overall corporate investment grade credit rating. However, any future downgrades could limit Avista Corp.’s ability to issue debt securities or obtain other financing at reasonable interest rates. In addition, future downgrades could require Avista Corp. to provide letters of credit and/or collateral to lenders and counterparties.

An increase in interest rates could negatively affect Avista Corp.’s future results of operations and cash flows.

During the years 2006 through 2008, utility capital expenditures are currently expected to be in the range of $160 million to $175 million per year. In addition to continuing needs for Avista Utilities’ distribution system, significant projects include the continued enhancement of Avista Utilities’ transmission system and upgrades to generating facilities. Avista Corp. also has approximately $567 million of long-term debt maturities and mandatory preferred stock redemptions between 2006 and 2008, with the majority occurring in 2007 and 2008. Avista Corp.’s forecasts indicate that it will need to issue new securities to fund a significant portion of these requirements. In 2004, Avista Corp. entered into forward-starting interest rate swap agreements to effectively lock in market fixed interest rates, which are relatively low compared to historical interest rates, for $200 million of forecasted debt issuances. However, with respect to the remaining debt that Avista Corp. expects to issue, rising interest rates could increase Avista Corp.’s future debt service costs and decrease operating cash flows.

Avista Corp. is subject to various operational and event risks, which are common to the utility industry.

Avista Utilities, Avista Corp.’s regulated utility operation, is subject to operational and event risks including, among others, increases or decreases in load demand, blackouts or disruptions to transmission or transportation systems, fuel quality, forced outages at generating plants and disruptions to information systems and other administrative tools required for normal operations.

Avista Utilities also has exposure to natural disasters and terrorism threats that can cause physical damage to its property, requiring repairs to restore utility service.

Avista Corp. may not be able to relicense its hydroelectric facilities located on the Spokane River at a cost-effective level with reasonable terms and conditions.

Avista Corp. owns and 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 Federal Energy Regulatory Commission (FERC) license and are referred to 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 on August 1, 2007; Avista Corp. filed its license application with the FERC in July 2005. Avista Corp. has requested the FERC to consider a license for Post Falls that is separate from the other four hydroelectric plants. This is due to the fact that Post Falls presents more complex issues that may take longer to resolve than those dealing with the rest of the Spokane River Project. The FERC may impose certain environmental, operating and other conditions in connection with the new licenses that could result in significant capital expenditures, higher operating costs and/or reduced hydroelectric generation capability. Avista Corp. plans to request regulatory approval to recover these costs. However, Avista Corp. cannot estimate the magnitude of these costs or provide certainty that they will be recovered through the rate making process.

In 2001, Avista Corp. received a 45-year operating license from the FERC for the Cabinet Gorge Hydroelectric Generating Project and the Noxon Rapids Hydroelectric Generating Project, which represent approximately 80 percent of Avista Corp.’s current hydroelectric generating capability. The Spokane River facilities represent approximately 20 percent of Avista Corp.’s current hydroelectric generating capability.

AVISTA CORPORATION

Avista Corp. is currently the subject of several regulatory proceedings and named in multiple lawsuits with respect to its participation in Western energy markets as disclosed in “Note 26 of the Notes to Consolidated Financial Statements.”

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. 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, and complaints and cross-complaints filed by various parties with respect to alleged misconduct by other parties in western power markets. In addition, a class action shareholder complaint has been filed against Avista Corp. and certain current and former executive officers based on alleged misconduct in western power markets. As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from Avista Corp. and its subsidiaries, which could result in a negative effect on Avista Corp.’s results of operations and cash flows. See “Note 26 of the Notes to Consolidated Financial Statements” for further information.

Avista Corp. has contingent liabilities as disclosed in “Note 26 of the Notes to Consolidated Financial Statements.” Avista Corp. cannot predict the outcome of these matters.

Avista Corp. has multiple matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. Avista Corp. cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or the extent, if any, that amounts payable by Avista Corp. may be recoverable through the rate making process. See “Note 26 of the Notes to Consolidated Financial Statements” for further details of these matters.

Lake Coeur d’Alene Matter

Avista Corp. is liable for compensation (not yet determined as to amount) for the use of portions of the bed and banks of Lake Coeur d’Alene and the St. Joe River, which were determined to be property of the Coeur d’Alene Tribe of Idaho. Avista Corp. is engaged with the Tribe in discussions with respect to past and future compensation (which may include interest) for use of the portions of the bed and banks of the Lake that are owned by the Tribe. If the parties cannot agree on the amount of compensation, the matter could result in litigation.

Montana Hydroelectric Litigation

A lawsuit was filed in Montana against all private owners of hydroelectric dams in Montana, including Avista Corp., alleging that the hydroelectric facilities are located on state-owned riverbeds and the owners have never paid compensation to the state’s public school trust fund. The lawsuit was originally filed by private parties and was subsequently joined by other public parties, including the Attorney General of the State of Montana. Various motions for summary judgment and counter claims are pending in federal and state courts.

Environmental Matters

Avista Corp. is subject to environmental regulation by federal, state and local authorities with respect to its past, present and future operations. Environmental issues include, but are not limited to, contamination of certain parcels of land that Avista Corp. currently owns, has formerly owned or has used as a customer, contamination of certain parcels of land and waters adjacent to Avista Corp.’s property, contamination of certain portions of the Spokane River as well as the levels of dissolved gas in waters downstream of Avista Corp.’s hydroelectric facilities and the resulting impact on free ranging fish.

Avista Corp. is subject to the risk from the potential effects of any legislation or administrative rulemaking.

Avista Corp. has been and is expected to continue to be impacted by legislation at the national and state level, as well as by administrative rules promulgated by government agencies, such as the FERC, NERC and the EPA. Future legislation or administrative rules could have a material adverse effect on Avista Corp.’s operations, results of operations, financial condition and cash flows.

Item 1B.

Unresolved Staff Comments

As of the filing date of this Annual Report on Form 10-K, Avista Corp. does not have any unresolved comments from the staff of the Securities and Exchange Commission.

AVISTA CORPORATION

Item 2.

Properties

Avista Utilities

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

Generation Properties


	No. of Units	Nameplate Rating (MW) (1)	Present Capability (MW) (2)
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 GS	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	2	166.5	176.0
Montana:
Colstrip Units 3 and 4 (3)	2	233.4	222.0
Oregon:
Coyote Springs 2	1	287.0	274.2

Total Thermal		830.9	820.5

Total Generation Properties		1,730.1	1,800.2

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

(2)	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, 2005.

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

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 625 miles of 230 kV line and 1,539 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.

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 enhancing its 230 kV transmission system, which Avista Utilities expects to be completed by the end of 2007.

AVISTA CORPORATION

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 service to each other’s customers that are connected through the other’s transmission system. Avista Utilities and the BPA have contracts in place that allow Avista Utilities to serve its native load customers connected through the BPA transmission system and allow the BPA to serve its wholesale utility customers connected through Avista Utilities’ transmission system.

Natural Gas Plant

Avista Utilities has natural gas distribution mains of approximately 2,700 miles in Washington, 1,600 miles in Idaho and 1,850 miles in Oregon. 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 221.4 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 26 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.

PART II

Item 5.

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

Avista Corp.’s common stock is currently listed on the New York Stock Exchange (NYSE) and the Pacific Stock Exchange (PSE) with the NYSE maintaining the principal listing. As of February 28, 2006, there were approximately 14,269 registered shareholders of the Company’s no par value common stock.

On February 10, 2006, the Board of Directors of Avista Corp. decided to delist the Company’s common stock from the PSE. The Board of Directors made this decision primarily due to the limited volume of Avista Corp. Common Stock transactions on the PSE and the costs of listing on the PSE.

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.

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 Sheets. Covenants in Avista Energy’s credit agreement, certain counterparty agreements and 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 2005, Avista Energy paid $15.1 million in dividends to Avista Capital.

For additional information, refer to “Notes 1, 23, 24 and 25 of Notes to Consolidated Financial Statements.” For high and low stock price, as well as dividend information, refer to “Note 30 of Notes to Consolidated Financial Statements.”

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

AVISTA CORPORATION

Item 6.

Selected Financial Data


	Years Ended December 31,
(in thousands, except per share data and ratios)	2005			2004			2003			2002			2001
Operating Revenues:
Avista Utilities	$	1,161,317		$	972,574		$	928,211		$	893,964		$	1,230,847
Energy Marketing and Resource Management		167,439			275,646			307,141			222,634			403,743
Avista Advantage		31,748			23,444			19,839			16,911			13,151
Other		18,532			17,127			13,581			14,645			16,385
Intersegment Eliminations		(19,429	)		(137,211	)		(145,387	)		(85,238	)		(152,375	)

Total	$	1,359,607		$	1,151,580		$	1,123,385		$	1,062,916		$	1,511,751

Income (Loss) from Operations (pre-tax):
Avista Utilities	$	165,378		$	134,073		$	146,777		$	149,180		$	114,927
Energy Marketing and Resource Management		(18,267	)		11,681			30,078			29,211			94,669
Avista Advantage		6,973			1,742			(1,331	)		(6,363	)		(15,098	)
Other		(2,060	)		(7,026	)		(3,821	)		(14,886	)		(10,432	)

Total	$	152,024		$	140,470		$	171,703		$	157,142		$	184,066

Income (Loss) from Continuing Operations:
Avista Utilities	$	52,479		$	32,467		$	36,241		$	36,382		$	24,164
Energy Marketing and Resource Management		(8,621	)		9,733			20,672			22,425			63,246
Avista Advantage		3,922			577			(1,334	)		(4,253	)		(10,748	)
Other		(2,612	)		(7,163	)		(4,936	)		(12,380	)		(8,421	)

Total		45,168			35,614			50,643			42,174			68,241
Loss from discontinued operations		—			—			(4,949	)		(6,719	)		(56,085	)

Net income before cumulative effect of accounting change		45,168			35,614			45,694			35,455			12,156
Cumulative effect of accounting change		—			(460	)		(1,190	)		(4,148	)		—

Net income		45,168			35,154			44,504			31,307			12,156
Preferred stock dividend requirements (1)		—			—			(1,125	)		(2,402	)		(2,432	)

Income available for common stock	$	45,168		$	35,154		$	43,379		$	28,905		$	9,724

Average common shares outstanding, basic		48,523			48,400			48,232			47,823			47,417
Average common shares outstanding, diluted		48,979			48,886			48,630			47,874			47,435
Common shares outstanding at year-end		48,593			48,472			48,344			48,044			47,633
Earnings per Common Share, Diluted (3):
Earnings from continuing operations	$	0.92		$	0.73		$	1.02		$	0.83		$	1.38
Loss from discontinued operations		—			—			(0.10	)		(0.14	)		(1.18	)

Earnings before cumulative effect of accounting change		0.92			0.73			0.92			0.69			0.20
Cumulative effect of accounting change		—			(0.01	)		(0.03	)		(0.09	)		—

Total earnings per common share, diluted	$	0.92		$	0.72		$	0.89		$	0.60		$	0.20

Total earnings per common share, basic	$	0.93		$	0.73		$	0.90		$	0.60		$	0.21
Dividends paid per common share		0.545			0.515			0.49			0.48			0.48
Book value per common share at year-end	$	15.87		$	15.54		$	15.54		$	14.84		$	15.12
Total Assets at Year-End:
Avista Utilities	$	2,838,154		$	2,608,155		$	2,532,936		$	2,369,418		$	2,569,798
Energy Marketing and Resource Management		2,012,354			1,002,843			1,013,213			1,349,626			1,506,185
Avista Advantage		46,094			47,318			45,621			31,733			20,288
Other		51,892			53,305			48,305			42,866			86,514
Discontinued Operations		—			—			—			5,900			27,919

Total	$	4,948,494		$	3,711,621		$	3,640,075		$	3,799,543		$	4,210,704

Long-Term Debt (not including current portion)	$	989,990		$	901,556		$	925,012		$	902,635		$	1,175,715
Long-Term Debt to Affiliated Trusts (2)		113,403			113,403			113,403			—			—
Company-Obligated Mandatorily Redeemable Preferred Trust Securities (2)		—			—			—			100,000			100,000
Preferred Stock Subject to Mandatory Redemption (1)		26,250			28,000			29,750			33,250			35,000
Common Equity	$	771,128		$	753,205		$	751,252		$	712,791		$	720,063
Ratio of Earnings to Fixed Charges		1.75			1.60			1.88			1.69			1.98
Ratio of Earnings to Fixed Charges and Preferred Dividend Requirements		1.75			1.60			1.85			1.63			1.91

(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, 2005, 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.

AVISTA CORPORATION

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, and assumptions underlying them (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,” “forecasts,” “projects,” “predicts,” and similar expressions.

All forward-looking statements (including those made in this Annual Report on Form 10-K) 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 effect 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:

•

weather conditions, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand;

•

changes in wholesale energy prices that can affect, among other things, cash requirements to purchase electricity and natural gas for retail customers, as well as the market value of derivative assets and liabilities and unrealized gains and losses;

•

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

•

the effect of state and federal regulatory decisions affecting the ability of the Company to recover its costs and/or earn a reasonable return, including, but not limited to, the disallowance of previously deferred costs;

•

the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2001 and 2002, and including possible retroactive price caps and resulting refunds;

•

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 affect allowed rates of return, financings, or industry and rate structures;

•

the outcome of legal proceedings and other contingencies concerning the Company or affecting directly or indirectly its operations;

•

the potential effects of any legislation or administrative rulemaking passed into law, including the Energy Policy Act of 2005 which was passed into law in August 2005;

•

the effect from the potential formation of a Regional Transmission Organization;

•

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

•

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;

•

the ability to relicense the Spokane River Project at a cost-effective level with reasonable terms and conditions;

•

unplanned outages at any Company-owned generating facilities;

•

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

•

natural disasters that can disrupt energy delivery as well as the availability and costs of materials and supplies and support services;

•

blackouts or large disruptions of transmission systems, which can have an impact on the Company’s ability to deliver energy to its customers;

•

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

•

changes in the long-term climate of the Pacific Northwest, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to hydroelectric resources;

•

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 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;

AVISTA CORPORATION

•

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 effect of any potential change in the Company’s credit ratings;

•

changes in actuarial assumptions, the interest rate environment and the actual return on plan assets with respect to the Company’s pension plan, which can affect 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;

•

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

•

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 rapidly advancing technologies, possibly making some of the current technology quickly obsolete;

•

changes in tax rates and/or policies; and

•

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

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 effect 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. and 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.

Potential Holding Company Formation

In February 2006, the Board of Directors of Avista Corp. made the decision to ask shareholders to approve a change in the Company’s organization, which would result in the formation of a holding company. The proposed holding company would become the parent to the regulated utility Avista Corp. (Avista Utilities) and Avista Capital, which is the parent to the Company’s non-utility subsidiaries. The holding company organizational structure is common in the utility industry. The recent repeal of the Public Utility Holding Company Act of 1935 removed certain restrictions on the formation of a public utility holding company for corporations like Avista Corp. that operate in more than one state.

The proposal for the formation of a holding company will be described for shareholders in Avista Corp.’s Proxy Statement-Prospectus to be distributed to shareholders in connection with the annual meeting of shareholders to be held on May 11, 2006. Avista Corp. has filed for regulatory approval from the Federal Energy Regulatory Commission (FERC) and the utility regulators in Washington, Idaho, Oregon and Montana, conditioned on approval by shareholders. If shareholders approve the proposal, and if state and federal regulatory approvals are received, the holding company organization could be implemented by the end of 2006.

AVISTA CORPORATION

The following chart presents the expected organization of the Company upon completion of all of the transactions associated with the formation of the holding company:

LOGO

¨	- denotes a business entity; Avista Utilities Corporation and Avista Advantage are also business segments.

0	- denotes business segment.

Avista Corp. Business Segments

Avista Corp. 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. The Company’s total common stockholders’ equity was $771.1 million as of December 31, 2005 of which $237.7 million represented its investment in Avista Capital.

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’s primary asset is its 49 percent interest in a 270 megawatt (MW) natural gas-fired combined cycle combustion turbine plant in northern Idaho (Lancaster Project).

Avista Advantage, Inc. (Avista Advantage) is a provider of facility information and cost management services for multi-site customers throughout North America. Through invoice processing, auditing, payment services and comprehensive reporting, Avista Advantage’s solutions are designed to provide companies with critical and easy-to-access information that enables them to proactively manage and reduce their utility, telecom and waste management expenses.

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 fabrication of electronic enclosures, parts and systems for the computer, telecom and

AVISTA CORPORATION

medical industries. AM&D also performs contract assembly for radiant floor heating systems. 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.

The following table presents results by business segment for the years ended December 31 (dollars in thousands):


	2005			2004			2003
Avista Utilities	$	52,479		$	32,467		$	36,241
Energy Marketing and Resource Management		(8,621	)		9,733			20,672
Avista Advantage		3,922			577			(1,334	)
Other		(2,612	)		(7,163	)		(4,936	)

Income from continuing operations		45,168			35,614			50,643
Loss from discontinued operations		—			—			(4,949	)

Net income before cumulative effect of accounting change		45,168			35,614			45,694
Cumulative effect of accounting change		—			(460	)		(1,190	)

Net income		45,168			35,154			44,504
Preferred stock dividend requirements		—			—			(1,125	)

Income available for common stock	$	45,168		$	35,154		$	43,379

Executive Level Summary

Net income was $45.2 million for 2005 compared to $35.2 million for 2004. This increase was due to the improved performance of Avista Utilities, as well as Avista Advantage and the Other business segment. This was partially offset by a net loss for Avista Energy (Energy Marketing and Resource Management segment).

Avista Corp.’s operating results and cash flows are derived primarily from Avista Utilities and Avista Energy. 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 is the Company’s most significant business segment. Avista Utilities expects to continue to be among the industry leaders in performance, value and service in its electric and natural gas utility businesses. Based on Avista Utilities’ forecast for electric customer growth of 2.5 percent and natural gas customer growth of 4 percent within its service area, Avista Utilities anticipates retail electric and natural gas load growth will average between 3 and 3.5 percent annually for the next four years. As part of Avista Utilities’ strategy to focus on its business in the northwestern United States, in April 2005, the Company completed the sale of its natural gas properties in South Lake Tahoe, California (see “Note 28 of the Notes to Consolidated Financial Statements”). This was the Company’s only regulated utility operation in California.

Avista Utilities operating and financial performance is substantially dependent upon, among other things: 1) weather conditions, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand, 2) the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, 3) the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand and 4) favorable regulatory decisions, allowing Avista Utilities to recover its costs, including particularly its purchased power and fuel costs, on a timely basis, and to earn a fair return on its investment.

Avista Utilities’ hydroelectric generation was 95 percent of normal in 2005. Hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. The Company cannot determine if this trend of lower than normal hydroelectric generation will continue in future years. Avista Utilities forecasts that hydroelectric generation will be near normal in 2006. This is an early forecast, which will change based upon precipitation, temperatures and other variables during the year.

Avista Utilities has increased capital expenditures in order to meet load growth needs and to continue to provide reliable service to its customers. Utility capital expenditures totaled $213.7 million in 2005, the most significant of which were the acquisition of the remaining interest in Coyote Springs 2, transmission system enhancements, and the repurchase of the Company’s corporate headquarters and central operating facility in Spokane. For 2006, the Company has established a utility capital budget of approximately $160 million. Significant projects include the continued enhancement of Avista Utilities’ transmission system and upgrades to generating facilities.

AVISTA CORPORATION

Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service. Avista Utilities has received base rate increases in each of its jurisdictions since October 2003. Most recently, in December 2005, Avista Utilities received approval from the Washington Utilities and Transportation Commission (WUTC) to increase its base electric and natural gas rates effective January 1, 2006. Avista Utilities will continue to file for rate adjustments to provide for recovery of its operating costs and capital investments and to more closely align earned returns with those allowed by regulatory agencies.

Avista Utilities’ net income was $52.5 million for 2005, an increase from $32.5 million for 2004 primarily due to the general rate increases, as well as the $4.1 million pre-tax gain on the sale of the South Lake Tahoe natural gas properties. This was partially offset by increases in other operating expenses particularly with respect to depreciation and amortization from utility plant additions as well as compensation and other employee related expenses. Results for 2004 were reduced by write-offs of $14.4 million ($9.4 million, net of tax) related to the Idaho Public Utility Commission (IPUC) general rate case order. Avista Utilities expects net income for 2006 to be similar to 2005.

Avista Energy’s business activities include trading electricity and natural gas, as well as the optimization of generation assets owned by other entities, long-term electric supply contracts, natural gas storage, and electric transmission and natural gas transportation arrangements. Avista Energy Canada, Ltd. (Avista Energy Canada) is a wholly owned subsidiary of Avista Energy that provides natural gas services to end-user industrial and commercial customers in British Columbia, Canada.

The earnings and cash flows of Avista Energy are by nature subject to significant volatility because they are derived primarily from the day-to-day trading of electricity and natural gas and optimization of assets owned by other entities, as opposed to long-term revenue streams, and because Avista Energy’s activities are for the most part subject to mark-to-market accounting. In addition, with respect to the management of natural gas storage and certain other contracts, Avista Energy’s earnings are subject to the anomalies caused by the differences between the required accounting and the economic management of these assets and contracts. While Avista Energy has taken measures to enhance profitability and reduce the risk of losses in the future, this business will continue to have volatility in its results.

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 energy markets in which Avista Energy operates continue to have volatile market prices and variations in liquidity.

The Energy Marketing Resource Management segment, which consists primarily of Avista Energy, incurred a net loss of $8.6 million for 2005 compared to net income of $9.7 million for 2004. The net loss for 2005 was the first annual net loss for this business segment since 1999. The net loss for 2005 was primarily due to losses in Avista Energy’s natural gas portfolio. The volatility in natural gas and electricity prices can result in significant changes in earnings from Avista Energy from year-to-year. Avista Energy’s trading of electricity and natural gas, as well as asset optimization activities, have been cumulatively profitable since 1999. Asset optimization has resulted in the recovery of a majority of the fixed and variable costs associated with the power purchase agreement for the Lancaster Project for 2006. In addition, early in 2006, the Company captured a significant amount of value relative to prior years, from the economic management of natural gas storage. Earnings associated with these activities, as well as the anticipated future success of trading natural gas and electricity, are expected to return this segment to profitability in 2006.

Avista Advantage remains focused on increasing revenues, controlling operating expenses, continuously enhancing client satisfaction and developing complementary value-added services in a competitive market. During the first quarter of 2005, Avista Advantage acquired TelAssess, Inc. Although not a significant financial transaction, this acquisition provides Avista Advantage a foundation on which to expand beyond existing utility bill information services to provide similar services relating to telecom expense management. Net income for Avista Advantage was $3.9 million for 2005, an increase from $0.6 million for 2004 based on increased revenues from an expanding customer base and stabilizing operating expenses from processing efficiencies. The Company expects net income for Avista Advantage to increase in 2006 as compared to 2005.

Over time as opportunities arise, the Company plans to continue to dispose of assets and phase out operations in the Other business segment. However, the Company may, from time to time, invest incremental funds in these businesses to protect its existing investments. The net loss in the Other business segment was $2.6 million for 2005, a decrease from $7.2 million (excluding the cumulative effect of accounting change) for 2004 primarily due to

decreased losses from asset impairments and write-offs incurred in 2004. The Company expects a similar net loss for 2006 as compared to 2005 for the Other business segment.

Total debt outstanding increased $37.5 million in 2005 primarily to fund utility capital expenditures that were in excess of net cash flows from operating activities. Avista Corp. issued $150.0 million of long-term debt during the fourth quarter of 2005 to, among other things, refinance borrowings on its committed line of credit. For 2006, the Company expects net cash flows from operating activities and Avista Corp.’s committed line of credit to provide adequate resources to fund capital expenditures, maturing long-term debt, dividends and other contractual commitments. However, the Company currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007.

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 Utilities – Electric Resources

As of December 31, 2005, Avista Utilities’ facilities had a total net capability of approximately 1,800 MW, of which 54 percent was hydroelectric and 46 percent was 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

In recent years, Avista Utilities has generally not earned its authorized rates of return. Avista Utilities regularly reviews the need for electric and natural gas rate changes in each state in which it provides service and will continue to file for rate adjustments to provide for recovery of its operating costs and capital investments and to more closely align earned returns with those allowed by regulatory agencies. The following table summarizes Avista Utilities’ authorized rates of return in each jurisdiction:


Jurisdiction and service	Implementation Date	Authorized Overall Rate of Return		Authorized Return on Equity		Authorized Equity Level
Washington electric and natural gas	January 2006	9.11	%	10.40	%	40	%
Idaho electric and natural gas	September 2004	9.25	%	10.40	%	43	%
Oregon natural gas	October 2003	8.88	%	10.25	%	48	%

In December 2005, the WUTC approved Avista Utilities’ combined electric and natural gas general rate case settlement agreement with certain conditions, which were subsequently accepted by the settling parties (Avista Utilities, the WUTC staff, the Northwest Industrial Gas Users and the Energy Project). The WUTC order provided for base rate increases of 7.5 percent for electric and 0.6 percent for natural gas, effective January 1, 2006. The electric base rate increase is designed to increase annual revenues by $21.4 million. The majority of the increase in electric revenues is related to increased power supply costs. As such, a significant portion of the increase will not increase gross margin or net income, because it will be matched by an increase in resource costs. The natural gas base rate increase is designed to increase annual revenues by approximately $1.0 million. The WUTC order also provides for further review of the ERM as discussed at “Power Cost Deferrals and Recovery Mechanisms” below.

As part of the general rate case settlement agreement that was modified and approved by the WUTC order, Avista Utilities has agreed to increase the utility equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008. Failure by Avista Utilities to meet those targets could result in a reduction in base rates of 2 percent for each target. The utility equity component was approximately 31 percent as of December 31, 2005.

In January 2005, the 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.

In October 2004, the 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, 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

AVISTA CORPORATION

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. Based on the final order, Avista Utilities had to write off a total of $14.4 million of costs in 2004.

Other Regulatory Filings and Rulings

In April 2005, the IPUC issued an order approving the inclusion of the remaining 50 percent of Coyote Springs 2 in base electric rates. The order provides for a 1.9 percent increase in base electric rates, which is designed to increase annual revenues by $3.2 million. At the same time, the IPUC approved a 1.9 percent reduction in the Company’s current PCA rate surcharge. These two requests together resulted in no overall change to customers’ existing rates.

The Oregon Public Utility Commission (OPUC) has issued temporary rules and is in the process of formulating final rules related to Oregon Senate Bill 408 (OSB 408). OSB 408 requires the OPUC to direct the utility to establish an automatic adjustment clause to account for the difference between taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. Taxes paid attributed to Oregon regulated operations are limited to the lesser of consolidated or stand-alone tax payments. The automatic adjustment clause may result in either rate increases or rate decreases and applies only to taxes paid and collected on or after January 1, 2006. Interpretation and application of OSB 408 is complicated by a number of factors, including, but not limited to, the adjustments that are allowed under OSB 408, the Company’s organizational structure, and the fact that the Company provides retail natural gas and electric services in multiple state jurisdictions. At this point in time, the Company cannot predict the effect that OSB 408 may have on revenues or net income related to its Oregon natural gas operations.

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 ERM allows Avista Utilities to increase or decrease electric rates periodically with WUTC approval to reflect changes in power supply costs. The ERM currently 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, which is referred to as the ERM dead band. Under the ERM, 90 percent of the power supply costs exceeding or below the dead band 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 WUTC rejected the proposal in the rate case settlement agreement to reduce the ERM dead band from $9.0 million to $3.0 million. However, Avista Utilities was directed to make a filing with the WUTC by January 31, 2006, with proposed changes to the ERM, including any changes to the ERM dead band. On January 31, 2006, Avista Utilities made its filing with the WUTC proposing that the ERM be continued for an indefinite period of time and that the $9.0 million ERM dead band be eliminated. This filing also satisfied a previous requirement for Avista Utilities to make a filing by the end of 2006 for a review of the ERM. The elimination of the $9.0 million ERM dead band would reduce the volatility of Avista Utilities’ earnings that has been caused by variations in hydroelectric generation, as well as prices for fuel and purchased power. The WUTC has set a procedural schedule that would allow for an order on any changes to the ERM (including any changes to the dead band) to be issued in late June or July of 2006. The WUTC also stated that any changes to the ERM ordered by the WUTC in 2006 would be effective for the full year (beginning January 1, 2006). The Company expensed the entire ERM dead band during 2005, 2004, 2003 and 2002 ($4.5 million in 2002 due to mid-year implementation on July 1, 2002).

The rate case settlement agreement approved by the WUTC increases the ERM surcharge from 9.8 percent to 10.8 percent, which allows Avista Utilities to more rapidly recover deferred power costs.

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 June 2005, the WUTC issued an order, which approved the recovery of the $10.8 million of deferred power costs incurred for 2004. In March 2006, the Company will make its filing for deferred power costs incurred in 2005.

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

AVISTA CORPORATION

power supply expenses and the authorized level of net power supply expense. As disclosed at “General Rate Cases” above, 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 IPUC authorized the recovery of remaining deferred power costs over a two-year period through a PCA rate surcharge to customers that was reduced to 4.4 percent. The PCA surcharge was further reduced to 2.5 percent in April 2005 with the approval of the inclusion of the remaining interest in Coyote Springs 2 in base electric rates. The decrease in the PCA rate surcharge extends the recovery period of deferred power costs by an additional year.

The following table shows activity in deferred power costs for Washington and Idaho during 2004 and 2005 (dollars in thousands):


	Washington			Idaho			Total
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
Activity from January 1 – December 31, 2005:
Power costs deferred		4,129			3,938			8,067
Interest and other net additions		5,403			278			5,681
Recovery of deferred power costs through retail rates		(26,549	)		(5,727	)		(32,276	)

Deferred power costs as of December 31, 2005	$	96,191		$	7,987		$	104,178

(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

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. Currently, purchased gas adjustments provide for the deferral and future recovery or refund of 100 percent of the difference between commodity costs and the amount recovered in current retail rates in Washington and Idaho. In Oregon, Avista Utilities has received a tariff revision that provides for 100 percent recovery of known hedges. With respect to the unhedged portion of customer loads, the revised tariff provides for the deferral and future recovery or refund of 90 percent of the difference between actual prices and the amount recovered in current retail rates effective October 1, 2005. The Company has hedged most of its natural gas load requirements in Oregon. During September through November of 2004, natural gas rate increases of 11.7 percent, 14.2 percent and 12.6 percent were implemented in Washington, Idaho and Oregon, respectively. During October and November of 2005, natural gas rate increases of 23.5 percent, 23.8 percent and 22.5 percent were implemented in Washington, Idaho and Oregon, respectively. These natural gas rate increases are designed to pass through increases in purchased natural gas costs to customers with no change in Avista Utilities’ gross margin or net income. Total deferred natural gas costs were $43.4 million and $28.6 million as of December 31, 2005 and 2004, respectively.

Natural Gas Benchmark Mechanism

See “Natural Gas Benchmark Mechanism” in “Note 1 of the Notes to Consolidated Financial Statements” for a description of the Natural Gas Benchmark Mechanism and related Agency Agreement. Effective April 1, 2005, the Natural Gas Benchmark Mechanism and related Agency Agreement were terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

Power Market Issues

Legal and Regulatory Proceedings in Western Power Markets

AVISTA CORPORATION

contributed to or caused unjust and unreasonable prices. 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, 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 refunds and damages from Avista Energy and Avista Utilities, which could result in a negative effect on future earnings. Avista Energy and Avista Utilities have joined other parties in opposing these refund claims and complaints for damages. See further information in “Note 26 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 Corporation (Enron) and certain of its affiliates, the FERC initiated investigations in 2002 of many participants in power markets in the western United States, including Avista Corp. doing business as Avista Utilities, and Avista Energy. 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. In April 2004, the FERC approved an agreement that resolves the investigation of Avista Corp. and Avista Energy. Other parties filed requests for rehearing and filed motions to intervene in these proceedings. In April 2005, the FERC denied the requests for rehearing and motion to intervene in these proceedings; however, the other parties subsequently filed appeals with the United States Court of Appeals for the Ninth Circuit in response to the FERC’s denial of rehearing requests. See further information under “Federal Energy Regulatory Commission Inquiry” in “Note 26 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 in September 2004. By orders issued in March 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

In July 2005, the FERC announced that it had officially abandoned its efforts commenced in 2002 to create new national standard wholesale power market rules. However, the FERC continues its efforts with respect to the formation of Regional Transmission Organizations. This could significantly change how transmission facilities are regulated and operated. Avista Corp. has participated with other utilities in the western United States on the possible formation of a Regional Transmission Organization (RTO).

Energy Policy Act of 2005

In August 2005, the Energy Policy Act of 2005 (Energy Policy Act) was passed into law. The Energy Policy Act substantially affects the regulation of energy companies, including Avista Corp. Key provisions of the Energy Policy Act affecting the Company include, but are not limited to, reform of the hydroelectric licensing process, tax credits for incremental hydroelectric production and the implementation of mandatory reliability standards. The Energy Policy Act also has provisions related to the future operation and development of transmission systems and federal support for certain clean power initiatives and renewable energy technologies, including wind power generation. Finally, the Energy Policy Act repealed the Public Utility Holding Company Act of 1935 (PUHCA) and, among other things, granted the FERC and state utility commissions access to the books and records of holding company systems, provides (upon request of a state commission or holding company system) for FERC review of allocations of costs of non-power goods and administrative services and modifies the jurisdiction of the FERC over certain mergers and acquisitions involving public utilities or holding companies.

AVISTA CORPORATION

The implementation of the Energy Policy Act requires proceedings at the state level and the development of regulations by the FERC, the Department of Energy and other federal agencies. In particular, the FERC has initiated rules that, among other things, implement new reliability standards, require that open access be provided to non-regulated transmission utilities, and implement new provisions relating to the repeal of PUHCA.

The Company continues to analyze and implement certain provisions of the Energy Policy Act. Such activities include the proposed formation of a holding company under the new provisions relating to the repeal of the PUHCA.

Results of Operations

Overall Operations

The following provides an overview of changes in the Company’s Consolidated Statements of Income. More detailed explanations are provided, particularly with respect to operating revenues and operating expenses in the business segment discussions (Avista Utilities, Energy Marketing and Resource Management, Avista Advantage and Other) that follow this section.

2005 compared to 2004

Utility revenues increased $188.7 million due to increases in electric revenues of $71.0 million and natural gas revenues of $117.7 million. The increase in natural gas revenues was primarily due to increased natural gas wholesale sales and increases in retail natural gas sales as a result of rate increases. The increase in electric revenues primarily reflects an increase in wholesale revenues and a slight increase in retail revenues, partially offset by a decrease in sales of fuel.

Non-utility energy marketing and trading revenues increased $9.6 million primarily due to increased revenues for Avista Energy Canada, partially offset by decreased net trading margin on contracts accounted for under Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

Other non-utility revenues increased $9.7 million to $50.3 million as a result of increased revenues from Avista Advantage of $8.3 million and increased revenues from the Other business segment of $1.4 million. The increase in revenues from Avista Advantage was primarily due to customer growth and the increase from the Other business segment was primarily due to increased sales at AM&D.

Utility resource costs increased $150.6 million primarily due to increased purchased power costs of $41.4 million and increased purchased natural gas costs of $109.9 million. The increase in purchased power and natural gas costs was primarily due to an increase in prices, as well as an increase in the volume of purchases.

Utility other operating expenses increased $1.1 million primarily due to an increase in incentive compensation expenses including performance share payouts, partially offset by a decrease in certain other operating expenses. These decreases in certain other operating expenses include the sale of the South Lake Tahoe natural gas operations and write-offs related the Idaho general rate case incurred in 2004.

Utility depreciation and amortization increased $8.1 million for 2005 compared to 2004 due in part to plant additions and the resulting increase in depreciation expense. Total utility capital expenditures were $213.7 million in 2005. The increase in utility depreciation and amortization was also due to a correction for overstated depreciation expense in prior periods recorded during 2004.

Non-utility resource costs increased $46.4 million primarily due to increased resource costs for Avista Energy Canada and partially due to an increase in transportation and transmission costs.

Other non-utility operating expenses decreased $7.7 million for 2005 compared to 2004 due to asset impairment charges recorded at Avista Power (Energy Marketing and Resource Management segment) in 2004, decreased compensation expense at Avista Energy (Energy Marketing and Resource Management segment), the impairment of goodwill at AM&D, the accrual of environmental liabilities at Avista Development and the write-off of an investment in a natural gas storage project during 2004 (Other business segment). This was partially offset by increased operating expenses for Avista Advantage due to expanding operations.

AVISTA CORPORATION

Interest expense decreased $0.8 million for 2005 compared to 2004 primarily due to a decrease in the effective borrowing rate on long-term debt as a result of previous debt issuances and repurchases, partially offset by an increase in interest expense on short-term borrowings.

Interest expense to affiliated trusts increased $0.4 million due to increasing interest rates and the effect on variable rate debt.

Other income-net increased $1.6 million primarily due to an increase in interest income.

Income taxes increased $4.3 million for 2005 compared to 2004, primarily due to increased income before income taxes. The effective tax rate was 36.4 percent for 2005 compared to 37.7 percent for 2004. The decrease in the effective tax rate was partially due to tax credits for the Kettle Falls Generation Plant that the Company began receiving the benefit from in 2005.

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 Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised in December 2003 (collectively referred to as FIN 46), which required Avista Ventures to consolidate several minor entities.

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.

Utility revenues increased $44.4 million due to an increase in natural gas revenues of $43.2 million and an increase in electric revenues of $1.2 million. The increase in natural gas revenues was primarily due to natural gas rate increases and partially due to increased therms sold, primarily as a result of customer growth. The slight increase in electric revenues reflects an increase in retail revenues, partially offset by a decrease in wholesale revenues and sales of fuel.

Non-utility energy marketing and trading revenues decreased $23.3 million primarily due to decreased net trading margin on contracts accounted for under SFAS No. 133 and a settlement with Enron affiliates during 2003, partially offset by increased revenues for Avista Energy Canada.

Other non-utility revenues increased $7.2 million to $40.6 million as a result of increased revenues from Avista Advantage of $3.6 million and increased revenues from the Other business segment of $3.6 million. The increased revenues from Avista Advantage was due to customer growth and the increase for the Other business segment was due to increased revenues from AM&D as well as revenues from entities consolidated in 2004 under FIN 46.

Utility resource costs increased $35.9 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.

Other utility operating expenses increased $14.9 million due to increased distribution and customer service expenses, 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 was also 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.

Utility depreciation and amortization increased $0.7 million for 2004 compared to 2003 primarily due to plant additions 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 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.

AVISTA CORPORATION

Utility taxes other than income taxes increased $5.5 million for 2004 compared to 2003 primarily due to increased retail revenues and related taxes, as well as an increase in property taxes.

Non-utility resource costs decreased $2.0 million primarily due to decreased resource costs for Avista Energy Canada.

Other non-utility operating expenses increased $4.4 million for 2004 compared to 2003 due the impairment of goodwill at AM&D, the accrual of an environmental liability at Avista Development, the write-off of an investment in a natural gas storage project, the effects from entities consolidated under FIN 46 (Other business segment) and the settlement of an employment contract at Avista Advantage. This was partially offset by decreased compensation expense and professional fees at Avista Energy (Energy Marketing and Resource Management segment).

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.

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.

Avista Utilities

2005 compared to 2004

Net income for Avista Utilities was $52.5 million for 2005 compared to $32.5 million for 2004. Avista Utilities’ income from operations was $165.4 million for 2005 compared to $134.1 million for 2004. This increase was primarily due to increased gross margin (operating revenues less resource costs) as a result of general rate increases and the IPUC related write-offs of $14.4 million ($9.4 million, net of taxes) in 2004, as well as the $4.1 million pre-tax gain related to the sale of Avista Utilities’ South Lake Tahoe natural gas properties in 2005. This was partially offset by an increase in depreciation expense, taxes other than income taxes and other operating expenses.

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


	Electric				Natural Gas				Total
	2005		2004		2005		2004		2005		2004
Operating revenues	$	723,112	$	652,081	$	438,205	$	320,493	$	1,161,317	$	972,574
Resource costs		343,945		300,958		325,651		218,044		669,596		519,002

Gross margin	$	379,167	$	351,123	$	112,554	$	102,449	$	491,721	$	453,572

Avista Utilities’ operating revenues increased $188.7 million and resource costs increased $150.6 million, which resulted in an increase of $38.1 million in gross margin for 2005 as compared to 2004. The gross margin on electric sales increased $28.0 million and the gross margin on natural gas sales increased $10.1 million. The increase in

AVISTA CORPORATION

electric gross margin was partially due to the IPUC’s disallowance of $12.0 million in deferred power costs in 2004. The increase in electric gross margin was also due to the Idaho electric general rate increase implemented in September 2004, as well as customer growth. 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 and the Washington natural gas general rate increase implemented in November 2004, as well as customer growth in the Washington, Idaho and Oregon service territories. The effects of general rate increases and customer growth were partially offset by the sale of the South Lake Tahoe natural gas operations in April 2005.

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


	Electric Operating Revenues				Electric Energy MWh sales
	2005		2004		2005	2004
Residential	$	211,934	$	209,518	3,420	3,343
Commercial		203,480		201,775	2,994	2,919
Industrial		91,552		90,288	2,091	2,076
Public street and highway lighting		4,898		4,847	25	25

Total retail		511,864		506,428	8,530	8,363
Wholesale		151,429		62,399	2,508	1,472
Sales of fuel		41,831		63,990	—	—
Other		17,988		19,264	—	—

Total	$	723,112	$	652,081	11,038	9,835

Retail electric revenues increased $5.4 million for 2005 from 2004. This increase was primarily due to an increase in total MWhs sold (increased revenues $10.0 million), partially offset by a decrease in revenue per MWh (decreased revenues $4.6 million). The increase in total MWhs sold was primarily due to customer growth and increased use per customer from colder weather during the fourth quarter heating season, partially offset by warmer weather during the first quarter heating season and colder weather during the third quarter cooling season. Total heating degree days at Spokane, Washington for 2005 increased as compared to 2004 with both periods warmer than normal. Total cooling degree days at Spokane, Washington for 2005 decreased as compared to 2004 with both periods warmer than normal. 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 Idaho general rate case increased gross margin, income from operations and net income for 2005 as compared to 2004, it did not have a significant effect on operating revenues.

Wholesale electric revenues increased $89.0 million primarily due to an increase in wholesale sales volumes (increased revenues $62.6 million) and partially due to an increase in wholesale sales prices (increased revenues $26.4 million). The increase in wholesale sales volumes reflects added generation capacity, earlier-than-normal and better-than-anticipated runoff to hydroelectric generating assets during 2005 and lower than anticipated retail loads, which resulted in excess resources that were sold in the wholesale market.

Sales of fuel decreased $22.2 million as a greater percentage of fuel purchases were used in generation. Sales of fuel represents natural gas that was not used for generation when electric wholesale market prices were generally below the cost of operating the natural gas-fired thermal generating units.

Other electric revenues decreased $1.3 million primarily as a result of decreased transmission revenues.

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


	Natural Gas Operating Revenues				Natural Gas Therms Delivered
	2005		2004		2005	2004
Residential	$	229,737	$	194,470	199,433	201,696
Commercial		126,648		104,754	122,981	122,852
Industrial		11,867		9,423	13,534	13,274

Total retail		368,252		308,647	335,948	337,822
Wholesale		58,074		152	72,903	305
Transportation		7,601		8,134	152,990	154,427
Other		4,278		3,560	466	3,030

Total	$	438,205	$	320,493	562,307	495,584

AVISTA CORPORATION

Natural gas revenues increased $117.7 million for 2005 from 2004 due to an increase in retail natural gas revenues and wholesale natural gas revenues. The $59.6 million increase in retail natural gas revenues was primarily due to an increase in retail rates (increased revenues $61.7 million), partially offset by a decrease in volumes (decreased revenues $2.1 million). During September through November of 2005 and 2004, retail rates for natural gas were increased in response to an increase in natural gas costs. In September and November 2004, general natural gas rate increases were implemented in Idaho and Washington, respectively. The decrease in total therms sold was primarily due to the sale of the South Lake Tahoe properties, partially offset by customer growth in the other service territories and a slight increase in use per customer. The increase in wholesale revenues reflects the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process that was implemented at Avista Utilities effective April 1, 2005.

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


	Electric Customers		Natural Gas Customers
	2005	2004	2005	2004
Residential	294,036	288,422	265,294	268,571
Commercial	37,282	36,728	31,652	31,886
Industrial	1,408	1,416	307	311
Public street and highway lighting	421	418	—	—

Total retail	333,147	326,984	297,253	300,768
Wholesale	46	43	12	1
Transportation	—	—	93	81

Total customers	333,193	327,027	297,358	300,850

The decrease in the average number of natural gas customers from 2004 to 2005 was due to the sale of Avista Utilities’ South Lake Tahoe, California natural gas properties in April 2005. Avista Utilities had approximately 18,750 customers in South Lake Tahoe, California as of December 31, 2004.

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


	2005		2004
Heating degree days (1):
Spokane, Washington actual	6,538		6,314
Spokane, Washington 30-year average (2)	6,820		6,820
Percent of average	96	%	93	%
Medford, Oregon actual	4,185		3,933
Medford, Oregon 30-year average (2)	4,533		4,533
Percent of average	92	%	87	%
Cooling degree days (3):
Spokane, Washington actual	409		571
Spokane, Washington 30-year average (2)	394		394
Percent of average	104	%	145	%

(1)

Heating degree days are a common measure used in the utility industry to analyze the demand for natural gas and electricity during the heating season (generally the first and fourth quarters of a fiscal year and to a lesser extent the second quarter). 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 (degree days below historic indicate warmer than average temperatures).

(2)	Computed for the period from 1971 through 2000.

(3)

Cooling degree days are used to analyze the demand for electricity during the summer (generally the third quarter) and indicate when a customer would use electricity for air conditioning. 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 (degree days above historic indicate warmer than average temperatures).

AVISTA CORPORATION

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


	2005			2004
Electric resource costs:
Power purchased	$	186,703		$	145,298
Power cost amortizations, net of deferrals		24,209			22,950
Fuel for generation		93,034			38,406
Other fuel costs		36,636			72,602
Other regulatory amortizations, net		(6,532	)		(2,529	)
Other electric resource costs		9,895			24,231

Total electric resource costs		343,945			300,958

Natural gas resource costs:
Natural gas purchased		335,796			225,908
Natural gas deferrals, net of amortizations		(13,912	)		(12,136	)
Other regulatory amortizations, net		3,767			4,272

Total natural gas resource costs		325,651			218,044

Total resource costs	$	669,596		$	519,002

Power purchased for 2005 increased $41.4 million compared to 2004 primarily due to an increase in the price of power purchases (increased costs $35.4 million) and partially due to an increase in the volume of power purchases (increased costs $6.0 million). The increase in the price of power represents overall increases in the wholesale energy markets. The increase in the volume of power purchased is consistent with the increase in retail and wholesale sales, partially offset by an increase in thermal generation.

Net amortization of deferred power costs was $24.2 million for 2005 compared to $23.0 million for 2004. During 2005, Avista Utilities recovered (collected as revenue) $26.5 million of previously deferred power costs in Washington and $5.7 million in Idaho. There was a decrease in the recovery of previously deferred power costs in Idaho as compared to 2004, which was primarily due to the reduction of the PCA rate surcharge. During 2005, Avista Utilities deferred $4.1 million and $3.9 million of power costs in Washington and Idaho, respectively. There was a decrease in the deferral of power costs due to lower actual electric resource costs as compared to the amount included in base rates in 2005 as compared to 2004.

Fuel for generation for 2005 increased $54.6 million compared to 2004 due to an increase in fuel prices and greater use of thermal generation, which increased 52 percent for 2005 as compared to 2004, primarily due to the addition of the remaining interest in Coyote Springs 2.

Other fuel costs for 2005 decreased $36.0 million compared to 2004. This natural gas fuel was sold with the associated revenues reflected as sales of fuel. Revenues from selling the natural gas exceeded other fuel costs in 2005. This excess revenue is accounted for under the ERM in Washington and the PCA in Idaho. The decrease in other fuel costs was primarily due to a greater percentage of fuel used in generation.

Other electric resource costs for 2005 decreased $14.3 million compared to 2004 primarily due to the disallowance of $12.0 million of deferred power costs in the 2004 Idaho general rate case.

The expense for natural gas purchased for 2005 increased $109.9 million compared to 2004 due to an increase in the cost of natural gas (increased costs $54.5 million) and an increase in total therms purchased (increased costs $55.4 million). The increase in total therms purchased is consistent with an increase in wholesale sales as part of the balancing of loads and resources with the natural gas procurement process. During 2005, Avista Utilities had $13.9 million of net deferrals of natural gas costs compared to $12.1 million of net deferrals for 2004. The increase reflects higher natural gas prices, partially offset by increased natural gas rates to recover deferred natural gas costs.

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 write-offs of $14.4 million ($9.4 million, net of tax) related to the 2004 Idaho general rate case. Excluding the write-offs, net income and income from operations 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, depreciation and amortization, and taxes other than income taxes.

AVISTA CORPORATION

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


	Electric				Natural Gas				Total
	2004		2003		2004		2003		2004		2003
Operating revenues	$	652,081	$	650,922	$	320,493	$	277,289	$	972,574	$	928,211
Resource costs		300,958		299,428		218,044		183,669		519,002		483,097

Gross margin	$	351,123	$	351,494	$	102,449	$	93,620	$	453,572	$	445,114

Avista Utilities’ operating revenues increased $44.4 million and resource costs increased $35.9 million, which resulted in an increase of $8.5 million in gross margin for 2004 as compared to 2003. The gross margin on natural gas sales increased $8.8 million and the gross margin on electric sales decreased $0.3 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 slight decrease in electric gross margin was primarily due to the disallowance of $12.0 million of deferred power costs in the Idaho general rate case, partially offset by the Idaho electric general rate increase implemented in September 2004 as well as customer growth.

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 Revenues				Electric Energy 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

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 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.

AVISTA CORPORATION

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 Operating Revenues				Natural Gas 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.

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


	Electric Customers		Natural Gas 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)	4,533		4,533
Percentage of average	87	%	89	%
Cooling degree days (3):
Spokane, Washington actual	571		578
Spokane, Washington 30-year average (2)	394		394
Percent of average	145	%	147	%

(1)

AVISTA CORPORATION

(2)	Computed for the period from 1971 through 2000.

(3)

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		(2,529	)		541
Other electric resource costs		24,231			11,633

Total electric resource costs		300,958			299,428

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		4,272			2,991

Total natural gas resource costs		218,044			183,669

Total resource costs	$	519,002		$	483,097

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).

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 in 2004 and 2003. 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 $12.6 million compared to 2003 primarily due to the disallowance of $12.0 million of deferred power costs in the Idaho general rate case.

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.

AVISTA CORPORATION

Energy Marketing and Resource Management

Energy Marketing and Resource Management primarily includes the results of Avista Energy, as well as Avista Power.

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

•

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

•

Optimization of generation 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.

•

Marketing natural gas to end-user industrial and commercial customers.

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. 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):


	2005			2004			2003
Net realized gains	$	40,142		$	39,520		$	82,317
Net unrealized losses		(38,126	)		(678	)		(22,128	)

Total gross margin (operating revenues less resource costs)	$	2,016		$	38,842		$	60,189

Overall segment results for 2005 compared to 2004

Energy Marketing and Resource Management’s net loss was $8.6 million for 2005 compared to net income of $9.7 million for 2004. The net loss was primarily due to changes in natural gas prices relative to the positions that Avista Energy had taken in the natural gas market. While Avista Energy’s portfolio was within its position limits and in accordance with its risk management practices, losses can and do occur when the market moves contrary to its positions, which occurred during 2005. As markets moved counter to certain contracts, Avista Energy acted to adjust its position consistent with established risk management policies. This process reduced the market risk; however, it had the effect of locking in losses on certain natural gas positions during 2005. While Avista Energy reduced the market risk in its natural gas trading portfolio considerably in the second half of 2005, some losses did continue to occur during the fourth quarter as Avista Energy continued to unwind positions established in earlier periods.

Avista Energy continued to produce positive results on the power side of its business in 2005, which includes trading, marketing and managing the output and availability of generation assets owned by other entities. However, gains from the power side of Avista Energy’s business were less in 2005 as compared to 2004.

Total assets for the Energy Marketing and Resource Management segment increased $1,009.5 million from December 31, 2004 to December 31, 2005 primarily as a result of the increase in commodity prices (particularly natural gas) and the effect on Avista Energy’s derivative commodity assets.

Overall segment results for 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 affected by the difference in the economic management and the required accounting for certain contracts and physical assets under management (see discussion below), as well as 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 related to increases in market liquidity in the Western power markets. Avista Energy’s commodity portfolio was historically valued using third-party broker

AVISTA CORPORATION

market quotes for the first 24 months and using a model for the long-term portion of the portfolio. Increased market liquidity 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.

Analysis of differences in the economic management and the required accounting for certain contracts and physical assets under management

The operations of Avista Energy are managed on an economic basis reflecting all contracts and assets under management at estimated market value, which is different from the required accounting for certain contracts and physical assets under management. Under SFAS No. 133, certain contracts, which are considered derivatives and accounted for at market value, economically hedge other contracts and physical assets under management, which are not considered derivatives and are generally accounted for at the lower of cost or market value. The accounting treatment does not affect the underlying cash flows or economics of these transactions. These differences are generally reversed in future periods as market values change or the contracts are settled or realized. These differences primarily relate to Avista Energy’s management of natural gas inventory and Avista Energy’s control of natural gas-fired generation through a power purchase agreement.

Avista Energy is affected by earnings volatility associated with its economic management of natural gas inventory. Generally, injections of natural gas into storage take place in the summer months and natural gas is withdrawn from inventory in the winter months. Avista Energy economically hedges the value of natural gas inventory with financial and physical sales, effectively locking in a margin on the natural gas inventory. However, accounting rules require the natural gas inventory to be carried at the lower of cost or market, while the forward 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 generally do not affect the recorded value for natural gas inventory. Therefore, if Avista Energy enters into a forward contract to sell natural gas as an economic hedge against the value of natural gas inventory, and market prices subsequently increase, a loss with respect to the forward contract is recorded in net income. While the market value of the natural gas inventory has also increased, the natural gas inventory remains recorded at the lower of cost or market value. During 2005, increases in the market price of natural gas and changes in inventory balances had a negative effect on net income of $2.7 million with respect to Avista Energy’s economic management of natural gas inventory. During 2004, this activity and changes in natural gas prices had a positive effect on net income of $0.9 million. During 2003, this activity and changes in natural gas prices had a negative effect on net income of $1.6 million. In early 2006, Avista Energy made the economic decision to sell its natural gas inventory forward for delivery in the first quarter of 2007. This transaction will allow Avista Energy to capture approximately $4 million of after-tax economic value. This forward sale will have to be marked to market in 2006, and it will result in earnings volatility. However, this decision is part of the prudent economic management of Avista Energy’s assets.

Avista Energy controls natural gas-fired generation through a power purchase agreement related to 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 economically hedges the value of this power purchase agreement by entering into contracts to buy and sell natural gas and electricity during certain time periods in the future. 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 that are recorded at estimated market value. 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 combinations of accounting treatments. However, not all of these contracts qualify for hedge accounting. Avista Energy will continue to recognize changes in the 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. Similar to natural gas inventory, the power purchase agreement is economically managed as if it is recorded at estimated market value. During 2005, changes in natural gas and electricity prices for the future delivery periods in which the contract had been economically hedged (but not hedged in accordance with SFAS No. 133) had a positive effect on net income of approximately $1.8 million. During 2004, this activity and changes in prices had a negative effect on net income of approximately $2.4 million. During 2003, this activity and changes in prices had a positive effect on net income of approximately $4.7 million.

Avista Energy has other differences between the economic management and the required accounting for certain contracts and physical assets under management, which have not been as significant as those described above.

AVISTA CORPORATION

However, these items could become more significant in the future and Avista Energy could enter into new contracts and agreements that could result in significant differences in future periods.

Analysis of operating revenues, resource costs and gross margin for 2005 compared to 2004

Operating revenues decreased $108.2 million and resource costs decreased $71.4 million for 2005 as compared to 2004 resulting in a decrease in gross margin of $36.8 million. Operating revenues decreased primarily due to decreased revenues under the Agency Agreement with Avista Utilities as natural gas procurement operations were transitioned to Avista Utilities effective April 1, 2005, and decreased net trading margin on contracts accounted for under SFAS No. 133, partially offset by increased revenues for Avista Energy Canada. Resource costs decreased primarily due to decreased resource costs under the Agency Agreement with Avista Utilities, partially offset by increased resource costs for Avista Energy Canada.

Avista Energy’s gross margin (operating revenues less resource costs) was $2.0 million for 2005 compared to $38.8 million for 2004. The decrease in gross margin was primarily due to the increase in natural gas prices and the resulting impact on Avista Energy’s natural gas positions. In addition, unfavorable movements in power prices also had a negative effect on Avista Energy’s gross margin for 2005 as compared to 2004.

Net realized gains increased to $40.1 million for 2005 from $39.5 million for 2004. The slight increase in net realized gains was due to increased net gains on settled financial transactions and physical electric transactions, partially offset by increased net losses on physical natural gas transactions and increased transmission and transportation fees. The total mark-to-market adjustment for Energy Marketing and Resource Management was a net unrealized loss of $38.1 million for 2005 compared to a net unrealized loss of $0.7 million for 2004. The net unrealized loss for 2005 was primarily due to realization of physical electric transactions and price movements that were unfavorable to Avista Energy’s positions.

Analysis of operating revenues, resource costs and gross margin for 2004 compared to 2003

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. Operating revenues decreased 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. Resource costs decreased primarily due to decreased resource costs for Avista Energy Canada and decreased resource costs under the Agency Agreement with Avista Utilities.

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. 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. 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.

AVISTA CORPORATION

Energy trading activities and positions

The following table summarizes information with respect to Avista Energy’s trading activities during 2005 (dollars in thousands):


	Electric Assets net of Liabilities			Natural Gas Assets net of Liabilities			Total Unrealized Gain (Loss)
Fair value of contracts as of December 31, 2004	$	58,965		$	11,341		$	70,306
Less contracts settled during 2005 (1)		(86,272	)		46,130			(40,142	)
Fair value of new contracts when entered into during 2005 (2)		—			—			—
Change in fair value due to changes in valuation techniques (3)		—			—			—
Change in fair value attributable to market prices and other market changes		45,989			(41,702	)		4,287

Fair value of contracts as of December 31, 2005	$	18,682		$	15,769		$	34,451

(1)	Contracts settled during 2005 include those contracts that were open in 2004 but settled during 2005 as well as new contracts entered into and settled during 2005. Amount represents net realized gains associated with these settled transactions.

(2)	Avista Energy did not enter into any origination transactions during 2005 in which dealer profit or mark-to-market gain or loss was recorded at inception.

(3)	During 2005, Avista Energy did not experience a change in fair value due to changes in valuation techniques.

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, 2005 (dollars in thousands):


	Less than one year			Greater than one and less than three years			Greater than three and less than five years			Greater than five years			Total
Electric assets (liabilities), net
Prices from other external sources (1)	$	620		$	34,537		$	—		$	—		$	35,157
Fair value based on valuation models (2)		(1,502	)		(2,121	)		12,892			(25,744	)		(16,475	)

Total electric assets (liabilities), net	$	(882	)	$	32,416		$	12,892		$	(25,744	)	$	18,682

Natural gas assets (liabilities), net
Prices from other external sources (1)	$	11,247		$	4,687		$	—		$	—		$	15,934
Fair value based on valuation models (3)		1,451			(1,421	)		(195	)		—			(165	)

Total natural gas assets (liabilities), net	$	12,698		$	3,266		$	(195	)	$	—		$	15,769

(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)

Avista Power

The results for Avista Power did not have a significant effect on the results for the Energy Marketing and Resource Management segment for 2005. 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 other operating expenses. The effect on net income from these impairment charges was $3.3 million and $3.2 million, net of tax, for 2004 and 2003, respectively.

AVISTA CORPORATION

Avista Advantage

2005 compared to 2004

Net income for Avista Advantage was $3.9 million for 2005 compared to $0.6 million for 2004. Operating revenues for Avista Advantage increased $8.3 million and operating expenses increased $3.1 million as compared to 2004. The increase in operating revenues was primarily due to the expansion of Avista Advantage’s customer base. Avista Advantage has approximately 350 customers representing approximately 175,000 billed sites in North America. The number of billed sites increased by approximately 33,000, or 24 percent, in 2005. Avista Advantage continues to have strong customer retention with an average 95 percent retention rate over the past three years. The increase in operating expenses over 2004 primarily reflects increased labor costs necessary to serve an expanding customer base, partially offset by increased efficiencies and the settlement of an employment contract during 2004. Avista Advantage’s average cost of processing a bill decreased 6 percent for 2005 as compared to 2004.

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.

Other Business Segment

2005 compared to 2004

The net loss from this business segment was $2.6 million for 2005 compared to a net loss of $7.2 million (excluding the cumulative effect of accounting change) for 2004. The decrease 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 environmental liabilities at Avista Development and Avista Capital’s purchase of Avista Advantage preferred stock at a premium during 2004. Operating revenues from this business segment increased $1.4 million and operating expenses decreased $3.6 million, respectively, for 2005 as compared to 2004. The net loss for AM&D was $0.8 million for 2005 compared to $1.0 million for 2004 (excluding the impairment of goodwill).

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 environmental liabilities 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 $3.6 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 net loss from AM&D decreased to $1.0 million for 2004 (excluding the impairment of goodwill), from $2.3 million for 2003.

New Accounting Standards

Effective January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment,” which 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 expects to record compensation expense (net of tax) of approximately $0.4 million in 2006 related to the periodic vesting of stock options granted to employees prior to 2005. The Company also expects to record compensation expense (net of tax) of approximately $1.7 million, $1.1 million and $0.5 million in 2006, 2007 and 2008, respectively, for performance share awards granted to employees in 2004, 2005 and the first quarter of 2006. For further information see “Note 2 of the Notes to Consolidated Financial Statements.”

AVISTA CORPORATION

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 effect 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 and 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, and the Company expects to recover 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 when 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 a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Utilities’ management of its loads and resources and certain contracts are considered derivative instruments. 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. Quoted market prices and forward price curves are used to estimate the fair value of Avista Utilities’ derivative commodity instruments. As such, the fair value of Avista Utilities’ derivative commodity instruments, which are recorded on the Consolidated Balance Sheet, are sensitive to market price fluctuations that can occur on a daily basis.

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. 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

AVISTA CORPORATION

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 has implemented hedge accounting in accordance with SFAS No. 133. 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. As of December 31, 2005, 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 2005, the pension plan funding deficit increased as compared to the end of 2004. As such, the Company increased the additional minimum liability for the unfunded accumulated benefit obligation by $2.8 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 $2.3 million, net of tax, for 2005.

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 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 12 of the Notes to Consolidated Financial Statements.”

The Company’s pension costs (including its Supplemental Executive Retirement Plan (SERP)) were $13.4 million, $14.9 million and $16.1 million for 2005, 2004 and 2003, 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 affect 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 2005, 2004 and 2003 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 and the key assumption of the expected long-term return on assets in 2005. Such change had an effect on reported pension costs in 2005, 2004 and 2003 and may have an effect 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.

AVISTA CORPORATION

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 used a discount rate of 5.75 percent in 2005 and 2004 for estimating the benefit obligation. 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 8.5 percent in 2005, and 8 percent in each of 2004 and 2003. For 2005, 2004 and 2003, the actual return on plan assets, net of fees, was a gain of $11.3 million (or 6.1 percent), $16.1 million (or 10.4 percent) and $32.3 million (or 23.3 percent), respectively. The pension plan asset allocation was modified in 2003 to include hedge, real estate and actively managed large cap growth and value funds and decrease fixed income and small cap equities allocations. The estimated long-term rate of return on assets was analyzed based upon the revised investment portfolio. The assumed long-term rate of return on assets was increased in 2005 based upon the analysis.

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


Actuarial Assumption	Change in Assumption		Effect on Projected Benefit Obligation			Effect on Pension Liability			Effect on Pension Cost
Expected long-term return on plan assets	-0.5	%	$	—		$	—	*	$	937
Expected long-term return on plan assets	+0.5	%		—			—	*		(936	)
Discount rate	-0.5	%		21,506			15,444			2,057
Discount rate	+0.5	%		(19,306	)		(13,964	)		(1,868	)

*	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 effect on the total pension liability.

The Company also has a SERP that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $0.6 million, $1.8 million and $0.3 million related to the SERP in 2005, 2004 and 2003, respectively. This resulted in a charge to other comprehensive income of $0.4 million, $1.2 million and $0.2 million, net of tax, for 2005, 2004 and 2003, respectively.

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. Assumed health care cost trend rates have a significant effect on the amounts reported for the postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2005 by $1.4 million and the service and interest cost by $0.1 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, 2005 by $1.2 million and the service and interest cost by $0.1 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.

AVISTA CORPORATION

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During 2005, positive cash flows from operating activities of $128.5 million, proceeds from property sales (primarily the sale of the Company’s South Lake Tahoe natural gas properties) of $17.2 million and an overall reduction in the Company’s consolidated cash position of $62.4 million were used to fund the majority of the Company’s cash requirements, including utility capital expenditures of $213.7 million and dividends of $26.4 million. To fund the portion of cash needs not met through other sources, total debt increased $37.5 million in 2005. In addition to dividends, the most significant financing transactions in 2005 were long-term debt issuances of $149.6 million and $111.6 million of debt redemptions and maturities. The overall decrease in cash of $62.4 million in 2005 primarily reflects a decrease in cash at Avista Energy primarily due to an increase of $28.7 million in cash deposited with counterparties as collateral funds, as well as Avista Energy’s net loss for the year.

Operating Activities Net cash provided by operating activities was $128.5 million for 2005 compared to $118.0 million for 2004. Net cash used in working capital components was $57.5 million for 2005, compared to net cash used of $79.9 million for 2004. The net cash used during 2005 primarily reflects an increase in accounts receivable and cash deposits with counterparties (representing cash deposited as collateral funds at Avista Energy), partially offset by a net increase in the balance outstanding under the Company’s revolving accounts receivable sales facility, and an increase in accounts payable. The $28.7 million increase in deposits with counterparties was due to high natural gas prices and the posting of cash collateral for margin requirements in addition to letters of credit issued under Avista Energy’s credit line. The significant increase in accounts receivable and accounts payable was primarily due to an increase in energy commodity prices, as well as increased natural gas wholesale sales and purchases at Avista Utilities. The net cash used in 2004 primarily reflects a decrease in deposits from counterparties (representing collateral funds returned), which substituted cash collateral with letters of credit. This was partially offset by an increase in accounts payable. Significant changes in non-cash items included a $37.4 million change in energy commodity assets and liabilities, representing the change to an unrealized loss of $38.1 million on energy trading activities for Avista Energy for 2005 from an unrealized loss of $0.7 million for 2004.

Investing Activities Net cash used in investing activities was $197.6 million for 2005, an increase compared to $129.1 million for 2004. Avista Corp. increased utility capital expenditures in order to meet load growth needs and to continue to provide reliable service to its customers. Utility capital expenditures totaled $213.7 million, the most significant of which were the acquisition of the remaining interest in Coyote Springs 2, transmission system enhancements, and the repurchase of the Company’s corporate headquarters and central operating facility in Spokane. During 2005, the Company received $17.2 million from the sale of properties (primarily the sale of its South Lake Tahoe natural gas properties).

Financing Activities Net cash provided by financing activities was $6.6 million for 2005 compared to net cash used of $28.7 million for 2004. During 2005, short-term borrowings decreased $5.0 million, which reflects a decrease in the amount of debt outstanding under Avista Corp.’s line of credit. In the fourth quarter of 2005, the Company issued $150.0 million (net proceeds of $149.6 million) of 6.25 percent First Mortgage Bonds due in 2035. During 2005, Avista Corp. redeemed a total of $26.0 million of medium-term notes scheduled to mature in future years, repaid $54.6 million of WP Funding LP debt and $31.0 million of long-term debt matured. Cash dividends paid increased to $26.4 million (or 54.5 cents per share) for 2005 from $24.9 million (or 51.5 cents per share) for 2004.

During 2004, short-term borrowings decreased $12.0 million, which primarily reflected 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).

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

AVISTA CORPORATION

flows from operations for Avista Utilities include the purchase of electricity and natural gas, other operating expenses, taxes and interest. The primary source and use of operating cash flows for Avista Energy is revenues and costs from realized energy commodity transactions 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.”

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 2005, the Company has repurchased $318.7 million of long-term debt.

The general rate increases that have been implemented at Avista Utilities since 2002 are allowing the Company to continue to improve its liquidity. In December 2005, the WUTC approved a settlement agreement (with certain conditions) related to Avista Utilities’ Washington general rate case that provides for electric and natural gas base rate increases, which are designed to increase annual revenues by $22.4 million effective January 1, 2006. See further details in the section “Avista Utilities - Regulatory Matters.”

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 streamflows for hydroelectric generation, outages at generating facilities and failure of third parties to deliver on energy or capacity contracts. Avista Utilities’ hydroelectric generation was 95 percent of normal in 2005. Including 2005, hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. The Company cannot determine if this trend of lower than normal hydroelectric generation will continue in future years. Avista Utilities forecasts that hydroelectric generation will be near normal in 2006. This is an early forecast, which will change based upon precipitation, temperatures and other variables during the year.

The Company monitors on an ongoing basis the potential liquidity impacts of increasing energy commodity prices, particularly with respect to natural gas, for both Avista Utilities and Avista Energy. The Company believes that it has adequate liquidity through current cash and cash equivalents, Avista Corp.’s $350.0 million committed line of credit and Avista Energy’s $145.0 million committed line of credit to meet the increased cash needs of higher energy commodity prices. Avista Utilities has regulatory mechanisms in place that provide for the deferral and recovery of the majority of its power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect the Company’s cash flow and liquidity.

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):


	2005				2004
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	39,524	2.0	%	$	85,432	4.4	%
Short-term borrowings		63,494	3.2			68,517	3.5
Long-term debt to affiliated trusts		113,403	5.6			113,403	5.8
Long-term debt		989,990	49.4			901,556	46.2

Total debt		1,206,411	60.2			1,168,908	59.9
Preferred stock-cumulative (including current portion)		28,000	1.4			29,750	1.5

Total liabilities		1,234,411	61.6			1,198,658	61.4
Stockholders’ equity		771,128	38.4			753,205	38.6

Total	$	2,005,539	100.0	%	$	1,951,863	100.0	%

AVISTA CORPORATION

The Company’s total debt increased $37.5 million from December 31, 2004 to December 31, 2005 due to the issuance of $150.0 million of long-term debt, partially offset by the redemption and maturity of long-term debt and a decrease in short-term borrowings. The increase in total debt was primarily to fund utility capital expenditures that were in excess of operating cash flows. 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 stockholders’ equity increased $17.9 million during 2005 primarily due to net income, 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 2006. Borrowings under Avista Corp.’s committed line of credit may supplement these funds to the extent necessary and Avista Corp. currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007.

During the fourth quarter of 2005, the Company issued $150.0 million of 6.25 percent First Mortgage Bonds due in 2035. The proceeds from the issuance were used to repay a portion of the borrowings outstanding under the Company’s $350.0 million committed line of credit and for the payment of corporate obligations.

On December 17, 2004, the Company entered into a 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, 2005 and 2004, the Company had $63.0 million and $68.0 million, respectively, of borrowings outstanding. As of December 31, 2005 and 2004, there were $44.1 million and $32.8 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, 2005, the Company was in compliance with this covenant with a ratio of 60.2 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, 2005 to be greater than 1.6 to 1. As of December 31, 2005, the Company was in compliance with this covenant with a ratio of 2.46 to 1.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of its significant subsidiaries (including Avista Energy) 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, 2005, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements.

The Company is restricted under various agreements and its Restated Articles of Incorporation as to the additional preferred stock it can issue. As of December 31, 2005, approximately $398.3 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, 2005, the Company could issue $285.5 million of additional First Mortgage Bonds under the Mortgage and Deed of Trust.

AVISTA CORPORATION

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, 2005, the Company had remaining availability of $109.6 million under this registration statement.

As further discussed at “Avista Utilities - Regulatory Matters,” in December 2005, the WUTC issued an order approving the settlement agreement reached in the Company’s Washington general rate case with certain conditions. The Company agreed to increase the utility equity component to 35 percent by the end of 2007 and to 38 percent by the end of 2008. Failure by the Company to meet those targets could result in a reduction in base rates of 2 percent for each target. The utility equity component was approximately 31 percent as of December 31, 2005.

Beyond expected earnings, the Company is evaluating additional ways to increase its utility equity ratio. Such measures could include delivering original issue shares under the Company’s equity compensation and dividend reinvestment plans, as well as possibly making small common stock issuances, from time to time through underwriters or agents. Regulators in each of the Company’s jurisdictions have approved the issuance of up to 2 million shares of common stock, from time to time, over the next two years (not including shares under equity compensation and dividend reinvestment plans, which have been previously approved by regulators).

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, 2005, Avista Corp. held a short-term subordinated note receivable from Avista Capital in the principal amount of $39.3 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, 2005, 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 effect on its financial condition, results of operations or cash flows. The Company believes that it has made significant efforts in addressing the pension plan funding deficit since 2002, primarily through cash contributions to the plan in excess of the amounts that are required to be funded under the Employee Retirement Income Security Act. The Company made $15 million in cash contributions to the pension plan in each of 2005 and 2004, which brings total pension plan contributions to $54 million from 2002 through 2005. The Company expects to contribute $15 million to the pension plan in 2006.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 22, 2005, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from May 29, 2005 to March 21, 2006. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in operating expenses of Avista Corp. As of December 31, 2005, $85.0 million in accounts receivables were sold under this 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 March 21, 2006 expiration.

AVISTA CORPORATION

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 Company (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. The transaction is structured such that Spokane Energy bears full recourse risk for a loan (balance of $106.5 million as of December 31, 2005) 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.

WP Funding LP

WP Funding LP was formed in 1993 for the purpose of acquiring the natural gas-fired combustion turbine generating facility in Rathdrum, Idaho (Rathdrum CT). FIN 46 required the Company to consolidate WP Funding LP effective for the period ended December 31, 2003 through June 30, 2005. WP Funding LP purchased the Rathdrum CT from Avista Corp. with funds provided by unrelated investors of which 97 percent represented debt and 3 percent represented equity. Avista Corp. operated the Rathdrum CT and leased it from WP Funding LP until September 2005. In September 2005, Avista Corp. terminated (by exercise of a purchase option) the lease agreement with, and acquired the Rathdrum CT from, WP Funding LP. As a result of this transaction, Avista Corp. is no longer including WP Funding LP in its consolidated financial statements. This transaction and deconsolidation did not have a material effect on the Company’s total consolidated assets, liabilities, stockholders’ equity or results of operations. From a consolidated perspective, the Company replaced the $56.3 million of WP Funding LP debt and third-party investment with other borrowings by Avista Corp.

Credit Ratings

The following table summarizes the Company’s credit ratings as of March 1, 2006:


	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	Stable

(1)	Only assets are subordinated debentures of Avista Corporation.

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

Dividends

AVISTA CORPORATION

On November 11, 2005, the Board of Directors declared a quarterly dividend of $0.14 per common share payable on December 15, 2005 to shareholders of record on November 30, 2005. This was an increase of $0.005 per common share over the previous quarterly dividend declared in August 2005. On February 10, 2006, the Board of Directors declared a quarterly dividend of $0.14 per common share payable on March 15, 2006 to shareholders of record on February 24, 2006.

Avista Utilities Operations

Capital expenditures for Avista Utilities were $431.3 million for the years 2003 through 2005. During the years 2006 through 2008, utility capital expenditures are currently expected to be in the range of $160 million to $175 million per year. In addition to continuing needs for Avista Utilities’ distribution system, significant projects include the continued enhancement of Avista Utilities’ transmission system and upgrades to generating facilities. 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. Long-term debt maturities and mandatory redemptions of preferred stock are expected to total approximately $567 million during the period from 2006 through 2008. During 2006, internally generated funds and short-term borrowing arrangements are expected to be sufficient to fund these requirements. However, the Company currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007. In 2007 and 2008, the Company will most likely need to issue additional long-term debt to fund these obligations, which include long-term debt maturities of approximately $500 million. The Company has already locked in the interest rate on $200 million of long-term debt issuances during this period through forward-starting interest rate swap agreements.

Avista Utilities is committed to investment in its generation, transmission and distribution systems with a focus on increasing capacity and improving reliability. Avista Utilities continues to upgrade its hydroelectric plants to increase their availability and capture additional output. Currently, plans call for upgrading one unit each year for the next five years. As outlined in Avista Utilities’ 2005 Electric Integrated Resource Plan, which was filed with regulators in Washington and Idaho, quarterly energy deficits are projected to begin in 2007 and annual energy deficits are projected to begin in 2010. To help meet forecasted increases in electric loads, Avista Utilities issued a request for proposals in January 2006 to consider adding approximately 35 average megawatts of long-term renewable energy supplies to begin in the fourth quarter of 2007. In early 2006, Avista Utilities has also entered into an agreement with Idaho Power to jointly investigate possible future coal-based generation resources.

As of December 31, 2005, Avista Utilities had $3.8 million of restricted cash. The restricted cash relates to deposits for Avista Corp.’s interest rate swap agreements.

Avista Utilities held cash deposits from other parties in the amount of $9.0 million as of December 31, 2005, which is included in deposits from counterparties on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

See “Notes 5, 15, 16, 17, 18, 21, 22 and 23 of Notes to Consolidated Financial Statements” for additional details related to financing activities.

Energy Marketing and Resource Management Operations

AVISTA CORPORATION

$50.0 million. No cash advances were outstanding as of December 31, 2005 and 2004. Letters of credit in the aggregate amount of $125.3 million and $91.3 million were outstanding as of December 31, 2005 and 2004, respectively. The cash deposits of Avista Energy at the respective banks collateralized $18.2 million and $21.5 million of these letters of credit as of December 31, 2005 and 2004, respectively, which is reflected as restricted cash on the Consolidated Balance Sheets. The increase in letters of credit outstanding is partially due to an increase in commodity prices, particularly with respect to natural gas.

The Avista Energy credit agreement continues to contain 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 continues to contain covenants and other restrictions related to the co-borrowers’ 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. These covenants, certain counterparty agreements and 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, 2005. Prior to the July 13, 2005 amendment, a reduction in the credit rating of Avista Corp. would have represented an event of default under Avista Energy’s credit agreement. The July 13, 2005 amendment to the credit agreement removed this covenant.

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 $37.7 million as of December 31, 2005. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $419.3 million as of December 31, 2005.

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 2005, Avista Energy’s maximum total outstanding short-term loan to Avista Capital was $40.2 million including accrued interest. As of December 31, 2005, 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 $59.4 million as of December 31, 2005, an increase of $28.7 million from December 31, 2004 due to high natural gas prices and the posting of cash collateral for margin requirements in addition to letters of credit issued under Avista Energy’s credit line. Avista Energy held cash deposits from other parties in the amount of $4.8 million as of December 31, 2005, which is included in deposits from counterparties on the Consolidated Balance Sheet. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

As of December 31, 2005, Avista Energy had $22.9 million in cash, as well as $21.8 million of restricted cash. Avista Energy’s total cash (not including restricted cash) decreased $61.8 million during 2005 primarily due to an increase in cash deposited with counterparties as collateral funds of $28.7 million, dividends to Avista Capital of $15.1 million, which flowed up to Avista Corp. and were used for general corporate purposes, as well as Avista Energy’s net loss for the year.

Capital expenditures for the Energy Marketing and Resource Management companies were $5.0 million for the years 2003 through 2005. Capital expenditures for this segment are not expected to be significant to Avista Corp.’s consolidated cash flows and financial condition during the years 2006 through 2008.

Avista Advantage Operations

Capital expenditures for Avista Advantage were $2.4 million for the years 2003 through 2005. Capital expenditures for the years 2006 through 2008 are not expected to be significant to Avista Corp.’s consolidated cash flows and financial condition and should be funded by Avista Advantage’s cash flows from operations.

As of December 31, 2005, Avista Advantage had $1.4 million of debt outstanding related to capital leases.

AVISTA CORPORATION

Other Operations

Capital expenditures for these companies were $3.1 million for the years 2003 through 2005. Capital expenditures for the years 2006 through 2008 in this segment are not expected to be significant to Avista Corp.’s consolidated cash flows and financial condition.

As of December 31, 2005, this business segment had $7.6 million of debt outstanding which included 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, 2005 (dollars in millions):


	2006		2007		2008		2009		2010		Thereafter
Avista Utilities:
Long-term debt maturities (1)	$	38	$	176	$	325	$	—	$	35	$	441
Long-term debt to affiliated trusts (1)		—		—		—		—		—		113
Interest on debt (2)		95		89		81		77		75		—
Short-term borrowings (3)		63		—		—		—		—		—
Accounts receivable sales (4)		85		—		—		—		—		—
Preferred stock redemptions (1)		2		26		—		—		—		—
Energy purchase contracts (5)		364		162		148		144		144		727
Public Utility District contracts (5)		4		4		4		4		4		64
Operating lease obligations (6)		2		1		1		1		—		2
Capital lease obligations (6)		1		1		1		—		—		—
Other obligations (7)		14		14		14		14		14		195
Information services contracts		11		11		12		12		12		26
Pension plan funding (9)		15		15		15		15		—		—
Avista Capital (consolidated):
Long-term debt		—		—		—		—		—		7
Short-term borrowings		1		—		—		—		—		—
Energy purchase contracts (8)		1,010		232		226		205		196		347
Operating lease obligations (6)		3		3		3		3		1		—
Capital lease obligations (6)		1		1		—		—		—		—

Total contractual obligations	$	1,709	$	735	$	830	$	475	$	481	$	1,922

(1)

For 2006, 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. However, the Company currently expects to issue long-term debt in the fourth quarter of 2006 primarily to fund debt that matures in the first quarter of 2007. In years subsequent to 2006, the Company will most likely need to issue additional long-term debt to fund these obligations.

(2)	Represents the Company’s estimate of interest payments on debt. The Company will make interest payments beyond 2010; however, the Company has not made an estimate of such payments at this time.

(3)	Represents $63 million outstanding under a $350 million revolving line of credit.

(4)	Represents $85 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.

(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 2009. The Company cannot reasonably estimate pension plan contributions beyond 2009 at this time.

AVISTA CORPORATION

In addition to the contractual obligations disclosed above, the Company will incur additional operating costs and capital expenditures in future periods for which it is not contractually obligated as part of its normal business operations.

As of December 31, 2005, 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. Prior to the July 13, 2005 amendment, a reduction in the credit rating of Avista Corp. would have represented an event of default under Avista Energy’s credit agreement. The July 13, 2005 amendment to the credit agreement removed this covenant.

Competition

Avista Utilities’ retail electric and natural gas distribution business has historically been recognized as a natural monopoly. 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. 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. Competition for available electric resources can be critical to utilities as surplus power resources are absorbed by load growth. Avista Utilities’ electric and natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.

The Energy Policy Act of 1992 (1992 Energy Act) removed certain barriers to a competitive wholesale market. The 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.

Participants in the wholesale energy markets include other utilities, federal power marketing agencies, energy marketing and trading companies, independent power producers, financial institutions, and commodity brokers. Avista Corp. actively monitors and participates as appropriate in energy industry developments to maintain and enhance its ability to effectively participate in wholesale energy 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 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 ERM dead band in Washington, are deferred on the Consolidated Balance Sheets for the opportunity for recovery through future retail rates. These deferred power and natural gas costs are subject to review for prudence and recoverability and as such certain deferred costs may be disallowed by the respective regulatory agencies.

AVISTA CORPORATION

Avista Utilities’ hydroelectric generation was 95 percent of normal in 2005. Including 2005, hydroelectric generation has been below normal (based on a 70-year average) for 5 of the past 6 years. The Company cannot determine if this trend of lower than normal hydroelectric generation will continue in future years. Avista Utilities forecasts that hydroelectric generation will be near normal in 2006. This is an early forecast, which will change based upon precipitation, temperatures and other variables during the year. 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.”

During recent years, natural gas prices have been volatile with a general upward trend. Avista Utilities’ average prices per dekatherm were $8.13, $6.62 and $5.50 in 2005, 2004 and 2003, respectively. The Company continues to be concerned about the impact that increasing rates have on its customers, which could reduce future demand for natural gas. However, market prices for natural gas continue to be competitive compared to alternative fuel sources for residential, commercial and industrial customers. The Company continues to discuss its natural gas purchase and hedging strategies with its regulators. 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, increases 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 natural gas 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, 2005, 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 “California Refund Proceeding” and “Pacific Northwest Refund Proceeding” in “Note 26 of the Notes to Consolidated Financial Statements” for further information with respect to the refund proceedings.

Avista Utilities and Avista Energy engage in wholesale sales and purchases of energy commodities and, accordingly, are subject to commodity price risk, credit risk and other risks associated with these activities.

Commodity Price Risk. Both Avista Utilities and Avista Energy are subject to energy commodity price risk. 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 on a regional basis, the price and availability of fuel for thermal generating plants, and disruptions of or constraints on transmission facilities, among other things. Natural gas prices are affected by a

AVISTA CORPORATION

number of factors, including but not limited to, the adequacy of North American production, the level of imports, the level of inventories, the demand for natural gas as fuel for electric generation, 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 and electricity prices, because of the fuel-switching capabilities of certain energy users. Demand changes caused by variations in the weather and other factors can also affect market prices for electricity and natural gas. Any combination of these factors that results in a shortage of energy generally causes the market price 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.

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 and are exposed to the risk that they may not be able to collect amounts owed to them. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits have been established. 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 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, but not limited to, 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 affect Avista Energy’s overall exposure to credit risk because the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

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.

AVISTA CORPORATION

Other Operating Risks. In addition to commodity price risk, Avista Utilities’ commodity positions are subject to operational and event risks including, among others, increases or decreases in load demand, blackouts or disruptions to transmission or transportation systems, fuel quality, 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. 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 rates. Additionally, amounts borrowed under the Company’s $350.0 million 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, 2005, Avista Corp. had a derivative liability of $10.0 million and provided cash collateral of $3.8 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, 2005 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 natural 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, 2005. Also, Avista Utilities has foreign currency risk as natural gas procurement operations have been implemented in 2005 and a significant portion of Avista Utilities’ natural gas supply is obtained from Canadian sources. This has not had 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 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 of 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 cash 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

AVISTA CORPORATION

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 significantly 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 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. 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 12 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.

Prior to June 30, 2005, Avista Energy utilized a VAR model to assess market risk for the next 8 calendar quarters. Beginning, in July 2005, Avista Energy began measuring VAR in the next 12 calendar quarters, and continues to apply other risk measurement techniques, including price sensitivity stress tests, to assess the future market risk, beyond twelve calendar quarters. The addition of four calendar quarters to the VAR calculation was due to more transparent pricing in longer-term commodity markets, due to new market participants and increased volumes. This change did not have a material effect on the VAR calculations.

As of December 31, 2005, Avista Energy’s estimated potential one-day unfavorable impact on gross margin as measured by VAR was $0.8 million, compared to $0.4 million as of December 31, 2004. The average daily VAR for 2005 was $0.9 million. The high daily VAR was $3.0 million and the low daily VAR was $0.3 million during 2005. Avista Energy was in compliance with its one-day VAR limits during 2005. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

As of December 31, 2005, 84 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, 8 percent represents settlements that were made within thirty days after December 31, 2005.

As of December 31, 2005, 90 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 81 percent represents settlements that were made within thirty days after December 31, 2005.

AVISTA CORPORATION

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.

Based on Avista Utilities’ forecast for electric customer growth of 2.5 percent and natural gas customer growth of 4 percent within its service area, Avista Utilities anticipates retail electric and natural gas load growth will average between 3 and 3.5 percent annually for the next four years. While the number of electric customers is expected to increase, the average annual usage by each residential electric customer is not expected to change significantly. The natural gas load growth is 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.

Succession Planning

Maintaining 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

Long-term global climate changes, particularly with respect to the Pacific Northwest, could have a significant effect on the Company’s business. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of hydroelectric generation capacity. Changing temperatures could also increase or decrease customer demand. The Company’s operations could also be affected by any legislative or regulatory developments in response to global climate changes, including restrictions on the operation of its power generation resources.

The Company continues to monitor legislative developments at both the state and national level with respect to environmental issues, particularly those related to the potential for further restrictions on the operation of its generating plants. Compliance with such legislation could result in increases in capital expenditures and operating expenses. For other environmental issues and other contingencies see “Note 26 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 22 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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have audited the accompanying consolidated balance sheets of Avista Corporation and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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.

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, 2005, 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 6, 2006 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 6, 2006

C ONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Years Ended December 31

Dollars in thousands, except per share amounts


	2005			2004			2003
Operating Revenues:
Utility revenues	$	1,161,317		$	972,574		$	928,211
Non-utility energy marketing and trading revenues		148,010			138,435			161,754
Other non-utility revenues		50,280			40,571			33,420

Total operating revenues		1,359,607			1,151,580			1,123,385

Operating Expenses:
Utility operating expenses:
Resource costs		669,596			519,002			483,097
Other operating expenses		181,478			180,418			165,478
Depreciation and amortization		80,914			72,787			72,068
Taxes other than income taxes		68,044			66,294			60,791
Non-utility operating expenses:
Resource costs		145,994			99,593			101,565
Other operating expenses		59,653			67,378			62,940
Depreciation and amortization		5,997			5,638			5,743

Total operating expenses		1,211,676			1,011,110			951,682

Gain on sale of utility properties		4,093			—			—

Income from operations		152,024			140,470			171,703

Other Income (Expense):
Interest expense		(86,512	)		(87,265	)		(91,505	)
Interest expense to affiliated trusts		(6,202	)		(5,782	)		(1,480	)
Capitalized interest		1,689			1,393			1,092
Other income - net		10,030			8,390			6,173

Total other income (expense)-net		(80,995	)		(83,264	)		(85,720	)

Income from continuing operations before income taxes		71,029			57,206			85,983
Income taxes		25,861			21,592			35,340

Income from continuing operations		45,168			35,614			50,643

Loss from discontinued operations, net of taxes of $(2,985)		—			—			(4,949	)

Net income before cumulative effect of accounting change		45,168			35,614			45,694
Cumulative effect of accounting change, net of taxes of $(248) and $(641)		—			(460	)		(1,190	)

Net income		45,168			35,154			44,504
Preferred stock dividend requirements		—			—			(1,125	)

Income available for common stock	$	45,168		$	35,154		$	43,379

Weighted-average common shares outstanding (thousands), Basic		48,523			48,400			48,232
Weighted-average common shares outstanding (thousands), Diluted		48,979			48,886			48,630
Earnings per common share, basic (Note 24):
Earnings from continuing operations	$	0.93		$	0.74		$	1.03
Loss from discontinued operations		—			—			(0.10	)

Earnings before cumulative effect of accounting change		0.93			0.74			0.93
Loss from cumulative effect of accounting change		—			(0.01	)		(0.03	)

Total earnings per common share, basic	$	0.93		$	0.73		$	0.90

Earnings per common share, diluted (Note 24):
Earnings from continuing operations	$	0.92		$	0.73		$	1.02
Loss from discontinued operations		—			—			(0.10	)

Earnings before cumulative effect of accounting change		0.92			0.73			0.92
Loss from cumulative effect of accounting change		—			(0.01	)		(0.03	)

Total earnings per common share, diluted	$	0.92		$	0.72		$	0.89

Dividends paid per common share	$	0.545		$	0.515		$	0.490

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Years Ended December 31

Dollars in thousands


	2005			2004			2003
Net income	$	45,168		$	35,154		$	44,504

Other Comprehensive Income (Loss):
Foreign currency translation adjustment		268			493			931
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $605, $(1,969) and $51, respectively		1,123			(3,656	)		94
Reclassification adjustment for realized gains on interest rate swap agreements deferred as a regulatory liability - net of taxes of $(1,556)		(2,889	)		—			—
Unfunded accumulated benefit obligation - net of taxes of $(1,444), $(4,086) and $5,097, respectively		(2,681	)		(7,589	)		9,466
Unrealized gains (losses) on derivative commodity instruments - net of taxes of $1,693, $(681) and $1,245, respectively		3,145			(1,264	)		2,313
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(898), $(257) and $(258), respectively		(1,668	)		(477	)		(480	)
Unrealized investment losses - net of taxes of $(34)		(64	)		—			—

Total other comprehensive income (loss)		(2,766	)		(12,493	)		12,324

Comprehensive income	$	42,402		$	22,661		$	56,828

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS

Avista Corporation

As of December 31

Dollars in thousands


	2005		2004
Assets:
Current Assets:
Cash and cash equivalents	$	25,917	$	88,317
Restricted cash		25,634		26,175
Accounts and notes receivable-less allowances of $44,634 and $44,193, respectively		502,947		313,899
Energy commodity derivative assets		918,609		284,231
Utility energy commodity derivative assets		69,494		12,557
Deposits with counterparties		59,354		30,667
Materials and supplies, fuel stock and natural gas stored		54,123		43,404
Deferred income taxes		14,519		12,288
Assets held for sale		11,850		28,479
Other current assets		87,921		68,123

Total current assets		1,770,368		908,140

Net Utility Property:
Utility plant in service		2,847,043		2,666,445
Construction work in progress		64,291		51,260

Total		2,911,334		2,717,705
Less: Accumulated depreciation and amortization		784,917		761,642

Total net utility property		2,126,417		1,956,063

Other Property and Investments:
Investment in exchange power-net		33,483		35,933
Non-utility properties and investments-net		77,731		78,564
Non-current energy commodity derivative assets		511,280		254,657
Investment in affiliated trusts		13,403		13,403
Other property and investments-net		15,058		19,721

Total other property and investments		650,955		402,278

Deferred Charges:
Regulatory assets for deferred income tax		114,109		123,159
Other regulatory assets		26,660		43,428
Non-current utility energy commodity derivative assets		46,731		55,825
Power and natural gas deferrals		147,622		148,206
Unamortized debt expense		48,522		53,413
Other deferred charges		17,110		21,109

Total deferred charges		400,754		445,140

Total assets	$	4,948,494	$	3,711,621

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS (continued)

Avista Corporation

As of December 31

Dollars in thousands


	2005			2004
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	511,427		$	325,194
Energy commodity derivative liabilities		906,794			253,527
Deposits from counterparties		13,724			6,015
Current portion of long-term debt		39,524			85,432
Current portion of preferred stock-cumulative (17,500 shares outstanding)		1,750			1,750
Short-term borrowings		63,494			68,517
Interest accrued		18,643			18,632
Regulatory liability for utility derivatives		66,047			4,486
Other current liabilities		108,485			118,285

Total current liabilities		1,729,888			881,838

Long-term debt		989,990			901,556

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
262,500 and 280,000 shares outstanding ($100 stated value)		26,250			28,000

Other Non-Current Liabilities and Deferred Credits:
Non-current energy commodity derivative liabilities		488,644			215,055
Regulatory liability for utility plant retirement costs		186,635			175,575
Non-current utility energy commodity derivative liabilities		88			33,490
Non-current regulatory liability for utility derivatives		46,643			22,335
Deferred income taxes		488,934			488,471
Other non-current liabilities and deferred credits		106,891			98,693

Total other non-current liabilities and deferred credits		1,317,835			1,033,619

Total liabilities		4,177,366			2,958,416

Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized;
48,593,139 and 48,471,511 shares outstanding		631,084			629,056
Note receivable from employee stock ownership plan		—			(495	)
Capital stock expense and other paid in capital		(10,486	)		(10,677	)
Accumulated other comprehensive loss		(23,299	)		(20,533	)
Retained earnings		173,829			155,854

Total stockholders’ equity		771,128			753,205

Total liabilities and stockholders’ equity	$	4,948,494		$	3,711,621

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

Increase (Decrease) in Cash and Cash Equivalents

Avista Corporation

For the Years Ended December 31

Dollars in thousands


	2005			2004			2003
Continuing Operating Activities:
Net income	$	45,168		$	35,154		$	44,504
Loss from discontinued operations		—			—			4,949
Cumulative effect of accounting change		—			460			1,190
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		86,911			78,425			77,811
Provision for deferred income taxes		8,865			19,168			28,395
Power and natural gas cost amortizations, net of deferrals		9,630			11,087			3,829
Amortization of debt expense		7,762			8,301			7,972
Write-offs and impairments of assets		1,001			21,990			4,900
Energy commodity assets and liabilities		38,126			678			22,128
Gain on sale of utility properties		(4,093	)		—			—
Other		(7,367	)		3,770			(11,214	)
Changes in working capital components:
Sale of customer accounts receivable under revolving agreement-net		13,000			—			7,000
Accounts and notes receivable		(203,363	)		(6,904	)		(4,485	)
Materials and supplies, fuel stock and natural gas stored		(10,642	)		(4,023	)		(682	)
Deposits with counterparties		(28,687	)		6,181			(1,175	)
Other current assets		(19,801	)		(16,283	)		(14,076	)
Accounts payable		189,115			26,909			(41,352	)
Deposits from counterparties		7,709			(91,796	)		5,137
Other current liabilities		(4,789	)		5,996			10,087

Net cash provided by continuing operating activities		128,545			118,045			126,053

Continuing Investing Activities:
Utility property capital expenditures (excluding AFUDC)		(213,652	)		(115,346	)		(102,271	)
Other capital expenditures		(4,044	)		(3,126	)		(3,388	)
Deposit for utility property acquisition		—			(5,000	)		—
Decrease (increase) in restricted cash		541			(9,703	)		(3,489	)
Changes in other property and investments		2,033			517			(5,953	)
Repayments received on notes receivable		318			1,062			1,214
Proceeds from property sales		17,211			2,466			549

Net cash used in continuing investing activities		(197,593	)		(129,130	)		(113,338	)

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

Increase (Decrease) in Cash and Cash Equivalents

Avista Corporation

For the Years Ended December 31

Dollars in thousands


	2005			2004			2003
Continuing Financing Activities:
Increase (decrease) in short-term borrowings	$	(5,023	)	$	(12,008	)	$	50,525
Proceeds from issuance of long-term debt		149,633			89,761			44,795
Redemption and maturity of long-term debt		(111,613	)		(66,857	)		(124,859	)
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		(826	)		(6,710	)		(1,709	)
Long-term debt and short-term borrowing issuance costs		(2,153	)		(6,149	)		(2,430	)
Cash received in interest rate swap agreement		4,445			125			—
Redemption of preferred stock		(1,750	)		(1,750	)		(1,575	)
Distribution to minority interests		(1,688	)		—			—
Issuance of common stock		2,066			4,061			5,497
Repurchase of subsidiary preferred stock		—			(4,285	)		—
Cash dividends paid		(26,443	)		(24,912	)		(24,777	)

Net cash provided by (used in) continuing financing activities		6,648			(28,724	)		(54,533	)

Net cash used in continuing operations		(62,400	)		(39,809	)		(41,818	)
Net cash used in discontinued operations (includes investing activities of $(261))		—			—			(3,342	)

Net decrease in cash and cash equivalents		(62,400	)		(39,809	)		(45,160	)
Cash and cash equivalents at beginning of period		88,317			128,126			173,286

Cash and cash equivalents at end of period	$	25,917		$	88,317		$	128,126

Supplemental Cash Flow Information:
Cash paid during the period:
Interest	$	85,569		$	84,220		$	86,755
Income taxes		26,405			11,321			11,476
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		1,728			(5,625	)		145
Intangible asset related to pension plan		(654	)		(654	)		(654	)
Unfunded accumulated benefit obligation		(3,471	)		(11,022	)		15,198
Unrealized gain (loss) on derivative commodity instruments		2,272			(2,677	)		2,819
Unrealized investment losses		(98	)		—			—

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Avista Corporation

For the Years Ended December 31

Dollars in thousands


	Preferred Stock Series K					Common Stock				Note Receivable from Employee Stock Ownership Plan			Capital Stock Expense and Other Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
	Shares		Amount			Shares	Amount			Note Receivable from Employee Stock Ownership Plan			Capital Stock Expense and Other Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
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								(11	)					273						(409	)		(147	)
Dividend Reinvestment Plan						127,502		2,279															2,279
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

Net income																				45,168			45,168
Equity compensation plan transactions								(196	)					191						(788	)		(793	)
Dividend Reinvestment Plan						121,628		2,224															2,224
Repayments of note receivable											495												495
Other comprehensive loss																	(2,766	)					(2,766	)
Cash dividends paid (common stock)																				(26,443	)		(26,443	)
ESOP dividend tax savings																				38			38

Balance as of December 31, 2005	—			—		48,593,139	$	631,084		$	—		$	(10,486	)	$	(23,299	)	$	173,829		$	771,128

The Accompanying Notes are an Integral Part of These Statements.

AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. 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 and northern Idaho, as well as parts of northeast and southwest Oregon. In April 2005, the Company completed the sale of its South Lake Tahoe, California natural gas distribution properties (see Note 28 for further information). This was the Company’s only regulated utility operation in California. Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility business segments. See Note 29 for business segment information.

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 price risks associated with wholesale purchases and sales of energy commodities.

Basis of Reporting

The consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries, including variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. All significant intercompany balances have been eliminated in consolidation. 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 the market value of energy commodity assets and liabilities, pension and other postretirement benefit plan obligations, contingent liabilities, recoverability of regulatory assets and unbilled revenues. 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 and Oregon. The Company is also subject to federal regulation by the FERC.

Utility Revenues

Utility revenues 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 $13.1 million (net of $57.1 million of unbilled receivables sold) and $13.0 million (net of $48.9 million of unbilled receivables sold) as of December 31, 2005 and 2004, respectively. See Note 5 for information with respect to the sale of accounts receivable. Revenues and resource costs from Avista Utilities’ settled energy contracts that are “booked out” (not physically delivered) are reported on a net basis as part of utility revenues.

AVISTA CORPORATION

Non-Utility Energy Marketing and Trading Revenues

Avista Energy follows Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, with respect to the majority of its contracts. Avista Energy reports the net margin on derivative commodity instruments held for trading as non-utility energy marketing and trading 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 non-utility energy marketing and trading revenues. Revenues from Canadian contracts through Avista Energy Canada, which are not held for trading, and are reported on a gross basis in non-utility energy marketing and trading revenues, totaled $144.6 million, $116.0 million and $107.1 million in 2005, 2004 and 2003, 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.

Other Non-Utility Revenues

Avista Advantage’s service revenues are recognized in the period services are rendered. Setup fees are deferred and recognized over the term of the related customer contracts. Interest earnings on funds held for customers are an integral part of Avista Advantage’s product offerings and are recognized in revenues as earned.

Revenues in the other business segment are generally derived from the operations of Advanced Manufacturing and Development and are recognized when products are shipped to customers.

Advertising Expenses

The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company’s operating expenses in 2005, 2004 and 2003.

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 (primarily state excise taxes and city utility taxes) are recorded as both operating revenue and expense and totaled $43.1 million, $35.0 million and $31.7 million in 2005, 2004 and 2003, respectively.

Other Income-Net

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


	2005			2004			2003
Interest income	$	5,974		$	4,313		$	4,810
Interest on power and natural gas deferrals		7,429			7,855			8,361
Net gain (loss) on the disposition of non-operating assets		318			785			(334	)
Net gain (loss) on investments		156			434			(1,207	)
Premium on repurchase of subsidiary preferred stock		—			(892	)		—
Other expense		(6,228	)		(6,854	)		(7,063	)
Other income		2,381			2,749			1,606

Total	$	10,030		$	8,390		$	6,173

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.

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

AVISTA CORPORATION

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

Prior to January 1, 2006, the Company followed the disclosure only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, employee stock options were 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 was recognized pursuant to the Company’s stock option plans. However, the Company recognized compensation expense related to the initial grant (2003) of performance-based share awards. See Note 2 with respect to the revision of SFAS No. 123, which will result in changes to stock compensation recognition beginning in 2006.

If compensation expense for the Company’s stock-based employee compensation 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:


	2005			2004			2003
Net income (dollars in thousands):
As reported	$	45,168		$	35,154		$	44,504
Add: Total stock-based employee compensation expense included in net income, net of tax		2,211			—			—
Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of tax		(2,911	)		(2,033	)		(2,186	)

Pro forma	$	44,468		$	33,121		$	42,318

Basic and diluted earnings per common share:
Basic as reported	$	0.93		$	0.73		$	0.90
Diluted as reported	$	0.92		$	0.72		$	0.89
Basic pro forma	$	0.92		$	0.68		$	0.85
Diluted pro forma	$	0.91		$	0.68		$	0.85

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss), net of tax, consisted of the following as of December 31 (dollars in thousands):


	2005			2004
Foreign currency translation adjustment	$	1,407		$	1,139
Unfunded accumulated benefit obligation for the pension plan		(19,625	)		(16,944	)
Unrealized loss on interest rate swap agreements		(6,586	)		(4,820	)
Unrealized loss on securities available for sale		(64	)		—
Unrealized gain on derivative commodity instruments		1,569			92

Total accumulated other comprehensive loss	$	(23,299	)	$	(20,533	)

Foreign Currency Translation Adjustment

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

Earnings Per Common Share

Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share is calculated by dividing income available for common stock by diluted weighted average common shares outstanding during the period, including common stock equivalent shares outstanding using the treasury stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares issuable upon exercise of stock options and contingent stock awards. See Note 24 for earnings per common share calculations.

AVISTA CORPORATION

Cash and Cash Equivalents

For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or less when purchased 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 $18.2 million and $21.5 million as collateral for letters of credit issued under Avista Energy’s credit agreement as of December 31, 2005 and 2004, respectively. See Note 17 for further information with respect to Avista Energy’s credit agreement. Restricted cash also includes deposits held in trust of $1.1 million and $1.6 million for certain employees of Avista Energy as part of a bonus retention plan as of December 31, 2005 and 2004, respectively. Restricted cash as of December 31, 2005 and 2004 includes $2.5 million of deposits related to forward contracts at Avista Energy. In addition, restricted cash includes $3.8 million and $0.6 million of deposits related to Avista Corp.’s interest rate swap agreements as of December 31, 2005 and 2004, respectively. See Note 18 for further information with respect to Avista Corp.’s interest rate swap agreements.

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):


	2005			2004			2003
Allowance as of the beginning of the year	$	44,193		$	46,382		$	46,909
Additions expensed during the year		2,867			3,367			1,912
Net deductions		(2,426	)		(5,556	)		(2,439	)

Allowance as of the end of the year	$	44,634		$	44,193		$	46,382

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 and consisted of the following as of December 31 (dollars in thousands):


	2005		2004
Materials and supplies	$	14,253	$	12,409
Fuel stock		3,773		4,050
Natural gas stored		36,097		26,945

Total	$	54,123	$	43,404

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, 2005 assets held for sale included $11.9 million of turbines and related equipment. See Note 4 for the sale of a turbine and related equipment in January 2006. As of December 31, 2004 assets held for sale included $15.2 million of assets related to Avista Utilities’ South Lake Tahoe natural gas properties and $13.3 million of turbines and related equipment. Liabilities held for sale were not significant as of December 31, 2005 and 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 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

AVISTA CORPORATION

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 2005, 2004 and 2003. 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 2.93 percent in 2005, 2.92 percent in 2004 and 2.98 percent in 2003.

The average service lives for the following broad categories of utility property are: electric thermal production - 29 years; hydroelectric production - 77 years; electric transmission - 43 years; electric distribution - 47 years; and natural gas distribution property - 36 years.

The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for which the Company has not recorded asset retirement obligations (see Note 11). The Company had estimated retirement costs of $186.6 million and $175.6 million included as a regulatory liability on the Consolidated Balance Sheets as of December 31, 2005 and 2004, 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) as of December 31, 2005 and December 31, 2004.

During the second quarter of 2005, the Company changed the date of its annual goodwill impairment test to November 30 from March 31. The Company selected the date of November 30 as it is closely aligned with the Company’s annual budget and forecasting process. In addition, the new date provides the Company additional time to meet accelerated public reporting requirements. The Company believes the change will not delay, accelerate or avoid an impairment charge. Accordingly, the Company believes that the accounting change described above is to an alternative accounting principle that is preferable under the circumstances. The Company completed its annual evaluation of goodwill for potential impairment as of March 31, 2005 and November 30, 2005 and determined that goodwill was not impaired at either time.

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 or credits 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 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),

AVISTA CORPORATION

investment in exchange power, regulatory asset for deferred income taxes, unamortized debt expense, regulatory asset for consolidation of variable interest entity, 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):


	2005		2004
Regulatory asset for consolidation of variable interest entity	$	—	$	19,167
Regulatory asset for postretirement benefit obligation		3,309		3,782
Demand side management and conservation programs		12,272		13,792
Asset retirement obligations		2,969		114
Other		8,110		6,573

Total	$	26,660	$	43,428

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 utility energy commodity derivative assets (see Note 6 for further information) and the gain on the general office building sale/leaseback. Those items without a specific line on the Consolidated Balance Sheets are included in 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 $5.6 million as of December 31, 2005.

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 remained with Avista Utilities; however, the assets were managed by Avista Energy through an Agency Agreement. Avista Utilities always managed natural gas procurement for its California operations, which the Company sold in April 2005 (see Note 28).

Effective April 1, 2005, the Natural Gas Benchmark Mechanism and related Agency Agreement were terminated and the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers.

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.

AVISTA CORPORATION

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 8.1 percent as of December 31, 2005. Total deferred power costs for Washington customers were $96.2 million and $113.2 million as of December 31, 2005 and 2004, 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 June 2005, the WUTC issued an order, which approved the recovery of the $10.8 million of deferred power costs incurred for 2004.

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. Avista Utilities accrues interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 2.0 percent on current year deferrals and 4.0 percent on carryover balances as of December 31, 2005. Total deferred power costs for Idaho customers were $8.0 million and $9.5 million as of December 31, 2005 and 2004, 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 $43.4 million and $28.6 million as of December 31, 2005 and 2004, respectively.

Reclassifications

Certain prior period amounts were reclassified to conform to current statement format. These reclassifications were made for comparative purposes and have not affected previously reported total net income or stockholders’ equity. In particular, the net change in restricted cash for 2004 and 2003 was reclassified from operating activities to investing activities in the Consolidated Statements of Cash Flows to conform to the Company’s 2005 presentation. This resulted in an increase to operating cash flows and a corresponding decrease to investing cash flows of $9.7 million and $3.5 million, respectively, from the amounts previously reported for 2004 and 2003.

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 were historically 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

AVISTA CORPORATION

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 Financial Accounting Standards Board (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.

The implementation of FIN 46 resulted in the consolidation of WP Funding, Limited Partnership (WP Funding LP) and the deconsolidation of capital trusts in 2003. 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 beginning in the first quarter of 2004. This resulted in a charge of $0.5 million recorded as a cumulative effect of accounting change for 2004.

In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment,” which supersedes APB No. 25 and SFAS No. 123 and their related implementation guidance. This statement establishes revised 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 provisions of this statement are effective beginning in the first quarter of 2006. The Company expects to record compensation expense (net of tax) of approximately $0.4 million in 2006 related to the periodic vesting of stock options granted to employees prior to 2005. The Company also expects to record compensation expense (net of tax) of approximately $1.7 million, $1.1 million and $0.5 million in 2006, 2007 and 2008, respectively, for performance share awards granted to employees in 2004, 2005 and the first quarter of 2006.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligation” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under FIN 47, the Company is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when the Company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The Company adopted FIN 47 as of December 31, 2005, the effects of which are disclosed in Note 11.

NOTE 3. DISCONTINUED OPERATIONS

Amounts reported as discontinued operations for 2003 represent the operations of Avista Labs. 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 in 2003 (through June 30). The total loss from discontinued operations for 2003 was comprised of a loss from operations of $4.0 million, asset impairment charges of $3.9 million and an income tax benefit of $3.0 million.

AVISTA CORPORATION

NOTE 4. IMPAIRMENT OF ASSETS

In January 2006, the Company completed the sale of a turbine and related equipment owned by Avista Power (Energy Marketing and Resource Management segment). In 2005, the Company recorded impairment charges of $1.0 million for the turbine and related equipment, which is included in other operating expenses in the Consolidated Statements of Income. The turbine and related equipment were classified as assets held for sale as of December 31, 2005.

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 sell the turbine and related equipment, and recorded an impairment charge of $5.1 million, which is included in other operating expenses in the Consolidated Statements of Income.

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 other operating expenses in the Consolidated Statements of Income.

NOTE 5. ACCOUNTS RECEIVABLE SALE

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 22, 2005, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from May 29, 2005 to March 21, 2006. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in other operating expenses of Avista Corp. As of December 31, 2005 and 2004, $85.0 million and $72.0 million in accounts receivables were sold, respectively, under this revolving agreement.

NOTE 6. UTILITY ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES

SFAS No. 133, as amended, 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 orders provide 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

AVISTA CORPORATION

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):


	2005		2004
Current utility energy commodity derivative asset	$	69,494	$	12,557
Current utility energy commodity derivative liability		3,447		8,071
Net current regulatory liability		66,047		4,486
Non-current utility energy commodity derivative asset		46,731		55,825
Non-current utility energy commodity derivative liability		88		33,490
Net non-current regulatory liability		46,643		22,335

Current utility energy commodity derivative liabilities are included in other current liabilities 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. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these exposures, 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

As part of its resource optimization process described above, 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 was 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. Effective April 1, 2005, the management of natural gas procurement functions was moved from Avista Energy back to Avista Utilities. This was required for Washington customers by WUTC orders issued in February 2004, and Avista Utilities’ resulting transition plan approved by the WUTC in April 2004. The Company also elected to move these functions back to Avista Utilities for Idaho and Oregon natural gas customers. The natural gas procurement process includes entering into financial and physical hedging transactions as a means of

AVISTA CORPORATION

managing risks. Avista Utilities always managed natural gas procurement for its California operations, which the Company sold in April 2005 (see Note 28).

Avista Energy

Avista Energy is an electricity and natural gas marketing, trading and resource management business. Avista Energy focuses on optimization of generation 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.

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.

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. 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 non-utility energy marketing and trading 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 non-utility energy marketing and trading 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 non-utility 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 CORPORATION

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.

The following table presents activity related to Avista Energy’s hedge accounting during the years ended December 31 (dollars in thousands):


	2005		2004		2003
Gain related to hedge ineffectiveness recorded in operating revenues	$	8,445	$	1,020	$	—
Gain reclassified from accumulated other comprehensive income (loss) and recognized in earnings (pre-tax)		2,566		735		480

Of the $8.4 million in pre-tax hedge ineffectiveness recorded in operating revenues for 2005, $4.4 million relates to designated hedges that matured during 2005. The balance of $4.0 million relates to designated hedging relationships that were outstanding as of December 31, 2005.

The following table presents the net gain (loss), net of tax, related to Avista Energy’s cash flow hedges as of December 31 (dollars in thousands):


	2005			2004
Accumulated other comprehensive income related to natural gas derivatives	$	11,583		$	1,556
Accumulated other comprehensive loss related to electric derivatives		(10,014	)		(1,464	)

Total accumulated other comprehensive income	$	1,569		$	92

Avista Energy expects to recognize a gain of $0.8 million in earnings during the next 12 months, related to amounts currently in accumulated other comprehensive income. 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, 2005 are set forth below (in thousands of MWhs and mmBTUs):


	Fixed Price Payor	Fixed Price Receiver	Maximum Terms in Years	Index Price Payor	Index Price Receiver	Maximum Terms in Years
Energy commodities (volumes)
Electric	30,048	32,031	12	2,645	4,202	3
Natural gas	279,147	271,286	4	1,544,629	1,551,353	2

The weighted average term of Avista Energy’s electric derivative commodity instruments as of December 31, 2005 was approximately 5 months. The weighted average term of Avista Energy’s natural gas derivative commodity instruments as of December 31, 2005 was approximately 4 months.

AVISTA CORPORATION

Estimated Fair Value The estimated fair value of Avista Energy’s derivative commodity instruments outstanding as of December 31, 2005, and the average estimated fair value of those instruments held during the year ended December 31, 2005, are set forth below (dollars in thousands):


	Estimated Fair Value as of December 31, 2005								Average Estimated Fair Value for the year ended December 31, 2005
	Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities		Current Assets		Long-term Assets		Current Liabilities		Long-term Liabilities
Electric	$	348,709	$	463,214	$	349,592	$	443,649	$	300,208	$	362,360	$	288,297	$	341,777
Natural gas		569,900		48,066		557,202		44,995		373,320		38,171		361,879		31,304

Total	$	918,609	$	511,280	$	906,794	$	488,644	$	673,528	$	400,531	$	650,176	$	373,081

The change in the estimated fair value position of Avista Energy’s energy commodity portfolio, net of reserves for credit and market risk for 2005 was an unrealized loss of $38.1 million and is included in the Consolidated Statements of Income in non-utility energy marketing and trading revenues. The change in the fair value position for 2004 was an unrealized loss of $0.7 million. In 2003, the unrealized loss was $22.1 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.

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 and are exposed to the risk that they may not be able to collect amounts owed to them. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits have been established. 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.

AVISTA CORPORATION

Other Operating Risks

In addition to market and credit risk, Avista Utilities’ commodity positions are subject to operational and event risks including, among others, increases or decreases in load demand, blackouts or disruptions to transmission or transportation systems, fuel quality, 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. 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 $13.7 million and $6.0 million as of December 31, 2005 and 2004, 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 $59.4 million and $30.7 million as of December 31, 2005 and 2004, respectively.

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

NOTE 9. JOINTLY OWNED ELECTRIC FACILITIES

The Company has a 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 expenses for plant in service are included in the corresponding accounts in the Consolidated Statements of Income. The Company’s share of utility plant in service for Colstrip was $323.9 million and accumulated depreciation was $183.2 million as of December 31, 2005.

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):


	2005		2004
Avista Utilities:
Electric production	$	988,539	$	924,933
Electric transmission		369,567		337,651
Electric distribution		790,630		760,400
Construction work-in-progress (CWIP) and other		119,690		109,222

Electric total		2,268,426		2,132,206

Natural gas underground storage		18,550		18,566
Natural gas distribution		471,574		449,155
CWIP and other		56,465		44,691

Natural gas total		546,589		512,412

Common plant (including CWIP)		96,319		73,087

Total Avista Utilities		2,911,334		2,717,705
Energy Marketing and Resource Management ⁽¹⁾		17,360		15,790
Avista Advantage ⁽¹⁾		14,736		13,688
Other ⁽¹⁾		36,624		34,757

Total	$	2,980,054	$	2,781,940

⁽¹⁾	Included in non-utility properties and investments-net on the Consolidated Balance Sheets.

AVISTA CORPORATION

Equipment under capital leases at Avista Utilities totaled $5.6 million and $5.3 million as of December 31, 2005 and 2004, respectively. The associated accumulated depreciation totaled $1.1 million and $0.5 million as of December 31, 2005 and 2004, respectively. Property, plant, and equipment under capital leases at Avista Capital’s subsidiaries totaled $5.2 million and $5.3 million as of December 31, 2005 and 2004, respectively. The associated accumulated depreciation totaled $4.1 million and $3.5 million as of December 31, 2005 and 2004, respectively.

NOTE 11. ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations” which requires the recording of the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the associated costs of the asset retirement obligation are capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. Upon retirement of the asset, the Company either settles the retirement obligation for its recorded amount or incurs a gain or loss. As asset retirement costs are recovered through rates charged to customers, the Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and asset retirement obligations recorded under SFAS 143. The regulatory assets do not earn a return. The adoption of SFAS No. 143 on January 1, 2003 did not have a material effect on the Company’s financial condition, results of operations or cash flows.

As described in Note 2, the Company adopted FIN 47 as of December 31, 2005, which has resulted in the recording of additional asset retirement obligations under SFAS No. 143. Specifically, the Company has recorded liabilities for future asset retirement obligations to (1) restore ponds at Colstrip (2) remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease (3) remove asbestos at the corporate office building and (4) dispose of PCBs in certain transformers. With the adoption of FIN 47, the Company recorded an asset retirement obligation of $3.2 million, a regulatory asset of $2.7 million, capitalized asset retirement costs of $1.0 million and related accumulated depreciation of $0.5 million. Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for removal and disposal of certain transmission and distribution assets, as well as abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.

The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars in thousands):


	2005			2004
Asset retirement obligation at beginning of year	$	1,191		$	660
Asset retirement obligation recognized		3,243			483
Asset retirement obligation settled		(28	)		(20	)
Asset retirement obligation accretion expense		123			68

Asset retirement obligation at end of year	$	4,529		$	1,191

The pro forma asset retirement obligation liability balances as if FIN 47 had been adopted on January 1, 2004 (rather than December 31, 2005) are as follows (dollars in thousands):


Pro forma asset retirement obligation as of January 1, 2004	$	3,538
Pro forma asset retirement obligation as of December 31, 2004	$	4,246

NOTE 12. 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 each of 2005 and 2004, and $12 million in 2003. The Company expects to contribute $15 million to the pension plan in 2006.

AVISTA CORPORATION

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 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 indicated in the table in this Note.

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 fair value of pension plan assets invested in debt and equity securities was based primarily on market prices. The fair value of pension plan assets invested in real estate was determined based on three basic approaches: (1) current cost of reproducing a property less deterioration and functional economic obsolescence (2) capitalization of the property’s net earnings power; and (3) value indicated by recent sales of comparable properties in the market. The fair value of plan assets was determined as of December 31, 2005 and 2004.

As of December 31, 2005 and 2004, the pension plan had assets with a fair value that was less than the present value of the accumulated benefit obligation under the plan. In 2005, the pension plan funding deficit increased as compared to the end of 2004 and as such the Company increased the additional minimum liability for the unfunded accumulated benefit obligation by $2.8 million and reduced 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 $2.3 million, net of taxes of $1.2 million for 2005. In 2004, the pension plan funding deficit increased as compared to the end of 2003 and as such the Company increased the additional minimum liability for the unfunded accumulated benefit obligation by $9.2 million and reduced 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 taxes of $3.5 million for 2004. In 2003, the pension plan funding deficit decreased as compared to the end of 2002 and as such the Company reduced the additional minimum liability for the unfunded accumulated benefit obligation by $15.5 million and the intangible asset by $0.6 million (representing the amount of unrecognized prior service cost) related to the pension plan. This resulted in an increase to other comprehensive income of $9.7 million, net of taxes of $5.2 million for 2003.

The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The Company recorded an additional minimum liability for the unfunded accumulated benefit obligation of $0.6 million, $1.8 million and $0.3 million related to the SERP for 2005, 2004 and 2003, respectively. This resulted in a charge to other comprehensive income of $0.4 million, $1.2 million and $0.2 million, net of tax, for 2005, 2004 and 2003, respectively.

The Company expects that benefit payments under the pension plan and the SERP will total $14.7 million, $15.6 million, $15.6 million, $16.4 million and $18.0 million in 2006, 2007, 2008, 2009 and 2010, respectively. For the ensuing five years (2011 through 2015), the Company expects that benefit payments under the pension plan and the SERP will total $109.6 million.

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. The Company elected to amortize the transition obligation of $34.5 million over a period of twenty years, beginning in 1993. In 2004, the Company recognized the effect of an amendment to the cost-sharing policy, which limits the employer portion of the premium for all retirees. This amendment reduced the accumulated benefit obligation by $4.3 million. The Company expects that benefit payments under the postretirement benefit plan will be $2.7 million, $2.6 million, $2.5 million, $2.3 million and $2.2 million in 2006, 2007, 2008, 2009 and 2010, respectively. For the ensuing five years (2011 through 2015), the Company expects that benefit payments under the postretirement benefit plan will total $9.6 million. The Company expects to contribute $2.7 million to the postretirement benefit plan in 2006, representing expected benefit payments to be paid during the year.

The Company established a Health Reimbursement Arrangement to provide employees with tax-advantaged funds to pay for allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on employees’ years of service and the ending salary. The liability and expense of this plan are included as post-retirement benefits.

AVISTA CORPORATION

The Company uses a December 31 measurement date for its pension and postretirement plans. The following table sets forth the pension and postretirement plan disclosures as of December 31, 2005 and 2004 and the components of net periodic benefit costs for the years ended December 31, 2005, 2004 and 2003 (dollars in thousands):


	Pension Benefits						Post- retirement Benefits
	2005			2004			2005			2004
Change in benefit obligation:
Benefit obligation as of beginning of year	$	285,738		$	265,790		$	31,868		$	39,185
Service cost		9,480			8,914			566			480
Interest cost		16,228			16,406			1,652			2,019
Plan amendment		—			—			—			(4,263	)
Actuarial loss (gain)		6,049			8,737			(1,800	)		(2,464	)
Benefits paid		(14,932	)		(13,309	)		(3,293	)		(3,042	)
Expenses paid		(817	)		(800	)		(30	)		(47	)

Benefit obligation as of end of year	$	301,746		$	285,738		$	28,963		$	31,868

Change in plan assets:
Fair value of plan assets as of beginning of year	$	186,579		$	167,962		$	16,862		$	14,587
Actual return on plan assets		12,460			16,816			1,236			1,882
Employer contributions		15,000			15,000			1,183			1,964
Benefits paid		(14,059	)		(12,399	)		(873	)		(1,524	)
Expenses paid		(817	)		(800	)		(30	)		(47	)

Fair value of plan assets as of end of year	$	199,163		$	186,579		$	18,378		$	16,862

Funded status	$	(102,583	)	$	(99,159	)	$	(10,585	)	$	(15,006	)
Unrecognized net actuarial loss		79,667			73,604			973			6,009
Unrecognized prior service cost		4,405			5,058			—			—
Unrecognized net transition obligation/(asset)		—			(499	)		3,536			4,041

Accrued benefit cost		(18,511	)		(20,996	)		(6,076	)		(4,956	)
Additional minimum liability		(34,595	)		(31,112	)		—			—

Accrued benefit liability	$	(53,106	)	$	(52,108	)	$	(6,076	)	$	(4,956	)

Accumulated pension benefit obligation	$	252,269		$	238,687			—			—

Accumulated postretirement benefit obligation:
For retirees							$	14,662		$	18,914
For fully eligible employees							$	5,980		$	5,672
For other participants							$	8,321		$	7,282
Weighted-average asset allocations as of December 31:
Equity securities		63	%		63	%		62	%		64	%
Debt securities		27	%		26	%		36	%		36	%
Real estate		5	%		5	%		—			—
Other		5	%		6	%		2	%		—
Target asset allocations as of December 31:
Equity securities		54-68	%		54-68	%		52-72	%		52-72	%
Debt securities		22-28	%		22-28	%		28-48	%		28-48	%
Real estate		3-7	%		3-7	%		—			—
Other		5-13	%		5-13	%		—			—
Weighted Average Assumptions as of December 31:
Discount rate for benefit obligation		5.75	%		5.75	%		5.75	%		5.75	%
Discount rate for annual expense		5.75	%		6.25	%		5.75	%		6.25	%
Expected long-term return on plan assets		8.50	%		8.00	%		8.50	%		8.00	%
Rate of compensation increase ⁽¹⁾		4.84	%		4.84	%
Medical cost trend pre-age 65 – initial								9.00	%		9.00	%
Medical cost trend pre-age 65 – ultimate								5.00	%		5.00	%
Ultimate medical cost trend year pre-age 65								2010			2009
Medical cost trend post-age 65 – initial								9.00	%		9.00	%
Medical cost trend post-age 65 – ultimate								6.00	%		6.00	%
Ultimate medical cost trend year post-age 65								2009			2008

⁽¹⁾	In 2004, changed to an age-based scale ranging from 2.50 percent to 8.00 percent.

AVISTA CORPORATION


	2005			2004			2003			2005			2004			2003
Components of net periodic benefit cost:
Service cost	$	9,480		$	8,914		$	7,806		$	566		$	480		$	482
Interest cost		16,228			16,406			15,705			1,652			2,019			2,477
Expected return on plan assets		(15,917	)		(13,436	)		(10,862	)		(1,368	)		(1,106	)		(842	)
Transition (asset)/obligation recognition		(499	)		(1,086	)		(1,086	)		505			505			979
Amortization of prior service cost		654			654			653			—			—			—
Net loss recognition		3,442			3,447			3,896			—			245			405

Net periodic benefit cost	$	13,388		$	14,899		$	16,112		$	1,355		$	2,143		$	3,501

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 2005 by $1.4 million and the service and interest cost by $0.1 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, 2005 by $1.2 million and the service and interest cost by $0.1 million.

The Company and its most significant subsidiaries have salary deferral 401(k) plans that are defined contribution plans and cover substantially all employees. Employees can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The respective company matches a portion of the salary deferred by each participant according to the schedule in the respective plan. Employer matching contributions of $4.4 million, $4.1 million and $3.8 million were expensed in 2005, 2004 and 2003, respectively.

The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. At each of December 31, 2005 and 2004, there were deferred compensation assets of $11.3 million included in other property and investments-net and corresponding deferred compensation liabilities of $11.3 million included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets.

NOTE 13. ACCOUNTING FOR INCOME TAXES

As of December 31, 2005 and 2004, the Company had net regulatory assets of $114.1 million and $123.2 million, respectively, related to the probable recovery of certain deferred tax liabilities from customers through future rates.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. The total net deferred income tax liability consisted of the following as of December 31 (dollars in thousands):


	2005		2004
Deferred income tax assets:
Allowance for doubtful accounts	$	16,604	$	16,428
Reserves not currently deductible		14,213		19,450
Alternative minimum tax		—		16,877
Contributions in aid of construction		7,691		6,840
Deferred compensation		5,164		5,138
Unfunded accumulated benefit obligation		9,100		8,732
Interest rate swaps		3,485		2,269
Other		10,812		10,047

Total deferred income tax assets	$	67,069	$	85,781

AVISTA CORPORATION


	2005		2004
Deferred income tax liabilities:
Differences between book and tax basis of utility plant	$	417,841		424,907
Power and natural gas deferrals		51,332		53,259
Unrealized energy commodity gains		12,252		24,542
Power exchange contract		37,024		39,436
Demand side management programs		3,518		3,866
Loss on reacquired debt		9,325		11,315
Other		10,192		4,639

Total deferred income tax liabilities		541,484		561,964

Net deferred income tax liability	$	474,415	$	476,183

Net current deferred income tax assets were $14.5 million and $12.3 million as of December 31, 2005 and 2004, respectively. Net non-current deferred tax liabilities were $488.9 million and $488.5 million as of December 31, 2005 and 2004, respectively.

The realization of deferred tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available evidence supporting the realization of its deferred tax assets and determined it is more likely than not that deferred tax assets will be realized.

A reconciliation of federal income taxes derived from statutory federal tax rates (35 percent in 2005, 2004 and 2003) applied to pre-tax income from continuing operations as set forth in the accompanying Consolidated Statements of Income is as follows for the years ended December 31 (dollars in thousands):


	2005			2004			2003
Federal income taxes at statutory rates	$	24,860		$	20,022		$	30,094
Increase (decrease) in tax resulting from:
Tax effect of regulatory treatment of utility plant differences		2,870			2,273			4,046
State income tax expense		1,139			821			942
Preferred dividends		713			759			383
Settlement of prior year tax returns and adjustment of tax reserves		42			(2,830	)		(389	)
Manufacturing deduction		(385	)		—			—
Kettle Falls tax credit		(2,891	)		—			—
Other-net		(487	)		547			264

Total income tax expense	$	25,861		$	21,592		$	35,340

Income Tax Expense Consisted of the Following:
Taxes currently provided	$	16,996		$	2,424		$	6,945
Deferred income taxes		8,865			19,168			28,395

Total income tax expense	$	25,861		$	21,592		$	35,340

In August 2005, the Internal Revenue Service (IRS) and Treasury Department issued a revenue ruling, and related regulations that affect the tax treatment by Avista Corp. of certain indirect overhead expenses. Avista Corp. had previously made a tax election to deduct certain indirect overhead costs on the 2002 tax return that were capitalized for financial accounting purposes. This election allowed Avista Corp. to accelerate tax deductions resulting in a reduction of approximately $40 million in current tax liabilities. This current tax benefit was deferred on the balance sheet in accordance with provisions of SFAS No. 109, “Accounting for Income Taxes” and did not have an effect on net income.

Avista Corp. believes that the revenue ruling and related regulations requires the Company to repay the original tax deductions over a two-year period (in 2005 and 2006) and that the tax deductions claimed on the Company’s tax returns were appropriate based on the applicable statutes and regulations in effect at the time. There can be no assurance that the Company’s position will prevail. However, it is not expected to have a significant effect on the Company’s net income.

AVISTA CORPORATION

NOTE 14. ENERGY PURCHASE CONTRACTS

Avista Utilities has contracts related to the purchase of fuel for thermal generation, natural gas and various agreements for the purchase, sale or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year 2055. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility resource costs in the Consolidated Statements of Income, were $652.2 million, $482.2 million and $464.1 million in 2005, 2004 and 2003, respectively. The following table details Avista Utilities’ future contractual commitments for power resources (including transmission contracts) and natural gas resources (including transportation contracts) (dollars in thousands):


	2006		2007		2008		2009		2010		Thereafter		Total
Power resources	$	104,684	$	103,869	$	103,546	$	104,641	$	104,674	$	375,282	$	896,696
Natural gas resources		259,100		58,133		44,067		39,711		39,460		352,155		792,626

Total	$	363,784	$	162,002	$	147,613	$	144,352	$	144,134	$	727,437	$	1,689,322

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

In addition, Avista Utilities has operational agreements, settlements and other contractual obligations with respect to its generation, transmission and distribution facilities. The expenses associated with these agreements are reflected as other operating expenses in the Consolidated Statements of Income.

The following table details future contractual commitments with respect to these agreements (dollars in thousands):


	2006		2007		2008		2009		2010		Thereafter		Total
Contractual obligations	$	14,265	$	14,289	$	14,314	$	14,462	$	14,489	$	194,889	$	266,708

Avista Utilities has fixed contracts with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating facilities. Although Avista Utilities has no investment in the PUD generating facilities, the fixed contracts obligate Avista Utilities to pay certain minimum amounts (based in part on the debt service requirements of the PUD) whether or not the facility is operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in utility resource costs in the Consolidated Statements of Income. Expenses under these PUD contracts were $9.0 million, $7.3 million and $8.5 million in 2005, 2004 and 2003, respectively. Information as of December 31, 2005 pertaining to these PUD contracts is summarized in the following table (dollars in thousands):


	Company’s Current Share of
	Output		Kilowatt Capability	Annual Costs (1)		Debt Service Costs (1)		Bonds Outstanding		Expira- tion Date
Chelan County PUD:
Rocky Reach Project	2.9	%	37,000	$	1,984	$	987	$	2,637	2011
Douglas County PUD:
Wells Project	3.5		30,000		1,090		640		7,635	2018
Grant County PUD:
Priest Rapids Project	5.7		55,000		2,643		773		11,892	2055
Wanapum Project	8.2		75,000		3,257		1,795		23,821	2055

Totals			197,000	$	8,974	$	4,195	$	45,985

(1)	The annual costs will change in proportion to the percentage of output allocated to Avista Utilities in a particular year. Amounts represent the operating costs for the year 2005. Debt service costs are included in annual costs.

The estimated aggregate amounts of required minimum payments (Avista Utilities’ share of existing debt service costs) under these PUD contracts are as follows (dollars in thousands):


	2006		2007		2008		2009		2010		Thereafter		Total
Minimum payments	$	3,587	$	3,938	$	3,966	$	3,986	$	3,605	$	63,961	$	83,043

AVISTA CORPORATION

In addition, Avista Utilities will be required to pay its proportionate share of the variable operating expenses of these projects.

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 are as follows (dollars in thousands):


	2006		2007		2008		2009		2010		Thereafter		Total
Energy contracts	$	1,009,668	$	231,795	$	225,693	$	205,182	$	196,331	$	346,907	$	2,215,576

Avista Energy also has sales commitments related to these contractual obligations in future periods.

NOTE 15. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of December 31 (dollars in thousands):


Maturity Year	Description	Interest Rate	2005			2004
2005	Secured Medium-Term Notes	6.39%-6.68%	$	—		$	29,500
2005	WP Funding LP Note	8.38%		—			54,572
2006	Secured Medium-Term Notes	7.89%-7.90%		30,000			30,000
2007	First Mortgage Bonds	7.75%		150,000			150,000
2007	Secured Medium-Term Notes	5.99%		13,850			13,850
2008	Secured Medium-Term Notes	6.06%-6.95%		45,000			45,000
2010	Secured Medium-Term Notes	6.67%-8.02%		35,000			35,000
2012	Secured Medium-Term Notes	7.37%		7,000			7,000
2013	First Mortgage Bonds	6.13%		45,000			45,000
2018	Secured Medium-Term Notes	7.26%-7.45%		22,500			27,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			24,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Pollution Control Bonds	5.00%		66,700			66,700
2034	Pollution Control Bonds	5.13%		17,000			17,000
2035	First Mortgage Bonds (1)	6.25%		150,000			—

	Total secured long-term debt			710,550			660,622

2006	Unsecured Medium-Term Notes	8.14%		8,000			8,000
2007	Unsecured Medium-Term Notes	7.90%-7.94%		12,000			12,000
2008	Unsecured Senior Notes	9.75%		279,735			279,735
2022	Unsecured Medium-Term Notes	8.15%		—			5,000
2023	Unsecured Medium-Term Notes	7.99%		—			5,000
2023	Pollution Control Bonds	6.00%		4,100			4,100

	Total unsecured long-term debt			303,835			313,835

	Other long-term debt and capital leases			11,506			13,047

	Interest rate swaps			5,236			1,092

	Unamortized debt discount			(1,613	)		(1,608	)

	Total			1,029,514			986,988
	Current portion of long-term debt			(39,524	)		(85,432	)

	Total long-term debt		$	989,990		$	901,556

(1)

The following table details future long-term debt maturities, including long-term debt to affiliated trusts (see Note 16) (dollars in thousands):


Year	2006		2007		2008		2009		2010		Thereafter		Total
Debt maturities	$	38,000	$	175,850	$	324,735	$	—	$	35,000	$	554,203	$	1,127,788

AVISTA CORPORATION

Substantially all utility properties owned by the Company are subject to the lien of the Company’s various mortgage indentures. 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, which may be issued based on, among other things, a 70 percent debt-to-collateral ratio, and/or retired First Mortgage Bonds, and a 2 to 1 net earnings to First Mortgage Bond interest ratio. As of December 31, 2005, the Company could issue $285.5 million of additional First Mortgage Bonds under the Mortgage and Deed of Trust. See Note 17 for information regarding First Mortgage Bonds issued to secure the Company’s obligations under its $350.0 million committed line of credit.

NOTE 16. LONG-TERM DEBT TO AFFILIATED TRUSTS

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 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The annual distribution rate paid during 2005 ranged from 3.275 percent to 5.285 percent. As of December 31, 2005, the annual distribution rate was 5.285 percent. Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II on or after June 1, 2007 and mature on June 1, 2037; however, this is limited by an agreement under the Company’s 9.75 percent Senior Notes that mature in 2008. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.

The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount with respect to, the Preferred Trust Securities to the extent that AVA Capital Trust III and Avista Capital II have funds available for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be mandatorily redeemed. As a result of the implementation of FIN 46 in 2003, the Company no longer includes these capital trusts in its consolidated financial statements as of December 31, 2003 and thereafter. 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.

NOTE 17. SHORT-TERM BORROWINGS

On December 17, 2004, the Company entered into a committed line of credit agreement 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, 2005 and 2004, there were $44.1 million and $32.8 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.

AVISTA CORPORATION

Balances and interest rates of bank borrowings under the Company’s revolving committed lines of credit were as follows as of and for the years ended December 31 (dollars in thousands):


	2005			2004			2003
Balance outstanding at end of period	$	63,000		$	68,000		$	80,000
Maximum balance outstanding during the period		167,000			170,000			85,000
Average balance outstanding during the period		61,181			54,858			26,034
Average interest rate during the period		4.45	%		3.14	%		2.99	%
Average interest rate at end of period		5.48			3.52			3.70

On July 13, 2005, Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, amended its committed credit agreement with a group of banks to increase the aggregate amount from $110.0 million to $145.0 million and to extend the expiration date to July 12, 2007. This committed credit facility provides for the issuance of letters of credit to secure contractual obligations to counterparties and for cash advances. This facility is secured by the assets of Avista Energy and Avista Energy Canada and guaranteed by Avista Capital and by CoPac Management, Inc., a wholly owned subsidiary of Avista Energy Canada. The maximum amount of credit extended by the banks for the issuance of letters of credit is the subscribed amount of the facility less the amount of outstanding cash advances, if any. The amendment to the credit agreement increased the maximum amount for cash advances from $30.0 million to $50.0 million. No cash advances were outstanding as of December 31, 2005 and 2004. Letters of credit in the aggregate amount of $125.3 million and $91.3 million were outstanding as of December 31, 2005 and 2004, respectively. The cash deposits of Avista Energy at the respective banks collateralized $18.2 million and $21.5 million of these letters of credit as of December 31, 2005 and 2004, respectively, which is reflected as restricted cash on the Consolidated Balance Sheets.

NOTE 18. INTEREST RATE SWAP AGREEMENTS

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 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 entered in 2004 provide for mandatory cash settlement of these contracts in 2008 and 2009. In June 2005, Avista Corp. entered into a forward-starting interest rate swap agreement in the amount of $50.0 million related to the anticipated issuance of debt to fund debt that matured during the second half of 2005. This interest rate swap agreement was cash settled in 2005 and the Company received $4.4 million, which has been deferred as a regulatory liability (part of long-term debt) and will be amortized over the 30-year life of the new debt issued in accordance with regulatory accounting practices.

AVISTA CORPORATION

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, 2005, Avista Corp. had a long-term derivative liability of $10.0 million. As of December 31, 2005, there was an unrealized loss of $6.5 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheets. 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. If regulatory accounting orders are not obtained prior to the mandatory cash settlements, the amount included in accumulated other comprehensive income or loss at the cash settlement date will be reclassified to a regulatory liability (part of long-term debt) in accordance with regulatory accounting practices under SFAS No. 71. This gain or loss will be amortized over the remaining life of the forecasted debt issued.

Rathdrum Power, LLC (RP LLC), an unconsolidated entity that is 49 percent owned by Avista Power, operates a 270 MW natural gas-fired combustion turbine plant in northern Idaho (Lancaster Project). Avista Power’s investment in RP LLC, which is included in non-utility properties and investments-net on the Consolidated Balance Sheets, is accounted for under the equity method and totaled $18.4 million as of December 31, 2005. As of December 31, 2005, RP LLC had $112.9 million of debt outstanding that is not included in the consolidated financial statements of the Company. There is no recourse to the Company with respect to this debt. RP LLC has entered into interest rate swap agreements to manage the risk that changes in interest rates may affect the amount of future interest payments. RP LLC agreed to pay fixed rates of interest with the differential paid or received under the interest rate swap agreements recognized as an adjustment to interest expense. These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133. As of December 31, 2005, there was an unrealized loss of $0.1 million recorded as accumulated other comprehensive loss on the Consolidated Balance Sheets.

NOTE 19. LEASES

The Company has multiple lease arrangements involving various assets, with minimum terms ranging from one to forty-five years. Certain lease arrangements require the Company, upon the occurrence of specified events, to purchase the leased assets. The Company’s management believes the likelihood of the occurrence of the specified events under which the Company could be required to purchase the leased assets is remote. Rental expense under operating leases for 2005, 2004 and 2003 was $7.2 million, $9.9 million and $14.2 million, respectively.

In November 2005, the Company terminated its lease agreement related to its corporate headquarters and central operating facility. Lease payments were approximately $2.3 million per year. In conjunction with the termination of the lease agreement, the Company purchased its corporate headquarters and central operating facility.

Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year as of December 31, 2005 were as follows (dollars in thousands):


Year ending December 31:	2006		2007		2008		2009		2010		Thereafter		Total
Minimum payments required	$	4,770	$	4,248	$	4,130	$	3,756	$	1,467	$	2,362	$	20,733

The payments under Avista Utilities’ capital leases are $1.1 million in 2006, $1.0 million in each of 2007 and 2008, and $0.1 million in 2009. The payments under the Avista Capital subsidiaries’ capital leases are $0.5 million in each of 2006, 2007 and 2008, and $0.4 million in 2009.

NOTE 20. GUARANTEES

The $145.0 million committed credit agreement of Avista Energy and its subsidiary, Avista Energy Canada, as co-borrowers, is guaranteed by Avista Capital and by CoPac Management, Inc., and secured by the assets of Avista Energy and Avista Energy Canada. This credit agreement expires on July 12, 2007. This agreement also provides for the issuance of letters of credit to secure contractual obligations to counterparties. No cash advances were outstanding as of December 31, 2005 and 2004. Letters of credit in the aggregate amount of $125.3 million and $91.3 million were outstanding as of December 31, 2005 and 2004, respectively.

The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount with respect to, the Preferred Trust Securities issued by its affiliates, AVA Capital Trust III and Avista Capital II, to the extent that these entities have funds available for such payments from the respective debt securities.

AVISTA CORPORATION

In the course of the energy trading business, Avista Capital provides guarantees to other parties with whom Avista Energy may be doing business. At any point in time, Avista Capital is only liable for the outstanding portion of the guarantee, which was $37.7 million and $24.5 million as of December 31, 2005 and 2004, respectively. The face value of all performance guarantees issued by Avista Capital for energy trading contracts at Avista Energy was $419.3 million and $391.7 million as of December 31, 2005 and 2004, respectively. Most guarantees do not have set expiration dates; however, either party may terminate the guarantee at any time with minimal written notice.

Avista Power, through its equity investment in RP LLC, is a 49 percent owner of the Lancaster Project, which commenced commercial operation in September 2001. Commencing with commercial operations, all of the output from the Lancaster Project is contracted to Avista Energy through 2026 under a power purchase agreement. Avista Corp. has guaranteed the power purchase agreement with respect to the performance of Avista Energy.

NOTE 21. PREFERRED STOCK-CUMULATIVE (SUBJECT TO MANDATORY REDEMPTION)

In September 2005, the Company made a mandatory redemption of 17,500 shares of preferred stock for $1.75 million. In September 2004, the Company made a mandatory redemption of 17,500 shares of preferred stock for $1.75 million. In March 2003, the Company repurchased 17,500 shares of preferred stock for $1.6 million, satisfying its redemption requirement for 2003. On September 15, 2006, the Company must redeem 17,500 shares at $100 per share plus accumulated dividends through a mandatory sinking fund. As such, redemption requirements are $1.75 million for 2006. The remaining shares must be redeemed on September 15, 2007 for $26.25 million. The Company has the right to redeem an additional 17,500 shares on each September 15 redemption date; however, this right is limited by an agreement under the Company’s 9.75 percent Senior Notes that mature in 2008. Upon involuntary liquidation, all preferred stock will be entitled to $100 per share plus accrued dividends.

The Company adopted SFAS No. 150 effective July 1, 2003. The adoption of this statement requires the Company to classify preferred stock subject to mandatory redemption as liabilities and preferred stock dividends as interest expense. The restatement of prior periods was not permitted.

NOTE 22. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying values of cash and cash equivalents, restricted cash, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Energy commodity derivative assets and liabilities, as well as derivatives related to interest rate swap agreements, are reported at estimated fair value on the Consolidated Balance Sheets.

The fair value of the Company’s long-term debt (including current-portion, but excluding capital leases) as of December 31, 2005 and 2004 was estimated to be $1,063.0 million, or 105 percent of the carrying value of $1,014.4 million, and $1,054.7 million, or 108 percent of the carrying value of $975.5 million, respectively. The fair value of the Company’s mandatorily redeemable preferred stock as of December 31, 2005 and 2004 was estimated to be $28.6 million, or 102 percent of the carrying value of $28.0 million, and $32.0 million, or 107 percent of the carrying value of $29.8 million, respectively. The fair value of the Company’s long-term debt to affiliated trusts as of December 31, 2005 and 2004 was estimated to be $104.6 million, or 95 percent of the carrying value of $110.0 million, and $108.3 million, or 98 percent of the carrying value of $110.0 million, respectively. The carrying value as of December 31, 2005 and 2004 does not include $3.4 million of debt that is considered common equity by the affiliated trusts. These estimates were primarily based on available market information.

NOTE 23. COMMON STOCK

In April 1990, the Company sold 1,000,000 shares of its common stock to the Trustee of the Investment and Employee Stock Ownership Plan for Employees of the Company (Plan) for the benefit of the participants and beneficiaries of the Plan. In payment for the shares of common stock, the Trustee issued a promissory note payable to the Company in the amount of $14.1 million. Dividends paid on the stock held by the Trustee, plus Company contributions to the Plan, if any, were used by the Trustee to make interest and principal payments on the promissory note. The balance of the promissory note receivable from the Trustee was repaid during 2005. Prior to 2005, the balance outstanding on the promissory note was reflected as a reduction of stockholders’ equity. The shares of common stock were allocated to the accounts of participants in the Plan as the note was repaid. During 2005, 2004 and 2003, the cost recorded for the Plan was $1.7 million, $6.2 million and $6.9 million, respectively. Interest on the note payable to the Company, cash and stock contributions to the Plan and dividends on the shares held by the

AVISTA CORPORATION

Trustee was less than $0.1 million, $0.4 million and less than $0.1 million, respectively, during 2005. Interest on the note payable to the Company, cash and stock contributions to the Plan and dividends on the shares held by the Trustee was $0.2 million, $1.7 million and less than $0.1 million, respectively, during 2004. Interest on the note payable to the Company, cash and stock contributions to the Plan and dividends on the shares held by the Trustee was $0.3 million, $1.7 million and $0.1 million, respectively, during 2003.

In November 1999, the Company adopted a shareholder rights plan pursuant to which holders of common stock outstanding on February 15, 1999, or issued thereafter, were granted one preferred share purchase right (Right) on each outstanding share of common stock. Each Right, initially evidenced by and traded with the shares of common stock, entitles the registered holder to purchase one one-hundredth of a share of preferred stock of the Company, without par value, at a purchase price of $70, subject to certain adjustments, regulatory approval and other specified conditions. The Rights will be exercisable only if a person or group acquires 10 percent or more of the outstanding shares of common stock or commences a tender or exchange offer, the consummation of which would result in the beneficial ownership by a person or group of 10 percent or more of the outstanding shares of common stock. Upon any such acquisition, each Right will entitle its holder to purchase, at the purchase price, that number of shares of common stock or preferred stock of the Company (or, in the case of a merger of the Company into another person or group, common stock of the acquiring person or group) that has a market value at that time equal to twice the purchase price. In no event will the Rights be exercisable by a person that has acquired 10 percent or more of the Company’s common stock. The Rights may be redeemed, at a redemption price of $0.01 per Right, by the Board of Directors of the Company at any time until any person or group has acquired 10 percent or more of the common stock. The Rights expire on March 31, 2009.

The Company has a Dividend Reinvestment and Stock Purchase Plan under which the Company’s shareholders may automatically reinvest their dividends and make optional cash payments for the purchase of the Company’s common stock at current market value.

From March 2000 through May 2003, the Company issued shares of its common stock to the Employee Investment Plan rather than having the Plan purchase shares of common stock on the open market. In the fourth quarter of 2000, the Company also began issuing new shares of common stock for the Dividend Reinvestment and Stock Purchase Plan. Shares issued under these plans in 2005, 2004 and 2003 are disclosed in the Consolidated Statements of Stockholders’ Equity.

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in the Company’s Articles of Incorporation and various mortgage indentures. 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.

NOTE 24. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the years ended December 31 (in thousands, except per share amounts):


	2005		2004			2003
Numerator:
Income from continuing operations	$	45,168	$	35,614		$	50,643
Loss from discontinued operations		—		—			(4,949	)

Net income before cumulative effect of accounting change		45,168		35,614			45,694
Cumulative effect of accounting change		—		(460	)		(1,190	)

Net income		45,168		35,154			44,504
Preferred stock dividend requirements		—		—			(1,125	)

Income available for common stock	$	45,168	$	35,154		$	43,379

AVISTA CORPORATION


	2005		2004			2003
Denominator:
Weighted-average number of common shares outstanding-basic		48,523		48,400			48,232
Effect of dilutive securities:
Contingent stock awards		198		209			244
Stock options		258		277			154

Weighted-average number of common shares outstanding-diluted		48,979		48,886			48,630

Earnings per common share, basic:
Earnings from continuing operations	$	0.93	$	0.74		$	1.03
Loss from discontinued operations		—		—			(0.10	)

Earnings before cumulative effect of accounting change		0.93		0.74			0.93
Loss from cumulative effect of accounting change		—		(0.01	)		(0.03	)

Total earnings per common share, basic	$	0.93	$	0.73		$	0.90

Earnings per common share, diluted:
Earnings from continuing operations	$	0.92	$	0.73		$	1.02
Loss from discontinued operations		—		—			(0.10	)

Earnings before cumulative effect of accounting change		0.92		0.73			0.92
Loss from cumulative effect of accounting change		—		(0.01	)		(0.03	)

Total earnings per common share, diluted	$	0.92	$	0.72		$	0.89

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 695,500, 730,100 and 1,306,200 for 2005, 2004 and 2003, respectively. These stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period. In addition, contingent stock awards of 318,900 and 156,800 were outstanding as of December 31, 2005 and 2004, respectively, which were not included in basic or diluted shares because the performance conditions were not satisfied.

NOTE 25. STOCK COMPENSATION PLANS

Avista Corp.

In 1998, the Company adopted and shareholders approved an incentive compensation plan, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain key employees, directors and officers of the Company and its subsidiaries may be granted stock options, stock appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The Company has available a maximum of 3.5 million shares of its common stock for grant under the 1998 Plan, including 1.0 million shares approved by shareholders in 2005. Beginning in 2000, non-employee directors began receiving options under this plan.

In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the exclusion of directors and executive officers of the Company. The Company has available a maximum of 2.5 million shares of its common stock for grant under the 2000 Plan. The Company currently does not plan to issue any further options or securities under this plan.

The Board of Directors has determined that it is no longer in the Company’s best interest to issue stock options under the 1998 Plan and the 2000 Plan. Other forms of compensation are in place including the issuance of performance shares to certain officers and other key employees.

Prior to January 1, 2006, the Company accounted for stock based compensation using APB No. 25, which requires the recognition of compensation expense on the excess, if any, of the market price of the stock at the date of grant over the exercise price of the option. As the exercise price for options granted under the 1998 Plan and the 2000 Plan was equal to the market price at the date of grant, there was no compensation expense recorded by the Company. However, the Company has recognized compensation expense related to the initial grant (2003) of performance share awards that vested on December 31, 2005. SFAS No. 123 requires the disclosure of pro forma net income and earnings per common share had the Company adopted the fair value method of accounting for stock options. Under this statement, the fair value of stock-based awards is calculated with option pricing models. These models require the use of subjective assumptions, including stock price volatility, dividend yield, risk-free interest

AVISTA CORPORATION

rate and expected time to exercise. The fair value of options is estimated on the date of grant using the Black-Scholes option-pricing model. See Note 1 for disclosure of pro forma net income and earnings per common share. In December 2004, the FASB issued SFAS No. 123R, which supersedes APB No. 25 and SFAS No. 123 and their related implementation guidance. 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 beginning in 2006. See Note 2 for further information.

In 2005, the Company granted 163,600 performance shares to certain officers and other key employees under the 1998 Plan, of which 163,100 awards were outstanding as of December 31, 2005. In 2004, the Company granted 156,800 performance shares to certain officers and other key employees under the 1998 Plan and the 2000 Plan, of which 155,800 awards were outstanding as of December 31, 2005. In 2003, the Company granted 162,600 performance shares to certain officers and other key employees under the 1998 Plan and the 2000 Plan, of which 152,914 awards were outstanding as of December 31, 2005. The performance shares are payable at the Company’s option in either cash or common stock three years from the date of grant. The amount of cash paid or common stock issued will range from 0 to 150 percent of the performance shares granted depending on the change in the value of the Company’s common stock relative to an external benchmark. Based on the change in value of the Company’s common stock relative to an external benchmark during the 3-year performance cycle, the Company issued 183,497 shares of common stock in early 2006 related to the performance shares granted in 2003. This resulted in compensation expense of $3.6 million recorded during 2005. In February 2006, the Company granted 132,266 performance shares and 34,660 restricted shares to certain officers and other key employees under the 1998 Plan.

Shares of common stock issued from the exercise of stock options under the 1998 Plan and the 2000 Plan were acquired on the open market prior to 2006. Beginning in 2006, the Company will issue new shares for the exercise of stock options. As of December 31, 2005, there were 2.7 million shares available for future stock grants under the 1998 Plan and the 2000 Plan.

The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:


	2005			2004			2003
Number of shares under stock options:
Options outstanding at beginning of year		2,332,198			2,481,886			2,684,350
Options granted		—			—			24,000
Options exercised		(192,377	)		(99,138	)		(37,439	)
Options canceled		(44,610	)		(50,550	)		(189,025	)

Options outstanding at end of year		2,095,211			2,332,198			2,481,886

Options exercisable at end of year		1,968,629			1,896,648			1,614,455

Weighted average exercise price:
Options granted	$	—		$	—		$	12.41
Options exercised	$	13.50		$	13.79		$	11.43
Options canceled	$	20.42		$	18.46		$	17.78
Options outstanding at end of year	$	15.68		$	15.58		$	15.57
Options exercisable at end of year	$	16.03		$	16.62		$	17.18
Weighted average fair value of options granted during the year	$	—		$	—		$	4.30
Principal assumptions used in applying the Black-Scholes model:
Risk-free interest rate		—			—			3.17	%
Expected life, in years		—			—			7
Expected volatility		—			—			37.10	%
Expected dividend yield		—			—			3.87	%

AVISTA CORPORATION

Information with respect to options outstanding and options exercisable as of December 31, 2005 was as follows:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Life (in years)	Number of Shares	Weighted Average Exercise Price
$10.17-$11.68	459,411	$	10.26	6.2	332,828	$	10.27
$11.69-$14.61	523,500		11.83	5.2	523,500		11.83
$14.62-$17.53	416,800		17.12	4.0	416,800		17.12
$17.54-$20.45	266,000		18.73	2.2	266,000		18.73
$20.46-$23.38	403,300		22.56	4.1	403,300		22.56
$26.30-$28.47	26,200		27.39	4.1	26,200		27.39

Total	2,095,211	$	15.68	5.0	1,968,628	$	16.03

Avista Capital Companies

Certain subsidiaries of Avista Capital have employee stock incentive plans under which certain employees and directors of the subsidiaries are granted options to purchase subsidiary shares at prices no less than the fair market value on the date of grant. Options outstanding under these plans generally vest over periods of between three and five years from the date granted and terminate ten years from the date granted. Employee stock incentive plans related to the Avista Capital subsidiaries are not significant to the consolidated financial statements.

Non-Employee Director Stock Plan

In February 2005, the Board of Directors elected to terminate the 1996 Director Plan. With the termination of the 1996 Director Plan, directors may elect each year to receive their annual retainer in cash, in common stock, or in a combination of both cash and common stock.

NOTE 26. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. With respect to these proceedings, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. In addition to issues specifically identified in this Note and with respect to matters that affect the regulated utility operations, the Company intends to seek, to the extent appropriate, regulatory approval of recovery of incurred costs through the rate making process.

Federal Energy Regulatory Commission Inquiry

On April 19, 2004, the Federal Energy Regulatory Commission (FERC) issued an order approving the contested Agreement in Resolution of Section 206 Proceeding (Agreement in Resolution) reached by Avista Corp. doing business as Avista Utilities, Avista Energy and the FERC’s Trial Staff with respect to an investigation into the activities of Avista Utilities and Avista Energy in western energy markets during 2000 and 2001. In the Agreement in Resolution, the FERC Trial Staff stated that its investigation found: (1) no evidence that any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy; (2) no evidence that Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) that Avista Utilities and Avista Energy did not withhold relevant information from the FERC’s inquiry into the western energy markets for 2000 and 2001. As part of the Agreement in Resolution, Avista Utilities agreed to continue to record conversations of energy traders for two years and to improve its account settlement process. Avista Utilities and Avista Energy agreed to maintain an annual training program on the applicable FERC Code of Conduct for all employees engaged in the trading of electric energy and capacity. The Agreement in Resolution imposes no monetary remedies or penalties against Avista Utilities or Avista Energy. In April 2005 and June 2005, the California Parties and the City of Tacoma, respectively, filed petitions for review of the FERC’s decisions approving the Agreement in Resolution with the United States Court of Appeals for the Ninth Circuit. Based on the FERC’s order approving the Agreement in Resolution and the FERC’s denial of rehearing requests, the Company does not expect that this proceeding will have any material adverse effect on its financial condition, results of operations or cash flows.

100

AVISTA CORPORATION

Class Action Securities Litigation

On November 10, 2005, an amended class action complaint was filed in the United States District Court for the Eastern District of Washington against Avista Corp., Thomas M. Matthews, the former Chairman of the Board, President and Chief Executive Officer of Avista Corp., Gary G. Ely, the current Chairman of the Board, President and Chief Executive Officer of Avista Corp., and Jon E. Eliassen, the former Senior Vice President and Chief Financial Officer of Avista Corp. Several class action complaints were originally filed in September through November 2002 in the same court against the same parties. In February 2003, the court issued an order, which consolidated the complaints and in August 2003, the plaintiffs filed a consolidated amended class action complaint. On June 13, 2005, the Company filed a motion for reconsideration of its earlier motion to dismiss this complaint, based, in part, on a recent United States Supreme Court decision with respect to the pleading requirements surrounding a sufficient showing of loss causation. On October 19, 2005, the Court granted the Company’s motion to dismiss this complaint. The order to dismiss was issued without prejudice, which allowed the plaintiffs to amend their complaint. The amended complaint filed on November 10, 2005 alleges damages due to the decrease in the total market value of the Company’s common stock during the class period, which was approximately $2.6 billion. These alleged losses stemmed from violations of federal securities laws through alleged misstatements and omissions of material facts with respect to the Company’s energy trading practices in western power markets. The plaintiffs assert that alleged misstatements and omissions regarding these matters were made in the Company’s filings with the Securities and Exchange Commission and other information made publicly available by the Company, including press releases. The class action complaint asserts claims on behalf of all persons who purchased, converted, exchanged or otherwise acquired the Company’s common stock during the period between November 23, 1999 and August 13, 2002. On January 6, 2006, the Company filed a motion to dismiss the November 10, 2005 complaint. The Company’s motion to dismiss has been set for hearing in March 2006. The Company continues to assert that, among other deficiencies in the complaint, the plaintiff has failed to show sufficient loss causation. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

California Refund Proceeding

In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the California Independent System Operator (CalISO) and the California Power Exchange (CalPX) during the period from October 2, 2000 to June 20, 2001 (Refund Period) in the California spot power market. The findings of the FERC administrative law judge were largely adopted in March 2003 by the FERC. The refunds ordered are based on the development of a mitigated market clearing price methodology. If the refunds required by the formula would cause a seller to recover less than its actual costs for the refund period, the FERC has held that the seller would be allowed to document these costs and limit its refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim pursuant to the FERC’s August 2005 order and demonstrated an overall revenue shortfall for sales into the California spot markets during the Refund Period after the mitigated market clearing price methodology is applied to its transactions. In January 2006, the FERC issued its Order On Cost Filings accepting Avista Energy’s cost filing claim, subject to a compliance filing and the utilization of final CalISO, CalPX and Automated Power Exchange Corporation data. Once the CalISO receives updated cost offset filings from Avista Energy and other sellers, it will continue its efforts to prepare revised settlement statements for spot market sales to California during the refund period.

In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the CalPX and the CalISO. As a result, the CalPX and the CalISO failed to pay various energy sellers, including Avista Energy. Both PG&E and the CalPX declared bankruptcy in 2001. In March 2002, SCE paid its defaulted obligations to the CalPX. In April 2004, PG&E paid its defaulted obligations into an escrow fund in accordance with its bankruptcy reorganization. Funds held by the CalPX and in the PG&E escrow fund are not subject to release until the FERC issues an order directing such release in the California refund proceeding. As of December 31, 2005, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties.

In addition, in June 2003, the FERC issued an order to review bids above $250 per MW made by participants in the short-term energy markets operated by the CalISO and the CalPX from May 1, 2000 to October 2, 2000. Market participants with bids above $250 per MW during the period described above have been required to demonstrate why their bidding behavior and practices did not violate applicable market rules. If violations were found to exist,

101

AVISTA CORPORATION

the FERC would require the refund of any unjust profits and could also enforce other non-monetary penalties, such as the revocation of market-based rate authority. Avista Energy was subject to this review. In May 2004, the FERC provided notice that Avista Energy was no longer subject to this investigation. In March and April 2005, the California Parties and PG&E, respectively, petitioned for review of the FERC’s decision by the United States Court of Appeals for the Ninth Circuit. In addition, many of the other orders that the FERC has issued in the California refund proceedings are now on appeal before the Ninth Circuit. Some of those issues have been consolidated as a result of a case management conference conducted in September 2004. In October 2004, the Ninth Circuit ordered that briefing proceed in two rounds. The first round is limited to three issues: (1) which parties are subject to the FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; and (3) which categories of transactions are subject to refunds. Oral argument on those issues took place in April 2005. In September 2005, the Ninth Circuit held that the FERC did not have the authority to order refunds for sales made by municipal utilities in the California Refund Case; no decision has yet been issued on the other issues argued in April 2005. The time for seeking rehearing in the municipal utilities case has been extended until 45 days after disposition of the case presenting the other issues. The second round of issues and their corresponding briefing schedules have not yet been set by the Ninth Circuit Court of Appeals.

Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that the California refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows due to netting against counterparty defaults. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Pacific Northwest Refund Proceeding

In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales in the Pacific Northwest between December 25, 2000 to June 20, 2001 were just and reasonable. During the hearing, Avista Utilities and Avista Energy vigorously opposed claims that Pacific Northwest markets were dysfunctional, that rates for spot market sales were unjust and unreasonable and that the imposition of refunds would be appropriate. In September 2001, the FERC’s Administrative Law Judge presiding over the evidentiary hearing issued a decision favorable to the Company’s position and recommended that the FERC not order refunds and instead dismiss the entire proceeding. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In November 2003, the FERC affirmed its order. Seven petitions for review, including one filed by Puget Sound Energy, Inc. (Puget), are now pending before the United States Court of Appeals for the Ninth Circuit. Opening briefs were filed in January 2005. Petitioners other than Puget challenged the merits of the FERC’s decision not to order refunds. Puget’s brief is directed to the procedural flaws in the underlying docket. Puget argues that because its complaint was withdrawn as a matter of law in July 2001, the FERC erred in relying on it to serve as the basis to initiate the preliminary investigation into whether refunds for individually negotiated bilateral transactions in the Pacific Northwest were appropriate. In February 2005, intervening parties, including Avista Energy and Avista Utilities, filed in support of Puget and also filed in opposition to the other six petitioners. Briefing was completed in May 2005. Oral arguments are expected, but have not yet been set. Because the resolution of the Pacific Northwest refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that the Pacific Northwest refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Reliant Energy, Inc. and Duke Energy Corporation Cross-Complaints

In April 2002, several subsidiaries of Reliant Energy, Inc. (Reliant) and Duke Energy Corporation (Duke) filed cross-complaints against Avista Energy and numerous other participants in the California energy markets. The cross-complaints seek indemnification for any liability that may arise from original complaints filed against Reliant and Duke with respect to charges of unlawful and unfair business practices in the California energy markets under California law. On November 9, 2005, both Duke and Reliant submitted to the Court stipulations with Avista Energy to conditionally dismiss, with prejudice, the cross complaints that had been filed against Avista Energy, subject to reinstatement if proposed settlements between Duke and Reliant and the plaintiffs are not approved by the Court. Avista Energy did not pay any amount to Duke or to Reliant to obtain these dismissals. The clerk of the court entered Reliant’s request for dismissal on December 19, 2005 and entered Duke’s request for dismissal on January 5, 2006.

102

AVISTA CORPORATION

On December 14, 2005, the Court granted final approval of the Duke settlement with the plaintiffs. The Court’s order granting final approval of the Duke settlement will become final on March 14, 2006, absent any appeal. On January 6, 2006, the Court granted preliminary approval of the Reliant settlement with the plaintiffs. A hearing on final approval of the Reliant settlement is set for April 28, 2006. If the Court does not grant final approval of the Reliant settlement, Reliant may elect to reactivate its cross-complaint. Similarly, should the Court for any reason fail to approve the Reliant settlement by May 31, 2006, Avista Energy may withdraw from the stipulation agreement by giving ten days advance written notice.

Based on the stipulation of dismissal, if approved, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

California Attorney General Complaint

In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the Attorney General of the State of California (California AG) that alleged violations of the Federal Power Act by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The complaint alleged that the FERC’s adoption and implementation of market-based rate authority was flawed and, as a result, individual sellers were liable for sales of energy at rates that were “unjust and unreasonable.” In May 2002, the FERC issued an order dismissing the complaint but directing sellers to re-file certain transaction summaries. It was not clear that Avista Corp. and its subsidiaries were subject to this directive but the Company took the conservative approach and re-filed certain transaction summaries in June and July of 2002. In July 2002, the California AG requested a rehearing on the FERC order, which request was denied in September 2002. Subsequently, the California AG filed a Petition for Review of the FERC’s decision with the United States Court of Appeals for the Ninth Circuit. In September 2004, the United States Court of Appeals for the Ninth Circuit upheld the FERC’s market-based rate authority, but found the requirement that all sales at market-based rates be contained in quarterly reports filed with the FERC to be integral to a market-based rate tariff. The California AG has interpreted the decision as providing authority to the FERC to order refunds in the California refund proceeding for an expanded refund period. The Court’s decision leaves to the FERC the determination as to whether refunds are appropriate. In October 2004, Avista Energy joined with others in seeking rehearing of the Court’s decision to remand the case back to the FERC for further proceedings. The Ninth Circuit has yet to rule on the request for rehearing. Based on information currently known to the Company’s management, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Port of Seattle Complaint

In May 2003, a complaint was originally filed by the Port of Seattle in the United States District Court for the Western District of Washington against numerous companies, including Avista Corp., Avista Energy, Inc. and Avista Power, LLC (collectively the Avista defendants), seeking compensatory and treble damages for alleged violations of the Sherman Act and the Racketeer Influenced and Corrupt Organization Act by transmitting, via wire communications, false information intended to increase the price of power, knowing that others would rely upon such information. The complaint alleged that the defendants and others knowingly devised and attempted to devise a scheme to defraud and to obtain money and property from electricity customers throughout the Western Electricity Coordinating Council (WECC), by means of false and fraudulent pretenses, representations and promises. The alleged purpose of the scheme was to artificially increase the price that the defendants received for their electricity and ancillary services, to receive payments for services they did not provide and to manipulate the price of electricity throughout the WECC. This case was transferred to the United States District Court for the Southern District of California to consolidate it with other pending actions. In May 2004, the United States District Court for the Southern District of California granted motions to dismiss filed by the Avista defendants, as well as other defendants, with respect to this complaint. The Court dismissed the complaint because it determined that it was without jurisdiction to hear the plaintiff’s claims, based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. In May 2004, the Port of Seattle filed an appeal with the United States Court of Appeals for the Ninth Circuit. In October 2005, the Ninth Circuit denied the plaintiffs’ joint motion for summary disposition of the Port of Seattle’s appeal. The Port of Seattle’s appeal to the Ninth Circuit has been briefed and oral argument is scheduled for March 7, 2006. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its

103

AVISTA CORPORATION

financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Wah Chang Complaint

In May 2004, Wah Chang, a division of TDY Industries, Inc. (a subsidiary of Allegheny Technologies, Inc.), filed a complaint in the United States District Court for the District of Oregon against numerous companies, including Avista Corp., Avista Energy and Avista Power. The complaint seeks compensatory and treble damages for alleged violations of the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, as well as violations of Oregon state law. According to the complaint, from September 1997 to September 2002, the plaintiff purchased electricity from PacifiCorp pursuant to a contract that was indexed to the spot wholesale market price of electricity. The plaintiff alleges that the defendants, acting in concert among themselves and/or with Enron Corporation and certain affiliates thereof (collectively, Enron) and others, engaged in a scheme to defraud electricity customers by transmitting false market information in interstate commerce in order to artificially increase the price of electricity provided by them, to receive payment for services not provided by them and to otherwise manipulate the market price of electricity, and by executing wash trades and other forms of market manipulation techniques and sham transactions. The plaintiff also alleges that the defendants, acting in concert among themselves and/or with Enron and others, engaged in numerous practices involving the generation, purchase, sale, exchange, scheduling and/or transmission of electricity with the purpose and effect of causing a shortage (or the appearance of a shortage) in the generation of electricity and congestion (or the appearance of congestion) in the transmission of electricity, with the ultimate purpose and effect of artificially and illegally fixing and raising the price of electricity in California and throughout the Pacific Northwest. As a result of the defendants’ alleged conduct, the plaintiff allegedly suffered damages of not less than $30 million through the payment of higher electricity prices. In September 2004, this case was transferred to the United States District Court for the Southern District of California for consolidation with other pending actions. In February 2005, the Court granted the defendants’ motion to dismiss the complaint because it determined that it was without jurisdiction to hear the plaintiff’s complaint, based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. In March 2005, Wah Chang filed an appeal with the United States Court of Appeals for the Ninth Circuit. The appeal of Wah Chang is still pending before the Ninth Circuit and awaits oral argument. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

City of Tacoma Complaint

In June 2004, the City of Tacoma, Department of Public Utilities, Light Division, a Washington municipal corporation (Tacoma Power), filed a complaint in the United States District Court for the Western District of Washington against over fifty companies, including Avista Corp., Avista Energy and Avista Power. According to the complaint, Tacoma Power distributes electricity to customers in Tacoma, and Pierce County, Washington, generates electricity at several facilities in western Washington and purchases power under supply contracts and in the Northwest spot market. Tacoma Power’s complaint seeks compensatory and treble damages from alleged violations of the Sherman Act. Tacoma Power alleges that the defendants, acting in concert, engaged in a pattern of activities that had the purpose and effect of creating the impressions that the demand for power was higher, the supply of power was lower, or both, than was in fact the case. This allegedly resulted in an artificial increase of the prices paid for power sold in California and elsewhere in the western United States during the period from May 2000 through the end of 2001. Due to the alleged unlawful conduct of the defendants, Tacoma Power allegedly paid an amount estimated to be $175.0 million in excess of what it would have paid in the absence of such alleged conduct. In September 2004, this case was transferred to the United States District Court for the Southern District of California for consolidation with other pending actions. In February 2005, the Court granted the defendants’ motion to dismiss this complaint for similar reasons to those expressed by the Court in the Wah Chang complaint described above. In March 2005, Tacoma Power filed an appeal with the United States Court of Appeals for the Ninth Circuit. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

104

AVISTA CORPORATION

State of Montana Proceedings

In June 2003, the Attorney General of the State of Montana (Montana AG) filed a complaint in the Montana District Court on behalf of the people of Montana and the Flathead Electric Cooperative, Inc. against numerous companies, including Avista Corp. The complaint alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. This case was subsequently moved to the United States District Court for the District of Montana; however, it has since been remanded back to the Montana District Court.

The Montana AG also petitioned the Montana Public Service Commission (MPSC) to fine public utilities $1,000 a day for each day it finds they engaged in alleged “deceptive, fraudulent, anticompetitive or abusive practices” and order refunds when consumers were forced to pay more than just and reasonable rates. In February 2004, the MPSC issued an order initiating investigation of the Montana retail electricity market for the purpose of determining whether there is evidence of unlawful manipulation of that market. The Montana AG has requested specific information from Avista Energy and Avista Corp. regarding their transactions within the State of Montana during the period from January 1, 2000 through December 31, 2001.

Because the resolution of these proceedings remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that these proceedings will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Montana Public School Trust Fund Lawsuit

In October 2003, a lawsuit was filed by Richard Dolan and Denise Hayman in the United States District Court for the District of Montana against all private owners of hydroelectric dams in Montana, including Avista Corp. The lawsuit alleges that the hydroelectric facilities are located on state-owned riverbeds and the owners have never paid compensation to the state’s public school trust fund. The lawsuit requests lease payments dating back to the construction of the respective dams and also requests damages for trespassing and unjust enrichment. An Amended Complaint adding Great Falls Elementary School District No. 1 and Great Falls High School District No. 1A was filed in January 2004. In February 2004, the Company filed its motion to dismiss this lawsuit; PacifiCorp and PPL Montana, as the other named defendants also filed a motion to dismiss, or joined therein. In May 2004, the Montana AG filed a complaint on behalf of the state to join in this lawsuit to allegedly protect and preserve state lands/school trust lands from use without compensation. In July 2004, the defendants (including Avista Corp.) filed a motion to dismiss the Montana AG’s complaint. In September 2004, the United States District Court granted the motion to dismiss filed with respect to plaintiffs Richard Dolan, Denise Hayman and the school districts. However, the motion to dismiss the Montana AG’s complaint was denied, citing, among other things, that the FERC does not have exclusive jurisdiction over this matter. Subsequently, in response to the motions of the defendants, the federal magistrate judge in January 2005 filed recommendations that the Court’s previous decision be vacated based on lack of jurisdiction of the Court. In September 2005, the U.S. District Court issued an order vacating its prior decision, except as to matters of standing and jurisdiction. In November 2004, the defendants (including Avista Corp.) filed a petition for declaratory relief in Montana State Court requesting the resolution of the controversy that the plaintiffs raised in federal court and the Montana AG filed an answer, counterclaim and motion for summary judgment. The defendants have filed responses to the Montana AG’s motion for summary judgment. In June 2005, Avista Corp. moved for leave to amend its complaint to, inter alia, add two causes of action relating to breach of contract and negligent misrepresentation arising out of its Clark Fork Settlement Agreement that was entered into in 1999 with the State of Montana relating to the relicensing of Avista Corp.’s Noxon Rapids Hydroelectric Generating Project. The Montana State Court heard the motion for summary judgment of the Montana AG and took the matter under advisement. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, the Company intends to seek recovery of any amounts paid through the rate making process.

Colstrip Generating Project Complaint

In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed a consolidated complaint against the owners of the Colstrip Generating Project (Colstrip) in Montana District Court. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The plaintiffs allege damages to buildings as a result of rising ground water, as well as damages from contaminated waters leaking from the lakes and ponds of Colstrip. The plaintiffs are seeking punitive damages, an order by the court to remove the lakes and ponds and the forfeiture of all profits earned from the generation of Colstrip. The owners of Colstrip have undertaken certain groundwater investigation and remediation measures to address groundwater contamination. These measures include improvements to the lakes and ponds of Colstrip. The Company intends to continue to work with the other owners

105

AVISTA CORPORATION

of Colstrip in defense of this complaint. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Environmental Protection Agency Administrative Compliance Order

In December 2003, PPL Montana, LLC, as operator of Colstrip, received an Administrative Compliance Order (ACO) from the Environmental Protection Agency (EPA) pursuant to the Clean Air Act (CAA). In January 2006, the EPA issued a draft settlement agreement related to the ACO. The ACO alleges that Colstrip Units 3 & 4 have been in violation of the CAA permit at Colstrip since 1980. The permit required the Colstrip project operator to submit for review and approval by the EPA an analysis and proposal for reducing emissions of nitrogen oxides to address visibility concerns if, and when, EPA promulgates Best Available Retrofit Technology requirements for nitrogen oxide emissions. The EPA is asserting that regulations it promulgated in 1980 triggered this requirement. Avista Utilities and the other owners of Colstrip believe that the ACO is unfounded. The owners of Colstrip are discussing the proposed settlement agreement with the EPA, the Department of Environmental Quality (Montana DEQ) and the Northern Cheyenne Tribe. The draft settlement agreement would resolve the potential liability related to this issue. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, the Company intends to seek recovery of any amounts paid through the rate making process.

Colstrip Royalty Claim

The Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a Transportation Agreement. The Minerals Management Service (MMS) of the United States Department of the Interior issued an order to WECO to pay additional royalties concerning coal delivered to Colstrip Units 3 & 4 via the conveyor belt (approximately 4.46 miles long). The owners of Colstrip Units 3 & 4 take delivery of the coal at the western end (beginning) of the conveyor belt. The order asserts that additional royalties are owed MMS as a result of WECO not paying royalties in connection with revenue received by WECO from the owners of Colstrip Units 3 & 4 under the Transportation Agreement during the period October 1, 1991 through December 31, 2001. WECO’s appeal to the MMS was substantially denied in March 2005; WECO has now appealed the order to the Board of Land Appeals of the U.S. Department of the Interior. The entire appeal process could take several years to resolve. The owners of Colstrip Units 3 & 4 are monitoring the appeal process between WECO and MMS.

WECO has indicated to the owners of Colstrip Units 3 & 4 that if WECO is unsuccessful in the appeal process, WECO will seek reimbursement of any royalty payments by passing these costs through the Coal Supply Agreement. The owners of Colstrip Units 3 & 4 advised WECO that their position would be that these claims are not allowable costs per the Coal Supply Agreement nor the Transportation Agreement in the event the owners of Colstrip Units 3 & 4 were invoiced for these claims. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Hamilton Street Bridge Site

A portion of the Hamilton Street Bridge Site in Spokane, Washington (including a former coal gasification plant site that operated for approximately 60 years until 1948) was acquired by the Company through a merger in 1958. The Company no longer owns the property. In January 1999, the Company received notice from the State of Washington’s Department of Ecology (DOE) that it had been designated as a potentially liable party (PLP) with respect to any hazardous substances located on this site, stemming from the Company’s past ownership of the former gas plant site. The Company responded to the DOE acknowledging its listing as a PLP, but requested that additional parties also be listed as PLPs. In the spring of 1999, the DOE named two other parties as additional PLPs.

The DOE, the Company and another PLP, Burlington Northern & Santa Fe Railway Co. (BNSF), signed an Agreed Order in March 2000 that provided for the completion of a remedial investigation and a feasibility study. After receiving input from the Company and the other PLPs, the final Cleanup Action Plan (CAP) was issued by the DOE in August 2001 and the Consent Decree to implement the CAP was finalized in September 2002. The third PLP did not sign the Consent Decree. In September 2004, a Site Preparation Agreement was reached with the third PLP with

106

AVISTA CORPORATION

respect to the logistics of the CAP. The third PLP then completed the site preparation. The selected contractor then completed construction/installation of the work under the CAP by the end of the third quarter of 2005. The Company and BNSF filed the final Cleanup Action Report with the DOE during the fourth quarter of 2005. The Cleanup Action Plan does call for periodic ground water sampling and reporting for a period of five years.

Spokane River

In March 2001, the DOE informed Avista Development, a subsidiary of Avista Capital, of a health advisory concerning PCBs found in fish caught in a portion of the Spokane River. In June 2001, Avista Development received official notice that it had been designated as a PLP with respect to contaminated sites on the Spokane River. The DOE discovered PCBs in fish and sediments in the Spokane River in the 1970s and 1980s. In the 1990s, the DOE performed subsequent sampling of the river and identified potential sources of the PCBs, including the Spokane Industrial Park (SIP) and a number of other entities in the area. The SIP, renamed Pentzer Development Corporation (Pentzer Development) in 1990, operated a wastewater treatment plant at the site until it was closed in December 1993. The SIP’s treatment plant discharged to the Spokane River under the terms of a National Pollutant Discharge Elimination System permit issued by the DOE. Pentzer Development sold the property in 1996 and merged with Avista Development in 1998. The DOE has named at least three other PLPs in this matter.

As directed by Avista Development and one other PLP, Kaiser Aluminum & Chemical Corporation (Kaiser), the field-work for the remedial investigation began in April 2003 and was completed by the end of 2003. The other PLPs have not been participating in the process. The Cleanup Action Plan (CAP), remedial investigation and feasibility study were finalized in August 2005. The Company expects that work under the CAP will be completed in 2006.

The Company has entered into a settlement with the DOE and Kaiser relating to the remediation of the site. Under the agreement, the Company will perform the selected remedial action. Kaiser, which is presently operating under Chapter 11 bankruptcy protection, has paid the Company approximately 50 percent of the current estimate of the total costs, which was approved by the Kaiser bankruptcy judge and will be used by the Company to fund the costs of the remediation. During 2004, the Company accrued its share of the total estimated costs, which was not material to the Company’s consolidated financial condition or results of operations. Because of uncertainties with respect to, among other things, any future cost sharing agreement with the non-participating PLPs and unforeseen site conditions, the Company’s estimate of its liability could change in future periods. Based on information currently known to the Company’s management, the Company does not believe that such a change would be material to its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimate of the liability. Such a change, should it occur, could be significant.

Harbor Oil Inc. Site

Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. In June 2005, EPA Region 10 provided notification to Avista Corp., as a customer of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law. Harbor Oil’s primary business was the collection and blending of used oil for sale as fuel to ships at sea. The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and heavy metals.

Thirteen other companies received a similar notice, including current and former owners of the site, the Bonneville Power Administration, Portland General Electric Corporation, Northwestern Energy and Unocal Oil. Several meetings have been held with the EPA and the Potentially Responsible Parties (PRPs) to ask questions of the EPA regarding the Harbor Oil site and discuss the process used by the EPA in selecting PRPs.

Based on the review of its records related to Harbor Oil, the Company does not believe it is a major contributor to this potential environmental contamination based on the relative volume of waste oil delivered to the Harbor Oil site. However, there is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred. As such, it is currently not possible to make an estimate of any liability at this time.

Northeast Combustion Turbine Site

In August 2005, a diesel fuel spill occurred at the Company’s Northeast Combustion Turbine generating facility (Northeast CT) located in Spokane, Washington. The Northeast CT site had fuel storage facilities that were leased to Co-op Supply, Inc., an affiliate of Cenex Cooperative (Co-op). The fuel spill occurred when Co-op made a

107

AVISTA CORPORATION

delivery of diesel to a tank that was already nearly full and the extra fuel overflowed into a containment area. It is estimated that approximately 26,000 gallons of fuel escaped the containment area and leaked into the soil below it. An investigation, supervised by the DOE, determined the fuel was, for the most part, uniformly present in the soil to a depth of 30-35 feet. Groundwater below the site is at a depth of 170 feet. Remediation efforts included the removal of contaminated soil and the related fuel storage facilities. Options to dispose of the contaminated soil are currently being evaluated and are expected to be completed by the middle of 2006. During the fourth quarter of 2005, the Company filed a complaint against Co-op and an engineering firm to recover a substantial portion of the cleanup costs. The Company has accrued the estimated cleanup costs during 2005, which was not material to the Company’s consolidated financial condition or results of operations. It is possible that a change could occur in the Company’s estimate of the liability. Such a change, should it occur, is not expected to be significant.

Lake Coeur d’Alene

In July 1998, the United States District Court for the District of Idaho issued its finding that the Coeur d’Alene Tribe of Idaho (Tribe) owns, among other things, portions of the bed and banks of Lake Coeur d’Alene (Lake) lying within the current boundaries of the Coeur d’Alene Reservation. This action had been brought by the United States on behalf of the Tribe against the state of Idaho. The Company was not a party to this action. The United States District Court decision was affirmed by the United States Court of Appeals for the Ninth Circuit. The United States Supreme Court affirmed this decision in June 2001. This will result in, among other things, the Company being liable to the Tribe for compensation for the use of reservation lands under Section 10(e) of the Federal Power Act.

The Company’s Post Falls Hydroelectric Generating Station (Post Falls), a facility constructed in 1906 with a present capability of 18 MW, utilizes a dam on the Spokane River downstream of the Lake which controls the water level in the Lake for portions of the year (including portions of the lakebed owned by the Tribe). The Company has other hydroelectric facilities on the Spokane River downstream of Post Falls, but these facilities do not affect the water level in the Lake. The Company and the Tribe are engaged in discussions with respect to past and future compensation (which may include interest) for use of the portions of the bed and banks of the Lake, which are owned by the Tribe. If the parties cannot agree on the amount of compensation, the matter could result in litigation. The Company cannot predict the amount of compensation that it will ultimately pay or the terms of such payment. However, the Company intends to seek recovery of any amounts paid through the rate making process.

Spokane River Relicensing

Clark Fork Settlement Agreement

Dissolved atmospheric gas levels exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other signatories to the agreement and completed the Gas Supersaturation Control Program (GSCP). The Idaho Department of Environmental Quality and the U.S. Fish and Wildlife Service approved the GSCP in February 2004 and the FERC issued an order approving the GSCP in January 2005. The GSCP provides for the opening and modification of one and, potentially, both of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. Streamflows would be diverted to the tunnels when these flows are in excess of turbine capacity. The Company has undertaken physical and computer modeling studies to confirm the feasibility and likely effectiveness of its tunnel solution. The results of these studies will also help the

108

AVISTA CORPORATION

Company to refine its estimated costs for completion of the tunnels. The cost of modifying the first tunnel is currently preliminarily estimated to be $38 million (including AFUDC and inflation) and will be incurred between 2004 and 2010 ($1.7 million incurred through December 31, 2005), with the majority of these costs being incurred in 2007 through 2009. The second tunnel would be modified only after evaluation of the performance of the first tunnel and such modifications would commence no later than 10 years following the completion of the first tunnel. It is currently preliminarily estimated that the costs to modify the second tunnel would be $26 million (including AFUDC and inflation). As part of the GSCP, the Company provides $0.5 million annually as mitigation for aquatic resources that might be adversely affected by high dissolved gas levels. Mitigation funds will continue until the modification of the second tunnel commences or if the second tunnel is not modified to an agreed upon point in time commensurate with the biological effects of high dissolved gas levels. The Company intends to seek recovery of the costs for the modification of Cabinet Gorge and the mitigation payments through the rate making process.

The U.S Fish and Wildlife Service has listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the U.S. Fish and Wildlife Service, the Company is evaluating the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies will help the Company and other parties determine the best use of funds toward continuing fish passage efforts or other bull trout population enhancement measures.

Emergis Technologies, Inc. Complaint

On January 20, 2006, Emergis Technologies, Inc. (Emergis) filed a complaint against the Company alleging that certain electronic invoicing and payment system processes employed by Avista Utilities infringe upon a patent owned and held by Emergis. The complaint was filed in the United States District Court for the Eastern District of Washington and seeks unspecified compensatory and treble damages from alleged infringement of Emergis’ patent. The Company is in the process of assessing the validity of the complaint with respect to its electronic utility billing and payment processing system. Because the resolution of this complaint remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect that this complaint will have a material adverse effect on its financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

Other Contingencies

In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company believes that any ultimate liability arising from these actions will not have a material adverse impact on the Company’s financial condition, results of operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability being incurred. Such a change, should it occur, could be significant.

The Company routinely assesses, based on in-depth studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who have and have not agreed to a settlement and recoveries from insurance carriers. The Company’s policy is to accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred.

The Company has potential liabilities under the Federal Endangered Species Act for species of fish that have either already been added to the endangered species list, been listed as “threatened” or been petitioned for listing. Thus far, measures adopted and implemented have had minimal impact on the Company.

Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights. The State of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River basin could potentially adversely affect the energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The Company is participating in this extensive adjudication process, which is unlikely to be concluded in the foreseeable future.

The Company must be in compliance with requirements under the Clean Air Act and Clean Air Act Amendments at with respect to its thermal generating plants. The Company continues to monitor legislative developments at both the state and national level with respect to the potential for further restrictions on sulfur dioxide, nitrogen oxide,

109

AVISTA CORPORATION

carbon dioxide (including cap and trade emission reduction programs), as well as other greenhouse gas and mercury emissions. In particular, the EPA has finalized mercury emission regulations that will affect coal-fired generation plants, including Colstrip. The new EPA regulations establish an emission trading program to take effect beginning in January 2010, with a second phase to take effect in 2018. In addition, the Montana DEQ is planning to propose rules for the control of mercury emissions from coal-fired plants that would be more restrictive than EPA regulations. The proposed rules will be presented to the Montana Board of Environmental Review on March 23, 2006. Compliance with these new and proposed requirements and possible additional legislation or regulations could result in increases in capital expenditures and operating expenses for expanded emission controls at the Company’s thermal generating facilities. The amount of these costs and the impact of the restrictions on the operation of the facilities cannot be estimated at this time.

As of December 31, 2005, the Company’s collective bargaining agreement with the International Brotherhood of Electrical Workers represented approximately 50 percent of all of Avista Utilities’ employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the bargaining unit employees expires in March 2007. Two local agreements in Oregon, which cover approximately 50 employees, expire in April 2010. Another local agreement in Oregon is up for negotiations in 2007.

NOTE 27. INFORMATION SERVICES CONTRACTS

The Company has information services contracts that expire between 2006 and 2012. Total payments under these contracts were $12.8 million, $12.8 million and $12.0 million in 2005, 2004 and 2003, respectively. The majority of these costs are included in other operating expenses in the Consolidated Statements of Income. Minimum contractual obligations under the Company’s information services contracts are approximately $11.1 million, $11.4 million, $11.8 million, $12.1 million, $12.5 million, $12.9 million and $13.2 million from 2006 through 2012. The most significant of these contracts provides for increases due to changes in the cost of living index and further provides flexibility in the annual obligation from year-to-year subject to a three-year true-up cycle.

NOTE 28. DISPOSITION OF SOUTH LAKE TAHOE PROPERTIES

In April 2005, Avista Corp. completed the sale of its South Lake Tahoe, California natural gas properties to Southwest Gas Corporation as part of Avista Utilities’ strategy to focus on its business in the northwestern United States. This was the Company’s only regulated utility operation in California. The cash proceeds received during 2005 were approximately $16.6 million. The total pre-tax gain for 2005 was $4.1 million related to the Company’s disposition of its South Lake Tahoe natural gas properties.

Total revenues for 2004 from the South Lake Tahoe region were approximately $20.3 million (or 6 percent of total natural gas revenues) and approximately 22.1 million therms (or 4 percent of total therms) were delivered to South Lake Tahoe customers.

The Company classified the assets of its South Lake Tahoe natural gas properties as assets held for sale on the Consolidated Balance Sheets as of December 31, 2004. These assets consisted primarily of net utility property, accounts receivable and deferred natural gas costs.

NOTE 29. INFORMATION BY BUSINESS SEGMENTS

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 facility information and cost management services for 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.

110

AVISTA CORPORATION

The following table presents information for each of the Company’s business segments (dollars in thousands):


	Avista Utilities		Energy Marketing And Resource Management			Avista Advantage			Other			Intersegment Eliminations (1)			Total
For the year ended December 31, 2005:
Operating revenues	$	1,161,317	$	167,439		$	31,748		$	18,532		$	(19,429	)	$	1,359,607
Resource costs		669,596		165,423			—			—			(19,429	)		815,590
Gross margin		491,721		2,016			—			—			—			493,737
Other operating expenses		181,478		18,795			22,738			18,120			—			241,131
Depreciation and amortization		80,914		1,488			2,037			2,472			—			86,911
Income (loss) from operations		165,378		(18,267	)		6,973			(2,060	)		—			152,024
Interest expense (2)		91,847		395			912			1,694			(2,134	)		92,714
Income taxes		29,967		(4,981	)		2,147			(1,272	)		—			25,861
Net income (loss)		52,479		(8,621	)		3,922			(2,612	)		—			45,168
Capital expenditures		213,652		1,573			1,106			1,365			—			217,696
For the year ended December 31, 2004:
Operating revenues		972,574		275,646			23,444			17,127			(137,211	)		1,151,580
Resource costs		519,002		236,804			—			—			(137,211	)		618,595
Gross margin		453,572		38,842			—			—			—			492,414
Other operating expenses		180,418		25,797			19,800			21,781			—			247,796
Depreciation and amortization		72,787		1,364			1,902			2,372			—			78,425
Income (loss) from operations		134,073		11,681			1,742			(7,026	)		—			140,470
Interest expense (2)		92,068		528			874			1,008			(1,431	)		93,047
Income taxes		18,383		5,421			334			(2,546	)		—			21,592
Net income (loss) before cumulative effect of accounting change		32,467		9,733			577			(7,163	)		—			35,614
Net income (loss)		32,467		9,733			577			(7,623	)		—			35,154
Capital expenditures		115,346		1,455			840			831			—			118,472
For the year ended December 31, 2003:
Operating revenues		928,211		307,141			19,839			13,581			(145,387	)		1,123,385
Resource costs		483,097		246,952			—			—			(145,387	)		584,662
Gross margin		445,114		60,189			—			—			—			505,303
Other operating expenses		165,478		28,852			18,518			15,570			—			228,418
Depreciation and amortization		72,068		1,259			2,652			1,832			—			77,811
Income (loss) from operations		146,777		30,078			(1,331	)		(3,821	)		—			171,703
Interest expense (2)		91,908		1,009			742			1,025			(1,699	)		92,985
Income taxes		26,884		11,457			(718	)		(2,283	)		—			35,340
Income (loss) from continuing operations		36,241		20,672			(1,334	)		(4,936	)		—			50,643
Capital expenditures		102,271		2,013			459			916			—			105,659
Total Assets:
Total assets as of December 31, 2005		2,838,154		2,012,354			46,094			51,892			—			4,948,494
Total assets as of December 31, 2004		2,608,155		1,002,843			47,318			53,305			—			3,711,621

(1)

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.

(2)	Including interest expense to affiliated trusts.

111

AVISTA CORPORATION

NOTE 30. SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s energy operations are significantly affected by weather conditions. Consequently, there can be large variances in revenues, expenses and net income between quarters based on seasonal factors such as, but limited to, temperatures and streamflow conditions. A summary of quarterly operations (in thousands, except per share amounts) for 2005 and 2004 follows:


	Three Months Ended
	March 31			June 30		September 30			December 31
2005
Operating revenues	$	362,664		$	272,832	$	265,679		$	458,432
Operating expenses		324,481			226,822		261,752			398,621

Gain on sale of utility properties		—			3,209		884			—

Income from operations		38,183			49,219		4,811			59,811

Net income (loss)	$	10,189		$	18,604	$	(9,037	)	$	25,412
Outstanding common stock:
Weighted average		48,478			48,508		48,538			48,568
End of period		48,501			48,532		48,561			48,593
Total earnings (loss) per common share, diluted	$	0.21		$	0.38	$	(0.20	)	$	0.52
Dividends paid per common share	$	0.135		$	0.135	$	0.135		$	0.14
Trading price range per common share:
High	$	18.37		$	18.66	$	20.20		$	19.55
Low	$	16.62		$	16.31	$	17.90		$	16.76
2004
Operating revenues	$	343,732		$	225,888	$	241,552		$	340,408
Operating expenses		300,525			189,301		237,007			284,277

Income from operations		43,207			36,587		4,545			56,131

Net income (loss) before cumulative effect of accounting change		12,684			10,132		(9,782	)		22,580
Cumulative effect of accounting change		(460	)		—		—			—

Net income (loss)	$	12,224		$	10,132	$	(9,782	)	$	22,580
Outstanding common stock:
Weighted average		48,352			48,384		48,416			48,446
End of period		48,375			48,411		48,440			48,472
Earnings (loss) per common share, diluted:
Earnings (loss) before cumulative effect of accounting change	$	0.26		$	0.21	$	(0.20	)	$	0.46
Cumulative effect of accounting change		(0.01	)		—		—			—

Total earnings (loss) per common share, diluted	$	0.25		$	0.21	$	(0.20	)	$	0.46

Dividends paid per common share	$	0.125		$	0.13	$	0.13		$	0.13
Trading price range per common share:
High	$	18.92		$	19.17	$	18.56		$	18.55
Low	$	17.55		$	15.51	$	16.95		$	16.95

NOTE 31: SUBSEQUENT EVENT

The proposal for the formation of a holding company will be described for shareholders in Avista Corp.’s Proxy Statement-Prospectus to be distributed to shareholders in connection with the annual meeting of shareholders to be held on May 11, 2006. Avista Corp. has filed for regulatory approval from the FERC and the utility regulators in Washington, Idaho, Oregon and Montana, conditioned on approval by shareholders. If shareholders approve the proposal, and if state and federal regulatory approvals are received, the holding company organization could be implemented by the end of 2006.

112

AVISTA CORPORATION

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A.

Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers as appropriate to allow timely decisions regarding required disclosure. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company has evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon the Company’s evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2005.

Management’s Report on Internal Control Over Financial Reporting

The Company’s management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with accounting principals generally accepted in the United States of America.

The Company’s internal control over financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principals generally accepted in the United States of America, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.

Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company conducted an assessment of the effectiveness of the Company’s internal control over financial reporting based on the framework established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management has determined that the Company’s internal control over financial reporting as of December 31, 2005 is effective.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, the independent registered public accounting firm who audits the Company’s consolidated financial statements, as stated in their report on the following page, which expresses unqualified opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005.

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter (the Company’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

113

AVISTA CORPORATION

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Avista Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005 of the Company, and our report dated March 6, 2006 expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Seattle, Washington

March 6, 2006

114

AVISTA CORPORATION

Item 9B.

Other Information

None.

PART III

Item 10.

Directors and Executive Officers of the Registrant

Information regarding the directors of the Registrant and compliance with Section 16(a) of the Exchange Act has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Proxy Statement-Prospectus to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 11, 2006.


Executive Officers of the Registrant Name	Age	Business Experience During the Past 5 Years

Gary G. Ely	58	Director and Chairman of the Board since May 2001. President and Chief Executive Officer since October 2000; Executive Vice President February 1999 – October 2000; Senior Vice President and General Manager August 1996 – February 1999; various other staff and management positions with the Company since 1967.

Marian M. Durkin	52	Senior Vice President, General Counsel and Chief Compliance Officer since November 2005; Senior Vice President and General Counsel August 2005 – November 2005; prior to employment with the Company: held several legal positions with United AirLines, Inc. from 1995 to August 2005, most recently served as Vice President Deputy General Counsel and Assistant Secretary.

Karen S. Feltes	50	Senior Vice President of Human Resources and Corporate Secretary since November 2005; Vice President of Human Resources and Corporate Secretary March 2003 – November 2005; Vice President of Human Resources and Corporate Services February 2002 – March 2003; various human resources positions with the Company April 1998 – February 2002.

Malyn K. Malquist	53	Senior Vice President and Chief Financial Officer since January 2006; Senior Vice President, Chief Financial Officer and Treasurer February 2004 – January 2006; Senior Vice President and Chief Financial Officer November 2002 – February 2004; Senior Vice President September 2002 – November 2002; prior to employment with the Company: General Manager of Truckee Meadows Water Authority June 2001 – September 2002; President of Malyn Malquist Consulting January 2001 – June 2001; Chief Executive Officer of Data Engines, Inc. June 2000 – October 2000; Various positions at Sierra Pacific Resources April 1994 – April 2000, positions included Chairman of the Board, Chief Executive Officer, President, Senior Vice President, Chief Financial Officer and Principal Operations Officer.

Scott L. Morris	48	Senior Vice President since February 2002; Vice President November 2000 – February 2002; President – Avista Utilities since August 2000; General Manager – Avista Utilities for the Oregon and California operations October 1991 – August 2000; various other staff and management positions with the Company since 1981.

Christy M. Burmeister-Smith	49	Vice President and Treasurer since January 2006; Vice President and Controller June 1999 – January 2006; various other staff and management positions with the Company since 1980.

Don F. Kopczynski	50	Vice President since May 2004; Vice President of Transmission and Distribution Operations – Avista Utilities since May 2004; various other staff and management positions with the Company and its subsidiaries since 1979.

115



David J. Meyer	52	Vice President and Chief Counsel for Regulatory and Governmental Affairs since February 2004; Senior Vice President and General Counsel September 1998 – February 2004.

Kelly O. Norwood	47	Vice President since November 2000; Vice President of State and Federal Regulation – Avista Utilities since March 2002; Vice President and General Manager of Energy Resources - Avista Utilities August 2000 – March 2002; various other staff and management positions with the Company since 1981.

Ronald R. Peterson	53	Vice President since February 1998; Vice President of Energy Resources and Optimization – Avista Utilities since March 2003; Vice President and Treasurer November 1998 – March 2003; Vice President Finance – Avista Utilities September 2001 – March 2003; Vice President and Controller February 1998 – November 1998; Controller August 1996 – February 1998; various other staff and management positions with the Company since 1975.

Ann M. Wilson	40	Vice President and Controller since January 2006; Vice President and Controller of Avista Energy January 2000 – January 2006; various other staff and management positions with the Company since 1997.

Roger D. Woodworth	49	Vice President since November 1998; Vice President, Business Development and Service Optimization of Avista Utilities since March 2003; Vice President of Utility Operations of Avista Utilities September 2001 – March 2003; Vice President – Corporate Development November 1998 – September 2001; various other staff and management positions with the Company since 1979.

All of the Company’s executive officers, with the exception of Marian M. Durkin, Don F. Kopczynski, Kelly O. Norwood and Ronald R. Peterson, were officers or directors of one or more of the Company’s subsidiaries in 2005. The Company’s executive officers are elected annually by the Board of Directors.

The Company has adopted a Code of Business Conduct and Ethics (Code of Conduct) for directors, officers (including the principal executive officer, principal financial officer and controller), and employees. The Code of Conduct is available on the Company’s Web site at www.avistacorp.com and will also be provided to any shareholder without charge upon written request to:

Avista Corp.

Corporate Secretary

P.O. Box 3727 MSC-10

Spokane, Washington 99220-3727

Any changes to or waivers for executive officers and directors of the Company’s Code of Conduct will be posted on the Company’s Web site.

Item 11.

Executive Compensation

Information regarding executive compensation has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Proxy Statement-Prospectus to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 11, 2006.

116

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

(a)	Security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities):

Information regarding security ownership of certain beneficial owners (owning 5 percent or more of Registrant’s voting securities) has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Proxy Statement-Prospectus to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 11, 2006.

(b)	Security ownership of management:

Information regarding security ownership of management has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Proxy Statement-Prospectus to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 11, 2006.

(c)	Changes in control:

None.

(d)	Securities authorized for issuance under equity compensation plans as of December 31, 2005:


Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders (1)	2,083,877	$	11.20	1,077,562
Equity compensation plans not approved by security holders (2)	673,181	$	14.12	1,665,765

Total	2,757,058	$	11.91	2,743,327

(1)	Includes the Long-Term Incentive Plan approved by shareholders in 1998 and the Non-Employee Director Stock Plan approved by shareholders in 1996. In February 2005, the Board of Directors elected to terminate the Non-Employee Director Stock Plan.

(2)

Represents stock options outstanding and stock available for future issuance under the Non-Officer Employee Long-Term Incentive Plan, which was adopted by the Company in 2000. The Company currently does not plan to issue any further options or securities under this plan. Under this plan, employees (excluding directors and executive officers) of the Company and its subsidiaries may be granted stock options, stock appreciation rights, stock awards, performance awards, other stock-based awards and dividend equivalent rights. Stock options granted under this plan are equal to the market price of the Company’s common stock on the date of grant. Stock options granted under this plan have terms of up to 10 years and generally vest at a rate of 25 percent per year over a four-year period.

Item 13.

Certain Relationships and Related Transactions

Information regarding certain relationships and related transactions has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Proxy Statement-Prospectus to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 11, 2006.

Item 14.

Principal Accountant Fees and Services

Information regarding principal accountant fees and services has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Proxy Statement-Prospectus to be filed with the Securities and Exchange Commission in connection with the Registrant’s annual meeting of shareholders to be held on May 11, 2006.

117

AVISTA CORPORATION

PART IV

Item 15.

Exhibits, Financial Statement Schedules



(a) 1. Financial Statements (Included in Part II of this report):

Report of Independent Registered Public Accounting Firm		64

Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003		65

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003		66

Consolidated Balance Sheets as of December 31, 2005 and 2004		67-68

Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		69-70

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003		71

Notes to Consolidated Financial Statements		72

(a)

2. Financial Statement Schedules:

None

(a)

3. Exhibits:

Reference is made to the Exhibit Index commencing on page 120. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.

118

AVISTA CORPORATION

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	AVISTA CORPORATION

March 7, 2006	By	/s/ Gary G. Ely
Date		Gary G. Ely Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Title	Date

/s/ Gary G. Ely Gary G. Ely Chairman of the Board, President and Chief Executive Officer	Principal Executive Officer	March 7, 2006

/s/ Malyn K. Malquist Malyn K. Malquist (Senior Vice President and Chief Financial Officer)	Principal Financial and Accounting Officer	March 7, 2006

/s/ Erik J. Anderson Erik J. Anderson	Director	March 7, 2006

/s/ Kristianne Blake Kristianne Blake	Director	March 7, 2006

/s/ David A. Clack David A. Clack	Director	March 7, 2006

/s/ Roy L. Eiguren Roy L. Eiguren	Director	March 7, 2006

/s/ Jack W. Gustavel Jack W. Gustavel	Director	March 7, 2006

/s/ John F. Kelly John F. Kelly	Director	March 7, 2006

/s/ Jessie J. Knight, Jr. Jessie J. Knight, Jr.	Director	March 7, 2006

/s/ Michael L. Noel Michael L. Noel	Director	March 7, 2006

/s/ Lura J. Powell Lura J. Powell	Director	March 7, 2006

/s/ R. John Taylor R. John Taylor	Director	March 7, 2006

119

AVISTA CORPORATION

EXHIBIT INDEX


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
3(i)	1-3701 (with 2001 Form 10-K)	3(a)	Restated Articles of Incorporation of Avista Corporation as amended November 1, 1999.

3(ii)	1-3701 (with Form 8-K dated as of August 13, 2004)	3(b)	Bylaws of Avista Corporation, as amended August 13, 2004.

4.1	2-4077	B-3	Mortgage and Deed of Trust, dated as of June 1, 1939.

4.2	2-9812	4(c)	First Supplemental Indenture, dated as of October 1, 1952.

4.3	2-60728	2(b)-2	Second Supplemental Indenture, dated as of May 1, 1953.

4.4	2-13421	4(b)-3	Third Supplemental Indenture, dated as of December 1, 1955.

4.5	2-13421	4(b)-4	Fourth Supplemental Indenture, dated as of March 15, 1967.

4.6	2-60728	2(b)-5	Fifth Supplemental Indenture, dated as of July 1, 1957.

4.7	2-60728	2(b)-6	Sixth Supplemental Indenture, dated as of January 1, 1958.

4.8	2-60728	2(b)-7	Seventh Supplemental Indenture, dated as of August 1, 1958.

4.9	2-60728	2(b)-8	Eighth Supplemental Indenture, dated as of January 1, 1959.

4.10	2-60728	2(b)-9	Ninth Supplemental Indenture, dated as of January 1, 1960.

4.11	2-60728	2(b)-10	Tenth Supplemental Indenture, dated as of April 1, 1964.

4.12	2-60728	2(b)-11	Eleventh Supplemental Indenture, dated as of March 1, 1965.

4.13	2-60728	2(b)-12	Twelfth Supplemental Indenture, dated as of May 1, 1966.

4.14	2-60728	2(b)-13	Thirteenth Supplemental Indenture, dated as of August 1, 1966.

4.15	2-60728	2(b)-14	Fourteenth Supplemental Indenture, dated as of April 1, 1970.

4.16	2-60728	2(b)-15	Fifteenth Supplemental Indenture, dated as of May 1, 1973.

4.17	2-60728	2(b)-16	Sixteenth Supplemental Indenture, dated as of February 1, 1975.

4.18	2-60728	2(b)-17	Seventeenth Supplemental Indenture, dated as of November 1, 1976.

4.19	2-69080	2(b)-18	Eighteenth Supplemental Indenture, dated as of June 1, 1980.

4.20	1-3701 (with 1980 Form 10-K)	4(a)-20	Nineteenth Supplemental Indenture, dated as of January 1, 1981.

4.21	2-79571	4(a)-21	Twentieth Supplemental Indenture, dated as of August 1, 1982.

*	Incorporated herein by reference.

**	Filed herewith.

120

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
4.22	1-3701 (with Form 8-K dated September 20, 1983)	4(a)-22	Twenty-First Supplemental Indenture, dated as of September 1, 1983.

4.23	2-94816	4(a)-23	Twenty-Second Supplemental Indenture, dated as of March 1, 1984.

4.24	1-3701 (with 1986 Form 10-K)	4(a)-24	Twenty-Third Supplemental Indenture, dated as of December 1, 1986.

4.25	1-3701 (with 1987 Form 10-K)	4(a)-25	Twenty-Fourth Supplemental Indenture, dated as of January 1, 1988.

4.26	1-3701 (with 1989 Form 10-K)	4(a)-26	Twenty-Fifth Supplemental Indenture, dated as of October 1, 1989.

4.27	33-51669	4(a)-27	Twenty-Sixth Supplemental Indenture, dated as of April 1, 1993.

4.28	1-3701 (with 1993 Form 10-K)	4(a)-28	Twenty-Seventh Supplemental Indenture, dated as of January 1, 1994.

4.29	1-3701 (with 2001 Form 10-K)	4(a)-29	Twenty-Eighth Supplemental Indenture, dated as of September 1, 2001

4.30	333-82502	4(b)	Twenty-Ninth Supplemental Indenture, dated as of December 1, 2001

4.31	1-3701 (with June 30, 2002 10-Q)	4(f)	Thirtieth Supplemental Indenture, dated as of May 1, 2002

4.32	333-39551	4(b)	Thirty-First Supplemental Indenture, dated as of May 1, 2003

4.33	1-3701 (with September 30, 2003 10-Q)	4(f)	Thirty-Second Supplemental Indenture, dated as of September 1, 2003

4.34	333-64652	4(a)33	Thirty-Third Supplemental Indenture, dated as of May 1, 2004

4.35	1-3701 (with Form 8-K dated as of December 15, 2004)	4.1	Thirty-Fourth Supplemental Indenture, dated as of November 1, 2004.

4.36	1-3701 (with Form 8-K dated as of December 15, 2004)	4.2	Thirty-Fifth Supplemental Indenture, dated as of December 1, 2004.

4.37	1-3701 (with Form 8-K dated as of December 15, 2004)	4.3	Thirty-Sixth Supplemental Indenture, dated as of December 1, 2004.

4.38	1-3701 (with Form 8-K dated as of December 15, 2004)	4.4	Thirty-Seventh Supplemental Indenture, dated as of December 1, 2004.

*	Incorporated herein by reference.

**	Filed herewith.

121

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
4.39	1-3701 (with Form 8-K dated as of May 12, 2005)	4.1	Thirty-Eighth Supplemental Indenture, dated as of May 1, 2005.

4.40	1-3701 (with Form 8-K dated as of November 17, 2005)	4.1	Thirty-Ninth Supplemental Indenture, dated as of November 1, 2005.

4.41	1-3701 (with Form 8-K dated as of December 15, 2004)	4.5	Supplemental Indenture No. 1, dated as of December 1, 2004 to the Indenture dated as of April 1, 1998 between Avista Corporation and JPMorgan Chase Bank, N.A.

4.42	333-82165	4(a)	Indenture dated as of April 1, 1998 between Avista Corp. Corporation and The Chase Manhattan Bank, as Trustee.

4.43	1-3701 (with March 31, 2001 Form 10-Q)	4(f)	Indenture dated as of April 3, 2001, by and among the Company and Chase Manhattan Bank and Trust Company, National Association, as Trustee.

4.44	1-3701 (with March 31, 2004 10-Q)	4(a)	Indenture dated as of April 1, 2004 between Avista Corporation and Union Bank of California, N.A., as Trustee

4.45	1-3701 (with March 31, 2004 10-Q)	4(b)	Avista Corporation Officer’s Certificate (Under Section 301 of the Indenture, dated as of April 1, 2004).

4.46	1-3701 (with March 31, 2004 10-Q)	4(c)	AVA Capital Trust III Amended and Restated Declaration of Trust, dated as of April 5, 2004, among Avista Corporation, Union Bank of California, N.A., as Institutional Trustee, SunTrust Delaware Trust Company, as Delaware Trustee, and Malyn K. Malquist and Diane C. Thoren, as Regular Trustees.

4.47	1-3701 (with Form 8-K dated as of May 12, 2005)	4.2	First Supplemental Loan Agreement between City of Forsyth, Montana, and Avista Corporation, dated as of May 1, 2005, relating to $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999A.

4.48	1-3701 (with Form 8-K dated as of May 12, 2005)	4.3	First Supplemental Trust Indenture between City of Forsyth, Montana, and J.P. Morgan Trust Company, N.A. (successor in interest to Chase Manhattan Bank and Trust Company, National Association) as Trustee, dated as of May 1, 2005, relating to $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999A.

4.49	1-3701 (with Form 8-K dated as of May 12, 2005)	4.4	First Supplemental Loan Agreement between City of Forsyth, Montana, and Avista Corporation, dated as of May 1, 2005, relating to $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999B.

*	Incorporated herein by reference.

**	Filed herewith.

122

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
4.50	1-3701 (with Form 8-K dated as of May 12, 2005)	4.5	First Supplemental Trust Indenture between City of Forsyth, Montana, and J.P. Morgan Trust Company, N.A. (successor in interest to Chase Manhattan Bank and Trust Company, National Association) as Trustee, dated as of May 1, 2005, relating to $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999B.

4.51	1-3701 (with Form 8-K dated as of May 12, 2005)	4.6	Loan Agreement, Restated as of May 1, 2005, between City of Forsyth, Montana and Avista Corporation, relating to $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999A.

4.52	1-3701 (with Form 8-K dated as of May 12, 2005)	4.7	Trust Indenture, Restated as of May 1, 2005, between City of Forsyth, Montana and J. P. Morgan Trust Company, N.A. (successor in interest to Chase Manhattan Bank and Trust Company, N.A.) as Trustee, relating to $66,700,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999A.

4.53	1-3701 (with Form 8-K dated as of May 12, 2005)	4.8	Loan Agreement, Restated as of May 1, 2005, between City of Forsyth, Montana and Avista Corporation, relating to $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999B.

4.54	1-3701 (with Form 8-K dated as of May 12, 2005)	4.9	Trust Indenture, Restated as of May 1, 2005, between City of Forsyth, Montana and J. P. Morgan Trust Company, N.A. (successor in interest to Chase Manhattan Bank and Trust Company, N.A.) as Trustee, relating to $17,000,000 City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) Series 1999B.

4.55	1-3701 (with 1988 Form 10-K)	4(h)-1	Indenture between the Company and Chemical Bank dated as of July 1, 1988 (Series A and B Medium-Term Notes).

4.56	1-3701 (with Form 8-K dated November 15, 1999)	4	Rights Agreement, dated as of November 15, 1999, between the Company and the Bank of New York as successor Rights Agent.

4.57	333-82502	4(c)	Exchange and Registration Rights Agreement, dated December 19, 2001 among the Company and Goldman, Sach & Co., BNY Capital Markets, Inc., Fleet Securities, Inc. and TD Securities (USA), Inc.

10.1	1-3701 (with Form 8-K dated as of December 15, 2004)	10.1	Credit Agreement, dated as of December 17, 2004 among Avista Corporation, the Banks listed therein, Bank of America, N.A., as Managing Agent, Keybank National Association and U.S. Bank, National Association, as Documentation Agents, Wells Fargo Bank, as Documentation Agent and an Issuing Bank, Union Bank of California, N.A., as Syndication Agent and an Issuing Bank, and The Bank of New York, as Administrative Agent and an Issuing Bank.

*	Incorporated herein by reference.

**	Filed herewith.

123

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
10.2	1-3701 (with Form 8-K dated as of December 15, 2004)	10.2	Bond Delivery Agreement, dated December 15, 2004 between Avista Corporation and AMBAC Assurance Corporation.

10.3	1-3701 (with Form 8-K dated as of December 15, 2004)	10.3	Bond Delivery Agreement, dated December 15, 2004 between Avista Corporation and AMBAC Assurance Corporation.

10.4	1-3701 (with Form 8-K dated as of December 15, 2004)	10.2	Bond Delivery Agreement, dated as of December 17, 2004, between Avista Corporation and The Bank of New York.

10.5	1-3701 (with June 30, 2002 Form 10-Q)	4(e)	Receivables Purchase Agreement, dated as of May 29, 2002, among Avista Receivables Corp., as Seller, Avista Corporation, as initial Servicer and Eaglefunding Capital Corporation, as Conduit Purchaser and Fleet National Bank, as Committed Purchaser and Fleet Securities, Inc. as Administrator.

10.6	1-3701 (with 2004 Form 10-K)	4(d)-1	Amendment No. 1 to Receivables Purchase Agreement.

10.7	1-3701 (with 2004 Form 10-K)	4(d)-2	Amendment No. 2 to Receivables Purchase Agreement.

10.8	1-3701 (with Form 8-K dated March 22, 2005)	10.1	Amendment No. 3, dated as of March 22, 2005, to the Receivables Purchase Agreement, dated as of May 29, 2002, among Avista Receivables Corporation, as Seller, Avista Corporation, as Servicer and Ranger Funding Company, LLC (formerly known as Receivables Capital Company LLC), as Conduit Purchaser and Bank of America, N.A., as Committed Purchaser and as Adminstrator.

10.9	1-3701 (with June 30, 2005 Form 10-Q)	10.2	Third Amended and Restated Credit Agreement, dated as of July 25, 2003, among Avista Energy, Inc. and Avista Energy Canada Ltd., as Co-Borrowers, and BNP Paribas, as Administrative Agent, Collateral Agent, an Issuing Bank, and a Bank and Fortis Capital Corp. as Documentation Agent, an Issuing Bank, and a Bank and Natexis Banques Populaires as a Bank and the other financial institutions which may become parties thereto.

10.10	1-3701 (with June 30, 2005 Form 10-Q)	10.2	First Amendment to Third Amended and Restated Credit Agreement dated as of July 23, 2004.

10.11	1-3701 (with June 30, 2005 Form 10-Q)	10.2	Second Amendment to Third Amended and Restated Credit Agreement dated as of July 13, 2005.

*	Incorporated herein by reference.

**	Filed herewith.

124

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
10.12	2-13788	13(e)	Power Sales Contract (Rocky Reach Project) with Public Utility District No. 1 of Chelan County, Washington, dated as of November 14, 1957.

10.13	2-60728	10(b)-1	Amendment to Power Sales Contract (Rocky Reach Project) with Public Utility District No. 1 of Chelan County, Washington, dated as of June 1, 1968.

10.14	1-3701 (with 2002 Form 10-K)	10(b)-3	Priest Rapids Project Product Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).

10.15	1-3701 (with 2002 Form 10-K)	10(b)-4	Priest Rapids Project Reasonable Portion Power Sales Contract executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).

10.16	1-3701 (with 2002 Form 10-K)	10(b)-5	Additional Product Sales Agreement (Priest Rapids Project) executed by Public Utility District No. 2 of Grant County, Washington and Avista Corporation dated December 12, 2001 (effective November 1, 2005 for the Priest Rapids Development and November 1, 2009 for the Wanapum Development).

10.17	2-60728	5(e)	Power Sales Contract (Wanapum Project) with Public Utility District No. 2 of Grant County, Washington, dated as of June 22, 1959 (effective until November 1, 2009).

10.18	2-60728	5(e)-1	First Amendment to Power Sales Contract (Wanapum Project) with Public Utility District No. 2 of Grant County, Washington, dated as of December 19, 1977 (effective until November 1, 2009).

10.19	2-60728	5(g)	Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.

10.20	2-60728	5(g)-1	Amendment to Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.

10.21	2-60728	5(h)	Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of September 18, 1963.

*	Incorporated herein by reference.

**	Filed herewith.

125

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
10.22	2-60728	5(h)-1	Amendment to Reserved Share Power Sales Contract (Wells Project) with Public Utility District No. 1 of Douglas County, Washington, dated as of February 9, 1965.

10.23	2-60728	5(i)	Canadian Entitlement Exchange Agreement executed by Bonneville Power Administration Columbia Storage Power Exchange and the Company, dated as of August 13, 1964

10.24	2-60728	5(j)	Pacific Northwest Coordination Agreement, dated as of September 15, 1964.

10.25	1-3701 (with September 30, 1985 Form 10-Q)	1	Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company, dated as of September 17, 1985, describing the settlement of Project 3 litigation.

10.26	2-66184	5(r)	Service Agreement (Natural Gas Storage Service), dated as of August 27, 1979, between the Company and Northwest Pipeline Corporation.

10.27	2-60728	5(s)	Service Agreement (Liquefaction-Storage Natural Gas Service), dated as of December 7, 1977, between the Company and Northwest Pipeline Corporation.

10.28	1-3701 (with 1989 Form 10-K)	10(k)-4	Amendment dated as of January 1, 1990, to Firm Transportation Agreement, dated as of June 15, 1988, between the Company and Northwest Pipeline Corporation.

10.29	1-3701 (with 1992 Form 10-K)	10(k)-6	Firm Transportation Service Agreement, dated as of April 25, 1991, between the Company and Pacific Gas Transmission Company.

10.30	1-3701 (with 1992 Form 10-K)	10(k)-7	Service Agreement Applicable to Firm Transportation Service, dated June 12, 1991, between the Company and Alberta Natural Gas Company Ltd.

10.31	1-3701 (with Form 8-K for August 1976)	13(b)	Letter of Intent for the Construction and Ownership of Colstrip Units No. 3 and 4, dated as of April 16, 1974.

*	Incorporated herein by reference.

**	Filed herewith.

126

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
10.32	1-3701 (with 1981 Form 10-K)	10(s)-7	Ownership and Operation Agreement for Colstrip Units No. 3 and 4, dated as of May 6, 1981.

10.33	1-3701 (with 1981 Form 10-K)	10(s)-2	Coal Supply Agreement for Colstrip Units No. 3 and 4 between The Montana Power Company, Puget Sound Power & Light Company, Portland General Electric Company, Pacific Power & Light Company, Western Energy Company and the Company, dated as of July 2, 1980.

10.34	1-3701 (with 1981 Form 10-K)	10(s)-4	Amendment No. 1 to Coal Supply Agreement for Colstrip Units No. 3 and 4, dated as of July 10, 1981.

10.35	1-3701 (with 1988 Form 10-K)	10(l)-5	Amendment No. 4 to Coal Supply Agreement for Colstrip Units No. 3 and 4, dated as of January 1, 1988.

10.36	1-3701 (with 1992 Form 10-K)	10(s)-1	Agreements for Purchase and Sale of Firm Capacity between the Company and Portland General Electric Company dated March and June 1992.

10.37	1-3701 (with 2003 Form 10-K)	10(l)	Power Purchase and Sale Agreement between Avista Corporation and Potlatch Corporation, dated as of July 22, 2003.

10.38	1-3701 (with 1992 Form 10-K)	10(t)-8	Executive Deferral Plan of the Company. (***)

10.39	1-3701 (with 1992 Form 10-K)	10(t)-10	The Company’s Unfunded Supplemental Executive Retirement Plan. (***)

10.40	1-3701 (with1992 Form 10-K)	10(t)-11	The Company’s Unfunded Supplemental Executive Disability Plan. (***)

10.41	1-3701 (with 1992 Form 10-K)	10(t)-12	Income Continuation Plan of the Company. (***)

10.42	1-3701 (with definitive proxy statement filed on March 31, 2005)	Appendix A	Avista Corporation Long-Term Incentive Plan. (***)

10.43	1-3701 (with 2004 Form 10-K)	10(o)-6	Avista Corp. Performance Award Plan Summary (***)

10.44	1-3701 (with 2004 Form 10-K)	10(o)-7	Avista Corporation Performance Award Agreement (***)

10.45	1-3701 (with 2002 Form 10-K)	10(q)-8	Employment Agreement between the Company and Malyn K. Malquist. (***)

*	Incorporated herein by reference.

**	Filed herewith.

***	Management contracts or compensatory plans filed as exhibits by reference per Item 601(10)(iii) of Regulation S-K.

127

AVISTA CORPORATION

EXHIBIT INDEX (continued)


	Previously Filed*
Exhibit	With Registration Number	As Exhibit
10.46	1-3701(with Form 8-K dated June 21, 2005)	10.1	Employment Agreement between the Company and Marian Durkin in the form of a Letter of Employment. (***)

10.47	333-47290	99.1	Non-Officer Employee Long-Term Incentive Plan

10.48	1-3701(with 2002 Form 10-K)	10(q)-10	Form of Change of Control Agreement between the Company and its Executive Officers. (***) (1)

10.49	1-3701 (with 2002 Form 10-K)	10(q)-11	Form of Change of Control Agreement between the Company and its Executive Officers. (***) (2)

10.50	1-3701 (with Form 8-K dated as of February 9, 2006)	10.1	Avista Corporation 2006 NEO Base Compensation Table (***)

10.51	1-3701 (with Form 8-K dated September 1, 2005)	10.1	Avista Corporation Non-Employee Director Compensation (***)

10.52	1-3701 (with Form 8-K dated February 9, 2006)	10.3	Avista Corporation & Avista Utilities Executive Officer Incentive Plan for 2006 (***)

12	**		Statement re computation of ratio of earnings to fixed charges and preferred dividend requirements.

21	**		Subsidiaries of Registrant

23	**		Consent of Independent Registered Public Accounting Firm

31.1	**		Certification of Chief Executive Officer

31.2	**		Certification of Chief Financial Officer

32	****		Certification of Corporate Officers (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

*	Incorporated herein by reference.

**	Filed herewith.

***	Management contracts or compensatory plans filed as exhibits by reference per Item 601(10)(iii) of Regulation S-K.

****	Furnished herewith.

(1)	Applies for Christy M. Burmeister-Smith, Don Kopczynski, David J. Meyer, Kelly O. Norwood, Ronald R. Peterson, Ann M. Wilson and Roger D. Woodworth.

(2)	Applies for Gary G. Ely, Marian M. Durkin, Karen S. Feltes, Malyn K. Malquist and Scott L. Morris.

128

Statement re computation of ratio of earnings to fixed charges

EXHIBIT 12

AVISTA CORPORATION

Computation of Ratio of Earnings to Fixed Charges and Preferred Dividend Requirements

Consolidated

(Thousands of Dollars)


	Years Ended December 31
	2005		2004		2003		2002		2001
Fixed charges, as defined:
Interest expense	$	84,952	$	84,746	$	85,013	$	96,005	$	100,180
Amortization of debt expense and premium - net		7,762		8,301		7,972		8,861		5,639
Interest portion of rentals		2,394		2,443		4,452		6,140		5,140

Total fixed charges	$	95,108	$	95,490	$	97,437	$	111,006	$	110,959

Earnings, as defined:
Income from continuing operations	$	45,168	$	35,614	$	50,643	$	42,174	$	68,241
Add (deduct):
Income tax expense		25,861		21,592		35,340		34,849		40,585
Total fixed charges above		95,108		95,490		97,437		111,006		110,959

Total earnings	$	166,137	$	152,696	$	183,420	$	188,029	$	219,785

Ratio of earnings to fixed charges		1.75		1.60		1.88		1.69		1.98
Fixed charges and preferred dividend requirements:
Fixed charges above	$	95,108	$	95,490	$	97,437	$	111,006	$	110,959
Preferred dividend requirements (1)		—		—		1,910		4,387		3,878

Total	$	95,108	$	95,490	$	99,347	$	115,393	$	114,837

Ratio of earnings to fixed charges and preferred dividend requirements		1.75		1.60		1.85		1.63		1.91

(1)	Preferred dividend requirements have been grossed up to their pre-tax level. Effective July 1, 2003, preferred dividends are included in interest expense with the adoption of SFAS No. 150.

Subsidiaries of Registrant

Exhibit 21

Avista Corporation

SUBSIDIARIES OF REGISTRANT


Subsidiary		State or Country of Incorporation
Avista Capital, Inc.		Washington

Avista Advantage, Inc.		Washington

Avista Development, Inc.		Washington

Avista Energy, Inc.		Washington

Avista Energy Canada LTD		Canada

CoPac Management, Inc.		Canada

Avista Power, LLC		Washington

Avista Rathdrum, LLC		Washington

Rathdrum Power, LLC		Idaho

Avista Ventures, Inc.		Washington

Pentzer Corporation		Washington

Bay Area Manufacturing, Inc.		Washington

Advanced Manufacturing and Development, Inc.		California

Avista Receivables Corporation		Washington

Avista Capital II		Delaware

AVA Capital Trust III		Delaware

Spokane Energy, LLC		Delaware

Consent of Independent Registered Public Accounting Firm

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 2-81697, 2-94816, 033-54791, 333-03601, 333-22373, 333-58197, 033-32148, 333-33790, 333-47290 and 333-126577 on Form S-8, in Registration Statement Nos. 333-106491, 033-53655, 333-39551, 333-82165, 333-63243, 333-16353, 333-16353-01, 333-16353-02, 333-16353-03, 333-64652, 033-49662 and 333-113501 on Form S-3, and in Registration Statement Nos. 333-62232 and 333-82502 on Form S-4 of our reports dated March 6, 2006, relating to the consolidated financial statements of Avista Corporation and subsidiaries (which expresses an unqualified opinion and includes an explanatory paragraph for certain changes in accounting and presentation resulting from the impact of recently adopted accounting standards), and management’s report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Avista Corporation for the year ended December 31, 2005.

/s/ Deloitte & Touche LLP

Seattle, Washington

March 7, 2006

Certification of Chief Executive Officer

Exhibit 31.1

CERTIFICATION

I, Gary G. Ely, certify that:

I have reviewed this report on Form 10-K of Avista Corporation;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: March 7, 2006				/s/ Gary G. Ely
				Gary G. Ely
				Chairman of the Board, President and
				Chief Executive Officer
				(Principal Executive Officer)

Certification of Chief Financial Officer

Exhibit 31.2

CERTIFICATION

I, Malyn K. Malquist, certify that:

I have reviewed this report on Form 10-K of Avista Corporation;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date: March 7, 2006				/s/ Malyn K. Malquist
				Malyn K. Malquist
				Senior Vice President and
				Chief Financial Officer
				(Principal Financial Officer)

Certification of Corporate Officers

Exhibit 32

AVISTA CORPORATION

CERTIFICATION OF CORPORATE OFFICERS

(Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

Each of the undersigned, Gary G. Ely, Chairman of the Board, President and Chief Executive Officer of Avista Corporation (the “Company”), and Malyn K. Malquist, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: March 7, 2006

/s/ Gary G. Ely

Gary G. Ely

Chairman of the Board, President and

Chief Executive Officer

/s/ Malyn K. Malquist

Malyn K. Malquist

Senior Vice President and

Chief Financial Officer