Edgar Filing: AVISTA CORP

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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, 2009

¨	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

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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. ¨

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

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 $973,684,544 based on the last reported sale price thereof on the consolidated tape on June 30, 2009.

As of January 31, 2010, 54,852,750 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

Documents Incorporated By Reference

Document

Part of Form 10-K into Which Document is Incorporated

Proxy Statement to be filed in connection with the annual

meeting of shareholders to be held on May 13, 2010

Part III, Items 10, 11,

12, 13 and 14

AVISTA CORPORATION

INDEX


Item No.			Page No.

	Acronyms and Terms		iv

		Part I

	Available Information		1
1.	Business		1
		Company Overview	1
		Avista Utilities	2
		General	2
		Electric Operations	2
		Electric Requirements	2
		Electric Resources	3
		Hydroelectric Licensing	4
		Future Resource Needs	5
		Natural Gas Operations	6
		Regulatory Issues	7
		Federal Laws Related to Wholesale Competition	8
		Regional Transmission Organizations	8
		Reliability Standards	8
		Environmental Issues	8
		Avista Utilities Operating Statistics	10
		Advantage IQ	12
		Other Businesses	12
1A.	Risk Factors		13
1B.	Unresolved Staff Comments		16
2.	Properties		17
		Avista Utilities	17
3.	Legal Proceedings		18
4.	Submission of Matters to a Vote of Security Holders		18

		Part II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		19
6.	Selected Financial Data		20
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
		Forward-Looking Statements	21
		Business Segments	22
		Executive Level Summary	23
		Avista Utilities – Regulatory Matters	26
		Results of Operations	29
		Avista Utilities	31
		Advantage IQ	36
		Other Businesses	36
		Accounting Standards to Be Adopted in 2010	37
		Critical Accounting Policies and Estimates	37
		Liquidity and Capital Resources	41
		Review of Cash Flow Statement	41
		Overall Liquidity	41
		Credit and Nonperformance Risk	42
		Capital Resources	43
		Avista Utilities Capital Expenditures	45
		Advantage IQ Credit Agreement	46
		Advantage IQ Operations	46
		Off-Balance Sheet Arrangements	46
		Spokane Energy, LLC	46

AVISTA CORPORATION


		Credit Ratings	47
		Pension Plan	47
		Dividends	47
		Contractual Obligations	48
		Competition	48
		Long-Term Economic and Utility Load Growth	49
		Environmental Issues and Other Contingencies	49
7A.	Quantitative and Qualitative Disclosures about Market Risk		53
8.	Financial Statements and Supplementary Data		57
		Report of Independent Registered Public Accounting Firm	58
		Financial Statements	59-65
		Consolidated Statements of Income	59
		Consolidated Statements of Comprehensive Income	60
		Consolidated Balance Sheets	61-62
		Consolidated Statements of Cash Flows	63-64
		Consolidated Statements of Equity	65
		Notes to Consolidated Financial Statements	66
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		108	*
9A.	Controls and Procedures		108
9B.	Other Information		110

		Part III

10.	Directors, Executive Officers and Corporate Governance		110
11.	Executive Compensation		111
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		111
13.	Certain Relationships and Related Transactions, and Director Independence		112
14.	Principal Accounting Fees and Services		112

		Part IV

15.	Exhibits, Financial Statement Schedules		113
	Signatures		114
	Exhibit Index		115

* = not an applicable item in the 2009 calendar year for Avista Corporation

iii

AVISTA CORPORATION

ACRONYMS AND TERMS

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


Acronym/Term		Meaning

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

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

AM&D		- Advanced Manufacturing and Development, does business as METALfx

APB		- Accounting Principles Board

Advantage IQ		- Advantage IQ, Inc., provider of facility information and cost management services for multi-site customers throughout North America, subsidiary of Avista Capital

ASC		- Accounting Standards Codification

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 is capable of producing 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

Deadband or ERM deadband		- the first $4.0 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

AVISTA CORPORATION


ERM		- the Energy Recovery Mechanism in the state of Washington

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 or 1000 volts, a measure of capacity on transmission lines

KW, KWH		- Kilowatt or 1000 watts a measure of generating output, kilowatt-hour or 1000 watt hours a measure of energy produced

Lancaster Plant		- a natural gas-fired combined cycle combustion turbine plant located in Idaho

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		- The Public Utility Commission of Oregon

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

PLP		- Potentially liable party

PUD		- Public Utility District

PURPA		- the Public Utility Regulatory Policies Act of 1978

RTO		- Regional Transmission Organization

SFAS		- Statement of Financial Accounting Standards

Spokane River Project		- the five hydroelectric plants operating under one FERC license on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls)

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

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

WUTC		- Washington Utilities and Transportation Commission

AVISTA CORPORATION

PART I

Our Annual Report on Form 10-K contains forward-looking statements, which should be read with the cautionary statements and important factors included at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements.” Forward-looking statements are all statements except those of historical fact, including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions. Forward-looking statements are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and could have a significant effect on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in our statements.

Available Information

Our Web site address is www.avistacorp.com. We make annual, quarterly and current reports available at our Web site as soon as practicable after electronically filing these reports with the Securities and Exchange Commission. Information contained on our Web site is not part of this report.

Item 1.

Business

Company Overview

Avista Corporation (Avista Corp. or the Company), 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, 2009, we employed 1,538 people in our utility operations and 897 people in our subsidiary businesses. Our corporate headquarters are in Spokane, Washington, the hub of the Inland Northwest. Historically, the primary industries in our service areas were mining, lumber and wood products, military and agriculture. Although they remain important, our economy is now more diversified. Health care, higher education, finance, manufacturing and tourism are also important sectors. Retail trade, governmental and professional services have expanded to serve a larger population.

We have two reportable business segments as follows:

•

Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas. The utility also engages in wholesale purchases and sales of electricity and natural gas.

•

Advantage IQ – an indirect subsidiary of Avista Corp. (approximately 74 percent owned as of December 31, 2009) that provides sustainable utility expense management solutions to its customers that are generally multi-site companies across North America to assess and manage utility costs and usage. Advantage IQ’s primary product lines include processing, payment and auditing of energy, telecom, waste, water/sewer and lease bills, as well as strategic management services.

We have other businesses, including sheet metal fabrication, venture fund investments and real estate investments, as well as certain natural gas storage facilities held by Avista Energy, Inc. (Avista Energy). These activities do not represent a reportable business segment and are conducted by various indirect subsidiaries of Avista Corp. Over time as opportunities arise, we dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy.

Advantage IQ, Avista Energy, and various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital) which is a direct, wholly owned subsidiary of Avista Corp. Our total Avista Corp. stockholders’ equity was $1,051.3 million as of December 31, 2009, of which $81.2 million represented our investment in Avista Capital.

See “Item 6. Selected Financial Data” and “Note 27 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries).

AVISTA CORPORATION

Avista Utilities

General

Through our regulated utility operations, we generate, transmit and distribute electricity and distribute natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. We also engage in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation.

Our utility provides electric distribution and transmission, as well as natural gas distribution services in parts of eastern Washington and northern Idaho. We also provide natural gas distribution service in parts of northeast and southwest Oregon. At the end of 2009, we supplied retail electric service to 356,000 customers and retail natural gas service to 316,000 customers across our entire service territory. See “Item 2. Properties” for further information on our utility assets.

Electric Operations

In addition to providing electric distribution and transmission services, we generate electricity from facilities that we own and we purchase capacity and energy and fuel for generation under long-term and short-term contracts. We also sell capacity and energy, and surplus fuel in the wholesale market in connection with our resource optimization activities as described below.

As part of our resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve our load obligations and the use of these resources to capture available economic value. We sell and purchase wholesale electric capacity and energy and fuel as part of the process of acquiring and balancing resources to serve our load obligations. These transactions range from terms of one hour up to multiple years. We make continuing projections of:

•

electric loads at various points in time (ranging from one hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and

•

resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience.

On the basis of these projections, we make purchases and sales of electric capacity and energy and fuel to match expected resources to expected electric load requirements. Resource optimization involves generating plant dispatch and scheduling available resources and also includes transactions such as:

•

purchasing fuel for generation,

•

when economical, selling fuel and substituting wholesale electric purchases, and

•

other wholesale transactions to capture the value of generation and transmission resources.

Our optimization process includes entering into hedging transactions to manage risks.

Our generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Our 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 were $9.3 million in 2009, $9.5 million in 2008 and $10.6 million in 2007.

Electric Requirements

Our peak electric native load requirement for 2009 occurred on December 8, 2009 at which time our total load was 2,371 MW consisting of:

•

native load of 1,763 MW,

•

long-term wholesale obligations of 259 MW, and

•

short-term wholesale obligations of 349 MW.

At that time our maximum resource capacity available was 2,514 MW, which included:

•

company-owned electric generation of 1,343 MW,

•

long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 103 MW,

•

other long-term wholesale contracts of 279 MW, and

•

short-term wholesale purchases of 789 MW.

AVISTA CORPORATION

Electric Resources

We have a diverse electric resource mix of hydroelectric projects, thermal generating facilities, and power purchases and exchanges.

At the end of 2009, our facilities had a total net capability of 1,776 MW, of which 56 percent was hydroelectric and 44 percent was thermal. See “Item 2. Properties” for detailed information on generating facilities.

Hydroelectric Resources We own and operate six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is our lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation for 2010 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 529 average megawatts (aMW) (or 4.6 million MWhs). Hydroelectric resources provided 526 aMW for 2009, 535 aMW for 2008 and 519 aMW for 2007.

The following table shows our hydroelectric generation (in thousands of MWhs) during the year ended December 31:


	2009	2008	2007
Noxon Rapids	1,673	1,696	1,591
Cabinet Gorge	1,061	1,081	1,088
Post Falls	84	85	83
Upper Falls	52	78	63
Monroe Street	104	104	100
Nine Mile	106	105	100
Long Lake	487	497	471
Little Falls	199	205	193

Total company-owned hydroelectric generation	3,766	3,851	3,689
Long-term hydroelectric contracts with PUDs	839	833	861

Total hydroelectric generation	4,605	4,684	4,550

Thermal Resources We own:

•

the combined cycle combustion turbine (CT) natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) located near Boardman, Oregon,

•

a 15 percent interest in a twin-unit, coal-fired boiler generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana,

•

a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington,

•

a two-unit natural gas-fired CT generating facility, located in northeast Spokane (Northeast CT),

•

a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and

•

two small natural gas-fired generating facilities (Boulder Park and Kettle Falls CT).

Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under both term contracts and spot market purchases, including transportation agreements with unilateral renewal rights.

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 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 has provided, and is expected to meet, fuel requirements for the Kettle Falls GS.

The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. We did not operate these generating units significantly in 2009, 2008 and 2007. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.

AVISTA CORPORATION

The following table shows our thermal generation (in thousands of MWhs) during the year ended December 31:


	2009	2008	2007
Coyote Springs 2	1,559	1,696	1,623
Colstrip	1,277	1,758	1,673
Kettle Falls GS	184	201	299
Northeast CT and Rathdrum CT	44	15	20
Boulder Park and Kettle Falls CT	33	23	25

Total thermal generation	3,097	3,693	3,640

Purchases, Exchanges and Sales We purchase and sell power under various long-term contracts. We also enter into short-term purchases and sales. See “Electric Operations” for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process.

Pursuant to the Public Utility Regulatory Policies Act of 1978 (PURPA), as amended by the Federal Energy Regulatory Commission (FERC) as required by the Energy Policy Act of 2005 (Energy Policy Act), we are required to purchase generation from qualifying facilities. This includes 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 2027. These contracts were not a significant source of power resources in 2009, 2008 and 2007.

See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2009, 2008 and 2007.

Hydroelectric Licensing

We are 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 our hydroelectric plants are regulated by the FERC through project licenses. The 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, we 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). As part of the Clark Fork Settlement Agreement, we initiated the implementation of protection, mitigation and enhancement measures in March 1999. Measures in the agreement address issues related to fisheries, water quality, wildlife, recreation, land use, cultural resources and erosion.

See “Clark Fork Settlement Agreement” in “Note 24 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 Cabinet Gorge during periods when we must divert excess river flows over the spillway and our mitigation plans and efforts.

We own and operate six hydroelectric plants on the Spokane River. Five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls, which have a total present capability of 144.1 MW) are under one 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 FERC issued a new 50-year license for the Spokane River Project on June 18, 2009.

The license incorporated certain conditions that were included in the December 2008 Settlement Agreement with United States Department of Interior (DOI) and the Coeur d’Alene Tribe (the Tribe), as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality Certifications and in the amended Washington 401 Water Quality Certification. Various issues that were appealed under the Washington 401 Water Quality Certification were subsequently resolved through settlement.

As part of the Settlement Agreement with the Washington Department of Ecology (DOE), we are currently engaged with the DOE and the Environmental Protection Agency (EPA) Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. On February 12, 2010, the DOE submitted the TMDL for the EPA’s review and approval. Once the TMDL process is completed, and our level of responsibility related to low dissolved oxygen in Lake Spokane is established, we will identify potential mitigation measures. It is not possible to provide cost estimates at this time because the mitigation measures have not been fully indentified or approved by the DOE. It is also possible the TMDL will be appealed by one or more parties if it is approved by the EPA.

We are implementing the environmental and operational conditions required in the license for the Spokane River Project. The estimated cost to implement the license conditions for the five hydroelectric plants is $334 million over the

AVISTA CORPORATION

50 year license term. This will increase the Spokane River Project’s cost of power by about 40 percent, while decreasing annual generation by approximately one-half of one percent. Costs to implement mitigation measures related to the TMDL are not included in these cost estimates.

The IPUC and the WUTC approved the recovery of licensing costs through general rate cases in 2009. We will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to the licensing of the Spokane River Project.

Future Resource Needs

We have operational strategies to provide sufficient resources to meet our 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. Our average hourly load was 1,082 aMW in 2009, 1,102 aMW in 2008 and 1,089 aMW in 2007. The following is a forecast of our average annual energy requirements and resources for 2010, 2011, 2012 and 2013:

Forecasted Electric Energy Requirements and Resources

(aMW)


	2010	2011	2012	2013
Requirements:
System load	1,101	1,130	1,152	1,174
Contracts for power sales	140	139	139	139

Total requirements	1,241	1,269	1,291	1,313

Resources:
Company-owned and contract hydro generation (1)	526	520	509	511
Company-owned base load thermal generation (2)	237	247	235	234
Company-owned other thermal generation (2)	291	285	296	296
Contracts for power purchases	625	482	468	466

Total resources	1,679	1,534	1,508	1,507

Surplus resources	438	265	217	194
Additional available energy (3)	142	152	152	142

Total surplus resources	580	417	369	336

(1)	The forecast assumes near normal hydroelectric generation (decline is related to changes in contracts with PUDs).

(2)

Excludes the Northeast CT and Rathdrum CT. We generally use these resources 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.

(3)	Northeast CT and Rathdrum CT. The combined maximum capacity of the Northeast CT and Rathdrum CT is 243 MW, with estimated available energy production as indicated for each year.

In the third quarter of 2009, we filed our 2009 Electric Integrated Resource Plan (IRP) with the WUTC and the IPUC. The IRP identifies a strategic resource portfolio that meets future electric load requirements, promotes environmental stewardship and meets our obligation to provide reliable electric service to customers at rates, terms and conditions that are fair, just, reasonable and sufficient. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project. Highlights of the IRP include:

•

Up to 150 MW of wind power by 2012 (which equates to approximately 50 average megawatts),

•

An additional 200 MW of wind power by 2022,

•

750 MW of clean-burning natural gas-fired generation facilities,

•

Aggressive energy efficiency measures to reduce generation requirements by 26 percent or 339 MW,

•

Transmission upgrades to integrate new generation resources into our system, and

•

Hydroelectric upgrades at existing facilities to generate additional renewable energy.

We are subject to Washington state renewable energy portfolio standards and must obtain a portion of our electricity from qualifying renewable resources or through purchase of renewable energy credits. Our IRP identified that additional qualifying renewable energy is needed by 2016 and that new capacity and energy resources are needed by 2018. Based on resource acquisition goals identified in the IRP, we evaluated proposals from suppliers to provide us with up to 35 average megawatts (which equates to approximately 105 MW of wind power) of long-term qualified renewable energy by the end of 2012.

AVISTA CORPORATION

In 2008, we completed the acquisition of the development rights for a wind generation site. We considered developing this site and/or acquiring additional renewable resources a few years early by taking advantage of certain federal and state tax incentives. However, after detailed analysis, we decided to postpone renewable resource acquisitions, including the potential construction of a wind generation project until the 2014-2015 timeframe.

Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.

The Lancaster Plant is a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party. All of the output from the Lancaster Plant is contracted to Avista Turbine Power, Inc. (ATP), an affiliate of Avista Energy, through 2026 under a power purchase agreement. ATP conveyed the majority of its rights and obligations under this agreement to Shell Energy through the end of 2009. ATP conveyed these rights and obligations to Avista Corp. (Avista Utilities) beginning in January 2010.

In Idaho, the net costs of the Lancaster power purchase agreement were determined to be prudent by the IPUC and are currently being recovered through the Power Cost Adjustment mechanism. We will include recovery of the net costs in base rates in our next general rate case filing. In Washington, the WUTC approved deferral of the net costs subject to a future determination of the power purchase agreement being a prudent resource acquisition, and review and approval of the costs in our next general rate case filing.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for information related existing laws, as well as potential legislation that could influence our future electric resource mix.

Natural Gas Operations

General We provide natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and parts of northeast and southwest Oregon.

Market prices for natural gas, like other commodities, continue to be volatile. To provide reliable supply and to manage the impact of volatile prices on our customers, we procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and over various time periods. We also use natural gas storage capacity to support high demand periods and to procure natural gas when prices may be seasonally lower. Securing prices throughout the year and even into subsequent years mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.

As part of the process of balancing natural gas retail load requirements with resources, we engage in wholesale purchases and sales of natural gas. We also optimize natural gas resources by using excess resources and market opportunities to generate economic value that reduces retail rates. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system.

We make continuing projections of our natural gas loads and assess available natural gas resources. Forward natural gas contracts are typically for monthly delivery periods. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, we plan and execute a series of transactions to hedge a significant portion of our projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four years into the future with the highest volumes hedged for the current and most immediately upcoming natural gas operating year (November through October). We also purchase a significant portion of our natural gas supply requirements in short-term and spot markets. Natural gas resource optimization activities include:

•

wholesale market sales of surplus natural gas supplies,

•

purchases and sales of natural gas to use underutilized pipeline capacity, and

•

sales of excess natural gas storage capacity.

We also provide transportation service to certain large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we move their natural gas through our distribution system from natural gas transmission pipeline delivery points to the customers’ premises. The total volume transported on behalf of our transportation customers for 2009, 2008 and 2007 was 144.6, 148.7 and 148.8 million therms, representing 16 percent, 18 percent and 21 percent of total system deliveries.

Natural Gas Supply We purchase all of our natural gas in wholesale markets. We are connected to multiple supply basins in the western United States and western Canada through firm capacity delivery rights on six pipeline networks. Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. We have interstate pipeline capacity to serve approximately 25 percent of natural gas supplies

AVISTA CORPORATION

from domestic sources, with the remaining 75 percent from Canadian sources. 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. Future prices and delivery constraints may cause our source mix to vary.

Natural Gas Storage We own 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 11.5 million therms, with a total working natural gas capacity of 244.1 million therms.

We also contract with Northwest Natural Gas for storage at the Mist Natural Gas storage facility. This contract is for 5 million therms of capacity and up to 150 million therms of deliverability. This contract expires on March 31, 2011.

Natural gas storage enables us to place natural gas into storage when prices may be lower or to satisfy minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are higher.

Avista Energy controls 30.3 million therms of our capacity at Jackson Prairie and in conjunction with the asset sales agreement has assigned this capacity to Shell Energy through April 30, 2011. After that date, it is our intent to transfer this capacity to Avista Utilities for use in utility operations subject to state regulatory approval.

Regulatory Issues

General As a regulated public utility, we are subject to regulation by state utility commissions for 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 Public Utility Commission of Oregon (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. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission service and wholesale sales.

Our 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. Rates are designed to provide, after recovery of allowable operating expenses, an opportunity for us 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 authorized by the utility commissions. In general, a request for new rates is made on the basis of net investment, operating expenses and revenues as of a date prior to the date of the request. Although the current ratemaking process provides recovery of some future changes in net investment, operating costs and revenues, it does not reflect all changes in costs for the period in which new retail rates will be in place. This results in a lag between the time we incur costs and the time when we can start recovering the costs through rates.

Our 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 “Notes 1 and 26 of the Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes.

General Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide 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 We defer the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the WUTC and the IPUC. 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 26 of the Notes to Consolidated Financial Statements” for detailed information on power cost deferrals and recovery mechanisms in Washington and Idaho.

Purchased Gas Adjustment (PGA) Under established regulatory practices in each respective state, we are allowed to adjust 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” and “Note 26 of the Notes to Consolidated Financial Statements” for detailed information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon.

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Federal Laws Related to Wholesale Competition

Federal law promotes practices that open the electric wholesale energy market to competition. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers.

Public utilities operating under the Federal Power Act are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an OASIS to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had any substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers.

Regional Transmission Organizations

FERC Order No. 2000 (issued in 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. While it has not formally withdrawn Order No. 2000, the FERC issued orders and made public policy statements indicating its support for the development and formation of regional independently-governed transmission organizations developed by such regions, but that do not necessarily meet all of the RTO functions and characteristics outlined in Order No. 2000. These include FERC Order No. 890 (issued in 2007), which required transmission providers to implement a number of regional transmission planning coordination requirements.

We have participated in discussions with transmission providers and other stakeholders in the Pacific Northwest for several years regarding the possible formation of an RTO in the region. ColumbiaGrid, a Washington nonprofit membership corporation, was formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. ColumbiaGrid members, including Avista Corp., elected an independent slate of directors to a three-member board in August 2006. ColumbiaGrid’s members and stakeholders continue to publicly assess new responsibilities and functions that ColumbiaGrid may undertake. ColumbiaGrid’s transmission planning and expansion functional agreement was accepted by the FERC and was signed by a number of Pacific Northwest parties, including Avista Corp. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid.

Reliability Standards

Among its other provisions, the Energy Policy Act provided for the implementation of mandatory reliability standards and authorized the FERC to assess fines for non-compliance with these standards and other FERC regulations.

The FERC subsequently certified the North American Electricity Reliability Council (NERC) as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. As of January 2010, the FERC has approved 104 NERC Reliability Standards, including nine western region standards, making up the set of legally enforceable standards for the United States’ bulk electric system. The first of these reliability standards became effective in June 2007. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Our failure to comply with these standards could result in financial penalties of up to $1 million per day per violation. We have continued to successfully demonstrate our compliance with these standards.

Environmental Issues

We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have an ownership interest are designed and operated in compliance with applicable environmental laws. Furthermore, we conduct periodic reviews and audits of pertinent facilities and operations to ensure compliance and to respond to or anticipate emerging environmental issues. The Company’s Board of Directors has a committee to oversee environmental issues.

In addition to the information provided in this section, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies.”

AVISTA CORPORATION

Fisheries 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, are 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 our hydroelectric facilities. We purchase power under long-term contracts with certain 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 our operations at this time. We cannot predict the economic costs to us resulting from future mitigation measures. We 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 Licensing” for further information.

Air Quality We must be in compliance with requirements under the Clean Air Act (CAA) and Clean Air Act Amendments (CAAA) in operating our thermal generating plants. We continue to monitor legislative developments at the state and national levels for potential further restrictions on sulfur dioxide, nitrogen oxide and carbon dioxide, as well as other greenhouse gas and mercury emissions. Compliance with new and proposed requirements and possible additional legislation or regulations will result in increases to capital expenditures and operating expenses for expanded emission controls at the Company’s thermal generating facilities.

The most significant impacts on us, related to the CAA and the 1990 CAAA, pertain to Colstrip, which is a “Phase II” coal-fired plant for sulfur dioxide (SO2) under the CAAA. However, we do not expect Colstrip to be required to implement any additional SO2 mitigation in the foreseeable future in order to continue operations. Our 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 2006 (expires in 2011) and the operating permit for the Kettle Falls GS was renewed in 2007 (expires in 2012). Coyote Springs 2 was issued a renewed Title V permit in 2008 that expires in 2013. Boulder Park and the Northeast CT do not require a Title V permit based on their limited output and instead each has a synthetic minor permit that does not expire.

In 2006, the Montana Department of Environmental Quality (Montana DEQ) adopted final rules for the control of mercury emissions from coal-fired plants. The new rules set strict mercury emission limits by 2010, and put in place a recurring ten-year review process to ensure facilities are keeping pace with advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities. The Company, along with the other owners of Colstrip, completed the first phase of testing on two mercury control technologies. The joint owners of Colstrip believe, based upon current results, that the plant will be able to comply with the Montana law without utilizing the temporary alternate emission limit provision. Current estimates indicate that our share of installation capital costs will be $1.4 million and annual operating costs will increase by $1.5 million (began in late-2009). We will continue to seek recovery, through the ratemaking process, of the costs to comply with various air quality requirements.

Water Quality See “Clark Fork Settlement Agreement” in “Note 24 of the Notes to Consolidated Financial Statements” regarding dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of Cabinet Gorge. See “Spokane River Licensing” in “Note 24 of the Notes to Consolidated Financial Statements” for the Clean Water Act certifications for our licensing of the Spokane River Project.

Global Climate Changes Rising concerns about long-term global climate changes could have a significant effect on our business. We continue to monitor and evaluate the possible adoption of national, regional, or state requirements related to global climate changes. These requirements could result in significant costs for us to comply with restrictions on carbon dioxide and other greenhouse gas emissions. Such requirements could also preclude us from developing certain types of generating plants or entering into new contracts for the output from generating plants that do not meet these requirements. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for further information.

Other Environmental Issues See “Colstrip Generating Project Complaint,” “Harbor Oil Inc. Site,” and “Aluminum Recycling Site” in “Note 24 of the Notes to Consolidated Financial Statements” for information on additional environmental issues.

AVISTA CORPORATION

AVISTA UTILITIES OPERATING STATISTICS


	Years Ended December 31,
	2009			2008			2007
ELECTRIC OPERATIONS
ELECTRIC OPERATING REVENUES (Dollars in Thousands):
Residential	$	315,649		$	279,641		$	251,357
Commercial		273,954			247,714			224,179
Industrial		107,741			101,785			95,207
Public street and highway lighting		6,607			5,962			5,517

Total retail		703,951			635,102			576,260
Wholesale		88,414			141,744			105,729
Sales of fuel		32,992			44,695			12,910
Other		15,426			16,916			16,231

Total electric operating revenues	$	840,783		$	838,457		$	711,130

ELECTRIC ENERGY SALES (Thousands of MWhs):
Residential		3,791			3,744			3,670
Commercial		3,177			3,188			3,132
Industrial		1,948			2,059			2,084
Public street and highway lighting		26			26			26

Total retail		8,942			9,017			8,912
Wholesale		2,354			1,964			1,594

Total electric energy sales		11,296			10,981			10,506

ELECTRIC ENERGY RESOURCES (Thousands of MWhs):
Hydro generation (from Company facilities)		3,766			3,851			3,689
Thermal generation (from Company facilities)		3,097			3,693			3,640
Purchased power - hydro generation from long-term contracts with PUDs		839			833			861
Purchased power - wholesale		4,152			3,253			2,959
Power exchanges		(18	)		(17	)		(18	)

Total power resources		11,836			11,613			11,131
Energy losses and Company use		(540	)		(632	)		(625	)

Total energy resources (net of losses)		11,296			10,981			10,506

NUMBER OF ELECTRIC RETAIL CUSTOMERS (Average for Period):
Residential		313,884			311,381			306,737
Commercial		39,276			39,075			38,488
Industrial		1,394			1,388			1,378
Public street and highway lighting		444			434			426

Total electric retail customers		354,998			352,278			347,029

ELECTRIC RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWh)		12,079			12,023			11,965
Revenue per KWh (in cents)		8.33			7.47			6.85
Annual revenue per customer	$	1,005.62		$	898.07		$	819.45
ELECTRIC AVERAGE HOURLY LOAD (aMW)		1,082			1,102			1,089

RESOURCE AVAILABILITY at time of system peak (MW):
Total requirements (winter):
Retail native load		1,763			1,821			1,685
Wholesale obligations		608			562			367

Total requirements (winter)		2,371			2,383			2,052

Total resource availability (winter)		2,514			2,480			2,302
Total requirements (summer):
Retail native load		1,522			1,602			1,631
Wholesale obligations		685			431			381

Total requirements (summer)		2,207			2,033			2,012

Total resource availability (summer)		2,499			2,250			2,434
COOLING DEGREE DAYS: (1)
Spokane, WA
Actual		589			478			576
30-year average		394			394			394
% of average		149	%		121	%		146	%

(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,
	2009			2008			2007
NATURAL GAS OPERATIONS
NATURAL GAS OPERATING REVENUES (Dollars in Thousands):
Residential	$	251,022		$	276,386		$	264,546
Commercial		135,236			152,147			148,416
Industrial and interruptible		9,945			12,159			11,284

Total retail		396,203			440,692			424,246
Wholesale		143,524			281,668			142,167
Transportation		6,067			6,327			6,638
Other		8,624			5,520			4,182

Total natural gas operating revenues	$	554,418		$	734,207		$	577,233

THERMS DELIVERED (Thousands of Therms):
Residential		207,979			210,125			195,756
Commercial		126,345			128,224			121,557
Industrial and interruptible		10,918			12,196			10,833

Total retail		345,242			350,545			328,146
Wholesale		397,977			345,916			223,084
Transportation		144,580			148,723			148,765
Interdepartmental and Company use		502			526			438

Total therms delivered		888,301			845,710			700,433

SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):
Purchases		751,057			710,137			561,277
Storage - injections		(99,330	)		(76,491	)		(35,228	)
Storage - withdrawals		95,183			66,271			28,842
Natural gas for transportation		144,580			148,723			148,765
Distribution system losses		(3,189	)		(2,930	)		(3,223	)

Total natural gas supply		888,301			845,710			700,433

NUMBER OF NATURAL GAS RETAIL CUSTOMERS (Average for Period):
Residential		280,667			277,892			273,415
Commercial		33,214			32,901			32,327
Industrial and interruptible		300			297			302

Total natural gas retail customers		314,181			311,090			306,044

NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (therms)		741			756			716
Revenue per therm (in dollars)	$	1.21		$	1.32		$	1.35
Annual revenue per customer	$	894.37		$	994.58		$	967.56
HEATING DEGREE DAYS: (1)
Spokane, WA
Actual		6,976			7,052			6,539
30-year average		6,820			6,820			6,820
% of average		102	%		103	%		96	%
Medford, OR
Actual		4,485			4,569			4,386
30-year average		4,533			4,533			4,533
% of average		99	%		101	%		97	%

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

AVISTA CORPORATION

Advantage IQ

Our subsidiary, Advantage IQ provides sustainable utility expense management solutions to multi-site companies across North America to assess and manage utility costs and usage. Advantage IQ’s invoice processing, auditing and payment services, coupled with energy procurement, comprehensive reporting and advanced analysis, provide the critical data clients need to balance the financial, social and environmental aspects of doing business.

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

Advantage IQ has secured five patents on its two critical business systems:

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Facility IQ^™ system, which provides operational information drawn from facility bills, and

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AviTrack^™ database, which processes and reports on information gathered from service providers to ensure that customers are receiving the most effective services at the proper price.

We are not aware of any claimed or threatened infringement on any of Advantage IQ’s patents issued to date and we expect to continue to expand and protect existing patents, as well as file additional patent applications for new products, services and process enhancements.

The following table presents key statistics for Advantage IQ:


	2009		2008		2007
Customers at year-end		532		537		403
Billed sites at year-end		421,080		417,078		199,088
Dollars of customer bills processed (in billions)	$	17.4	$	16.7	$	12.5

The 2009 and 2008 amounts include customers and sites of Cadence Network, which was acquired by Advantage IQ in July 2008 (see “Note 5 of the Notes to Consolidated Financial Statements”).

On August 31, 2009, Advantage IQ acquired substantially all of the assets and liabilities of Ecos Consulting, Inc. (Ecos), a Portland, Oregon-based energy efficiency solutions provider.

Other Businesses

In periods prior to 2008, we had a reportable Energy Marketing and Resource Management segment. This segment primarily included the results of Avista Energy. On June 30, 2007, Avista Energy and its subsidiary, Avista Energy Canada, completed the sale of substantially all of their contracts and ongoing operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this business segment. Avista Energy Canada provided natural gas services to industrial and commercial customers in British Columbia, Canada.

The historical activities of Avista Energy included trading electricity and natural gas, 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 still owns natural gas storage facilities and we expect these assets to eventually be transferred to our utility operations. This business had operating revenues and resource costs through the end of 2009 related to the power purchase agreement for the Lancaster Plant. The rights and obligations related to the power purchase agreement for the Lancaster Plant were conveyed to Avista Corp. (Avista Utilities) in January 2010.

Our other businesses include Advanced Manufacturing and Development (AM&D) doing business as METALfx, a subsidiary that performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, telecom, renewable energy and medical industries. Our other investments and operations include:

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real estate investments (primarily commercial office buildings),

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investments in venture capital funds and low income housing, and

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the remaining investment in a previous fuel cell subsidiary of the Company.

Over time as opportunities arise, we dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy.

AVISTA CORPORATION

Item 1A.

Risk Factors

Risk Factors

The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Annual Report on Form 10-K), and elsewhere. Please also see “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 our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Weather (temperatures and precipitation levels) has a significant effect on our results of operations, financial condition and cash flows.

Weather impacts are described in the following subtopics:

•

retail electricity and natural gas sales,

•

the cost of natural gas supply, and

•

the cost of power supply.

Retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and retail operating revenues.

The cost of natural gas supply tends to increase with increased demand during periods of cold weather. Increased costs may adversely affect cash flows during periods when we purchase natural gas for retail supply at prices above the amount currently allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we have generally been allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales.

The cost of power supply can be significantly impacted by weather. Precipitation (consisting of snowpack and its melting pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources are required and the ability to realize net benefits from surplus hydroelectric wholesale sales is reduced.

The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation also tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and it is partially deferred or shared with customers through regulatory mechanisms. Therefore, the impact on our results of operations may be larger or smaller than the weather-related impact on power supply cost.

As a result of these factors operating in combination, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather.

We have significant capital requirements that we expect to fund, in part, by accessing capital markets. Financial market conditions may impact our results of operations and our liquidity.

Deterioration in the financial markets and credit availability and the state of the global, United States and regional economies could have an impact on our operations. We could experience increased borrowing costs or limited access to capital on reasonable terms. Additionally, we may experience an increase in uncollectible customer

AVISTA CORPORATION

accounts and collection times. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth.

The deterioration in the financial markets could also result in significant declines in the market values of assets held by our pension plan (which impacts the funded status of the plan) and could increase future funding obligations and pension expense.

We rely on access to credit from financial institutions for short-term borrowings.

We need to maintain access to adequate levels of credit with financial institutions for short-term liquidity. We have $320 million and $75 million committed lines of credit, which are scheduled to expire in April 2011. We cannot predict whether we will have access to credit beyond the expiration date. The line of credit agreements contain customary covenants and default provisions. In the event of default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.

We are dependent on our ability to access long-term capital markets.

We need to access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

We are subject to commodity price risk.

A combination of factors exposes our operations to commodity price risks. These factors include:

•

Our obligation to serve our retail customers at rates set through the regulatory process. We cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval.

•

Customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors.

•

Some of our energy supply cost is fixed by nature of the energy-producing assets or through contractual arrangements. However, a significant portion of our energy resource costs are not fixed.

Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of higher prices in wholesale energy markets. Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.

Even when we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.

Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.

We have experienced higher costs for utility operations in each of the last several years. We have also made significant capital investments into utility plant assets. Our ability to recover these costs depends on the amount and timeliness of retail rate changes allowed by regulatory agencies. We expect to periodically file for rate increases with regulatory agencies to recover our costs and provide a reasonable return to our shareholders. If regulators grant substantially lower rate increases than our requests in the future, it could have a negative effect on our operating revenues, net income and cash flows.

AVISTA CORPORATION

Deferred power and natural gas costs are subject to regulatory review; costs higher than those recovered in base rates reduce cash flows.

We defer income statement recognition and recovery from customers of certain power and natural gas costs that are higher than what is currently authorized by regulators. These power and natural gas costs are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and for the potential of disallowance by regulators.

Despite the opportunity to recover deferred power and natural gas costs, our operating cash flows are negatively affected until these costs are recovered from customers.

Our energy resource management activities may cause volatility in our cash flows and results of operations.

We engage in active hedging and resource optimization practices; however, we cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To reduce energy cost volatility and economic exposure related to commodity price fluctuations, we routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. We do not cover the entire market price volatility exposure for our forecasted net positions. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which requires additional transactions or dispatch decisions that impact cash flows.

Downgrades in our credit ratings could limit our ability to obtain financing, adversely affect the terms of financing and impact our ability to acquire energy resources.

We restored an overall corporate investment grade credit rating with the three major credit rating agencies. Our credit ratings were downgraded during 2001, which resulted in an overall corporate credit rating that was below investment grade. The downgrades were due to liquidity concerns primarily related to the significant amount of purchased power and natural gas costs that we incurred in our utility operations. These downgrades increased our debt service costs. Any future downgrades could limit our ability to access capital markets or obtain other financing on reasonable terms. Future downgrades could also require us to provide letters of credit and/or collateral to lenders and counterparties. In addition, future downgrades could reduce the number of counterparties willing to do business with us.

We are subject to various operational and event risks that are common to the utility industry.

Our utility operations are subject to operational and event risks that include:

•

blackouts or disruptions to distribution, transmission or transportation systems,

•

forced outages at generating plants,

•

fuel cost and availability, including delivery constraints,

•

disruptions to our information systems and other administrative resources required for normal operations,

•

weather conditions and natural disasters that can cause physical damage to property, requiring repairs to restore utility service, and

•

terrorism and other malicious threats.

We are currently the subject of several regulatory proceedings, and we are named in multiple lawsuits related to our participation in western energy markets as disclosed in “Note 24 of the Notes to Consolidated Financial Statements.”

Through our utility operations and the prior operations of Avista Energy, we are involved in a number of legal and regulatory proceedings and complaints related to energy 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 2000 and 2001. This allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to:

•

refund proceedings in California and the Pacific Northwest,

•

market conduct investigations by the FERC, and

•

complaints filed by various parties related to alleged misconduct by parties in western power markets.

AVISTA CORPORATION

As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from us, which could result in a negative effect on our results of operations and cash flows. See “Note 24 of the Notes to Consolidated Financial Statements” for further information. Any potential refunds or obligations arising from western energy market issues (or any other contingent matters) were retained by Avista Energy as part of its asset sale agreement in June 2007.

We are subject to legislation and related administrative rulemaking, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance.

We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including the FERC and the EPA. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC may perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties of up to $1 million per day per violation.

Future legislation or administrative rules could have a material adverse effect on our operations, results of operations, financial condition and cash flows.

There has been increasing legislative action related to concerns over long-term global climate changes, which may affect our operational and financial performance.

We are subject to legislative developments at both the state and national level for the potential of further restrictions on sulfur dioxide, nitrogen oxide, carbon dioxide, as well as other greenhouse gas and mercury emissions. Our operations could be affected by changes in laws and regulations intended to mitigate the risk of global climate changes, including restrictions on the operation of our power generation resources. In particular, a greenhouse gas bill was passed by the legislature in the state of Washington and a bill was approved by the U.S. House of Representatives. There will most likely be continuing activity in the near future.

Environmental laws and regulations may:

•

increase the operating costs of generating plants,

•

increase the lead time and capital costs for the construction of new generating plants,

•

require modification of our existing generating plants,

•

require existing generating plant operations to be curtailed or shut down,

•

reduce the amount of energy available from our generating plants, and

•

restrict the types of generating plants that can be built.

We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters.

In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 24 of the Notes to Consolidated Financial Statements” for further details of these matters including:

•

a potential liability related to contamination from the holding ponds at Colstrip in Montana,

•

waste oil delivered to the Harbor Oil, Inc. site in Portland, Oregon, and

•

aluminum dross located on a parcel of land we own near the Spokane River.

Item 1B.

Unresolved Staff Comments

As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the Securities and Exchange Commission.

AVISTA CORPORATION

Item 2.

Properties

Avista Utilities

Substantially all of our utility properties are subject to the lien of our mortgage indenture.

Our utility 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	83.3
Little Falls (Spokane)	4	32.0	34.6
Nine Mile (Spokane)	3	26.4	17.6
Upper Falls (Spokane)	1	10.0	10.2
Monroe Street (Spokane)	1	14.8	15.0
Idaho:
Cabinet Gorge (Clark Fork)	4	265.0	254.6
Post Falls (Spokane)	6	14.8	18.0
Montana:
Noxon Rapids (Clark Fork)	5	480.6	556.6

Total Hydroelectric		913.6	989.9
Thermal Generating Stations
Washington:
Kettle Falls GS	1	50.7	50.0
Kettle Falls CT	1	7.2	6.9
Northeast CT	2	61.8	56.3
Boulder Park	6	24.6	24.0
Idaho:
Rathdrum CT	2	166.5	149.0
Montana:
Colstrip Units 3 and 4 (3)	2	233.4	222.0
Oregon:
Coyote Springs 2	1	287.0	278.3

Total Thermal		831.2	786.5

Total Generation Properties		1,744.8	1,776.4

(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 under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2009.

(3)	Jointly owned; data refers to our 15 percent interest.

AVISTA CORPORATION

Electric Distribution and Transmission Plant

We operate approximately 17,800 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of approximately 660 miles of 230 kV line and 1,500 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution system also includes numerous substations with transformers, switches, monitoring and metering devices, and other equipment.

The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources to the major load centers in our 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, Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company. These interconnections serve as points of delivery for power from generating facilities outside of our distribution territory, including:

•

Colstrip,

•

Coyote Springs 2, and

•

Mid-Columbia hydroelectric generating facilities.

These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest.

The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric and Kettle Falls projects. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp, Pend Oreille County PUD and Puget Sound Energy. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term contract that allows us to serve our native load customers that are connected through the BPA’s transmission system.

Natural Gas Plant

We have natural gas distribution mains of approximately 3,400 miles in Washington, 1,900 miles in Idaho and 2,300 miles in Oregon. The natural gas distribution system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.

We own 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 11.5 million therms, with a total working natural gas capacity of 244.1 million therms. Natural gas storage enables us to place natural gas into storage when prices are lower or to satisfy minimum natural gas purchasing requirements, as well as to meet high demand periods or to withdraw natural gas from storage when spot prices are higher.

Item 3.

Legal Proceedings

See “Note 24 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.

Item 4.

Submission of Matters to a Vote of Security Holders

None.

AVISTA CORPORATION

PART II

Item 5.

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

Our common stock is currently listed on the New York Stock Exchange. As of January 31, 2010, there were 11,675 registered shareholders of our common stock.

The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:

•

our results of operations, cash flows and financial condition,

•

the success of our business strategies, and

•

general economic and competitive conditions.

Our net income available for dividends is generally derived from our regulated utility operations (Avista Utilities).

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock (when outstanding) contained in our Restated Articles of Incorporation, as amended.

On February 12, 2010, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.25 per share on the Company’s common stock.

For additional information, refer to “Notes 1, 21, 22 and 23 of Notes to Consolidated Financial Statements.” For high and low stock prices, as well as dividend information, refer to “Note 28 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)	2009			2008			2007			2006		2005
Operating Revenues:
Avista Utilities	$	1,395,201		$	1,572,664		$	1,288,363		$	1,267,938	$	1,161,317
Advantage IQ		77,275			59,085			47,255			39,636		31,748
Other		40,089			45,014			82,139			198,737		185,971
Intersegment Eliminations		—			—			—			—		(19,429	)

Total	$	1,512,565		$	1,676,763		$	1,417,757		$	1,506,311	$	1,359,607

Income (Loss) from Operations (pre-tax):
Avista Utilities	$	195,389		$	174,245		$	150,053		$	177,049	$	165,101
Advantage IQ		11,603			11,297			11,012			10,479		6,973
Other		(6,334	)		(631	)		(22,636	)		12,032		(20,327	)

Total	$	200,658		$	184,911		$	138,429		$	199,560	$	151,747

Net income	$	88,648		$	74,757		$	38,727		$	72,941	$	44,988
Net income attributable to noncontrolling interests	$	(1,577	)	$	(1,137	)	$	(252	)	$	—	$	—
Net Income (Loss) Attributable to Avista Corporation:
Avista Utilities	$	86,744		$	70,032		$	43,822		$	57,794	$	52,299
Advantage IQ		5,329			6,090			6,651			6,255		3,922
Other		(5,002	)		(2,502	)		(11,998	)		8,892		(11,233	)

Total	$	87,071		$	73,620		$	38,475		$	72,941	$	44,988

Average common shares outstanding, basic		54,694			53,637			52,796			49,162		48,523
Average common shares outstanding, diluted		54,942			54,028			53,263			49,897		48,979
Common shares outstanding at year-end		54,837			54,488			52,909			52,514		48,593
Earnings per Common Share Attributable to Avista Corporation:
Diluted	$	1.58		$	1.36		$	0.72		$	1.46	$	0.92

Basic	$	1.59		$	1.37		$	0.73		$	1.48	$	0.93

Dividends paid per common share	$	0.810		$	0.690		$	0.595		$	0.570	$	0.545
Book value per common share at year-end	$	19.17		$	18.30		$	17.27		$	17.41	$	15.82
Total Assets at Year-End:
Avista Utilities	$	3,400,384		$	3,434,844		$	3,009,499		$	2,895,883	$	2,838,154
Advantage IQ		143,060			125,911			108,929			100,431		46,094
Other		63,515			69,992			71,369			1,060,194		2,064,246

Total	$	3,606,959		$	3,630,747		$	3,189,797		$	4,056,508	$	4,948,494

Long-Term Debt (including current portion)	$	1,071,338		$	826,465		$	948,833		$	976,459	$	1,029,514
Long-Term Debt to Affiliated Trusts		51,547			113,403			113,403			113,403		113,403
Preferred Stock Subject to Mandatory Redemption		—			—			—			26,250		28,000
Total Avista Corporation Stockholders’ Equity	$	1,051,287		$	996,883		$	913,966		$	914,525	$	768,849
Ratio of Earnings to Fixed Charges (1)		2.95			2.43			1.67			2.14		1.73

(1)	See Exhibit 12 for computations.

AVISTA CORPORATION

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

From time to time, we make forward-looking statements such as statements regarding projected or future:

•

financial performance,

•

cash flows,

•

capital expenditures,

•

dividends,

•

capital structure,

•

other financial items,

•

strategic goals and objectives, and

•

plans for operations.

These statements have underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our 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 except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.

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. Many of these factors are beyond our control and they could have a significant effect on our operations, results of operations, financial condition or cash flows. This could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:

•

weather conditions (temperatures and precipitation levels) and their effects on energy demand and electric generation, including the effect of precipitation and temperatures on the availability of hydroelectric resources, the effect of temperatures on customer demand, and similar impacts on supply and demand in the wholesale energy markets;

•

the effect of state and federal regulatory decisions on our ability to recover costs and earn a reasonable return including, but not limited to, the disallowance of costs and investments, and delay in the recovery of capital investments and operating costs;

•

changes in wholesale energy prices that can affect, among other things, the cash requirements to purchase electricity and natural gas, the value received for sales in the wholesale energy market, the necessity to request changes in rates that are subject to regulatory approval, collateral required of us by counterparties on wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;

•

global financial and economic conditions (including the impact on capital markets) and their effect on our ability to obtain funding at a reasonable cost;

•

our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions;

•

economic conditions in our service areas, including the effect on the demand for, and customers’ payment for, our utility services;

•

the potential effects of legislation or administrative rulemaking, including the possible adoption of national or state laws requiring resources to meet certain standards and placing restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;

•

changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension plan, which can affect future funding obligations, pension expense and pension plan liabilities;

•

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

•

unplanned outages at any of our generating facilities or the inability of facilities to operate as intended;

•

the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2000 and 2001, including possible refunds;

•

the outcome of legal proceedings and other contingencies;

•

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

AVISTA CORPORATION

•

wholesale and retail competition including, but not limited to, alternative energy sources, suppliers and delivery arrangements;

•

the ability to comply with the terms of the licenses for our hydroelectric generating facilities at cost-effective levels;

•

natural disasters that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;

•

blackouts or disruptions of interconnected transmission systems;

•

disruption to information systems, automated controls and other technologies that we rely on for operations, communications and customer service;

•

the potential for terrorist attacks or other malicious acts, particularly for our utility assets;

•

delays or changes in construction costs, and our ability to obtain required permits and materials for present or prospective facilities;

•

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 our hydroelectric resources;

•

changes in industrial, commercial and residential growth and demographic patterns in our service territory or the loss of significant customers;

•

the loss of key suppliers for materials or services;

•

default or nonperformance on the part of any parties from which we purchase and/or sell capacity or energy;

•

deterioration in the creditworthiness of our customers and counterparties;

•

the effect of any potential decline in our credit ratings, including impeded access to capital markets, higher interest costs, and certain covenants with ratings triggers in our financing arrangements and wholesale energy contracts;

•

increasing health care costs and the resulting effect on health insurance provided to our employees and retirees;

•

increasing costs of insurance, more restricted coverage terms and our ability to obtain insurance;

•

work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;

•

the potential effects of negative publicity regarding business practices, whether true or not, which could result in, among other things, costly litigation and a decline in our common stock price;

•

changes in technologies, possibly making some of the current technology obsolete;

•

changes in tax rates and/or policies; and

•

changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses.

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our 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. We undertake 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 us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.

In this Form 10-K, we discuss our credit ratings. A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

The following discussion and analysis is provided for the consolidated financial condition and results of operations of Avista Corp. and its subsidiaries and should be read along with the consolidated financial statements.

Business Segments

We have two reportable business segments as follows:

•

AVISTA CORPORATION

•

The following table presents net income (loss) attributable to Avista Corporation for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):


	2009			2008			2007
Avista Utilities	$	86,744		$	70,032		$	43,822
Advantage IQ		5,329			6,090			6,651
Other		(5,002	)		(2,502	)		(11,998	)

Net income attributable to Avista Corporation	$	87,071		$	73,620		$	38,475

Executive Level Summary

Overall

Our operating results and cash flows are primarily from:

•

regulated utility operations (Avista Utilities), and

•

facility information and cost management services for multi-site customers (Advantage IQ).

Our net income attributable to Avista Corporation was $87.1 million for 2009, an increase from $73.6 million for 2008. This increase was primarily due to increased earnings at Avista Utilities (primarily due to the implementation of general rate increases in Washington and Idaho) as well as a decrease in interest expense. This was partially offset by a decrease in earnings at Advantage IQ and an increase in the net loss from the other businesses.

In late 2007, early 2008, and early 2009, Moody’s Investors Service, Standard & Poor’s and Fitch Ratings, Inc. upgraded our credit ratings, which resulted in an investment grade rating for our senior unsecured debt and corporate rating from each of these rating agencies. The upgrades reflected several steps taken over the past few years to lower our business risk profile and improve financial metrics. See further discussion at “Credit Ratings.” It is important to note that we are at the lower end of the investment grade category. We are working to continuously strengthen our credit ratings by improving earnings and operating cash flows, controlling costs and reducing our debt ratio.

Employment has declined throughout our service area due to cutbacks in the construction, forest products, mining and manufacturing sectors. Non-farm employment contraction for December 2009 as compared to December 2008 was 1.8 percent in Spokane, Washington, 4.6 percent in Medford, Oregon and 3.9 percent in Coeur d’Alene, Idaho, compared to the national average decline of 3.0 percent. Unemployment rates were higher for December 2009 than December 2008 in our service areas. Unemployment rates for December 2009 were 9.3 percent in Spokane, Washington, 10.6 percent in Coeur d’Alene, Idaho and 11.7 percent in Medford, Oregon, compared to the national average of 10.0 percent. The housing markets in Coeur d’Alene, Idaho and Medford, Oregon have had a higher foreclosure rate than the national average; the 2009 annual foreclosure rate was 2.6 percent in Kootenai County (the county that includes Coeur d’Alene, Idaho), and 3.1 percent in Jackson County (the county that includes Medford, Oregon) compared to the national foreclosure rate of 2.2 percent; the housing market in Spokane County remains stable with a foreclosure rate of 0.9 percent.

Avista Utilities

Avista Utilities is our most significant business segment. Our utility operating and financial performance is dependent upon, among other things:

•

weather conditions,

•

regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a fair return on investment,

•

the price of natural gas in the wholesale market, including the effect on the price of fuel for generation,

•

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

AVISTA CORPORATION

•

the ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions.

Our utility net income was $86.7 million for 2009, an increase from $70.0 million for 2008 partially due to an increase in gross margin (operating revenues less resource costs). The increase in gross margin was primarily due to the implementation of the general rate increases in Washington and Idaho. In addition, our power supply costs were less than the amount included in retail rates in Washington. This was due to lower wholesale electric and natural gas fuel prices, partially offset by below normal hydroelectric generation and the negative impact from the extended outage at the Colstrip plant (with one of the units out of service from May 2009 until November 2009). This resulted in a benefit of $3.0 million under the Energy Recovery Mechanism (ERM) in Washington for 2009 compared to an expense of $7.4 million in 2008. The increase in net income was also due to a decrease in interest expense. These positive impacts on net income were partially offset by an increase in other operating expenses, depreciation and amortization and taxes other than income taxes.

We are continuing to invest in generation, transmission and distribution systems to enhance service reliability for our customers. Utility capital expenditures were $205.4 million for 2009. We expect utility capital expenditures to be over $210 million for 2010. These estimates of capital expenditures are subject to continuing review and adjustment and do not include costs for projects associated with stimulus funding (see discussion at “Avista Utilities Capital Expenditures”).

Advantage IQ

Advantage IQ had net income of $5.3 million for 2009, a decrease from $6.1 million for 2008. The decrease for 2009 as compared to 2008 was primarily due to lower short-term interest rates (which decreases interest revenue), the decrease in our ownership percentage in the business in connection with the acquisition of Cadence Network effective July 2, 2008 and increased amortization of intangible assets (related to the Cadence and Ecos acquisitions – refer to the Cadence and Ecos discussions below). During 2009, we experienced slower internal growth at Advantage IQ than was originally expected, as some of its clients are experiencing bankruptcies and store closures in these difficult economic times. Additionally, interest revenue was lower in 2009 due to the historic low short-term interest rate environment that we are experiencing, which is expected to continue in 2010. The decrease in interest revenue was offset by other customer billing services, which increased operating revenues for 2009 as compared to 2008.

On August 31, 2009, Advantage IQ acquired substantially all of the assets and liabilities of Ecos Consulting, Inc. (Ecos), a Portland, Oregon-based energy efficiency solutions provider. The acquisition of Ecos was funded primarily through borrowings under Advantage IQ’s committed credit agreement. Under the terms of the transaction, the assets and liabilities of Ecos were acquired by a wholly owned subsidiary of Advantage IQ.

Effective July 2, 2008, Advantage IQ acquired Cadence Network, a Cincinnati, Ohio-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock, which is subject to redemption. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to have their shares of Advantage IQ stock redeemed during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties.

We would like to have a market determined valuation of our investment in Advantage IQ within the next four years. The potential valuation of Advantage IQ depends on future market conditions, growth of the business and other factors. This may provide access to public market capital and provide potential liquidity to Avista Corp. and the other owners of Advantage IQ. There can be no assurance that we will be able to complete such a transaction.

Other Businesses

The net loss for these operations was $5.0 million for 2009 compared to a net loss of $2.5 million for 2008. Contributing to the net loss attributable to Avista Corporation for 2009 was the impairment of a commercial building of $3.0 million, losses on long-term venture fund investments of $0.8 million (compared to losses of $1.4 million in 2008) and increased litigation costs related to the remaining contracts and previous operations of Avista Energy.

Liquidity and Capital Resources

We need to access long-term capital markets from time to time to finance capital expenditures, repay maturing long-term debt and obtain additional working capital. Our ability to access capital on reasonable terms is subject to numerous factors, many of which, including market conditions, are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

AVISTA CORPORATION

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 5, 2011. We had $87.0 million of cash borrowings and $28.4 million in letters of credit outstanding as of December 31, 2009, under our $320.0 million committed line of credit.

In November 2009, we entered into a new committed line of credit in the total amount of $75.0 million with an expiration date of April 5, 2011. The new committed line of credit replaced a $200.0 million committed line of credit that expired in November 2009. We had no borrowings outstanding as of December 31, 2009, under our $75.0 million committed line of credit. We reduced the facility based on our forecasted liquidity needs.

In March 2009, we amended our accounts receivable sales facility to extend the termination date to March 2010. We expect to renew this facility before the March 2010 expiration. Under this facility, we can sell without recourse, on a revolving basis, up to $85.0 million of accounts receivable. Based upon calculations of our eligible accounts receivable under this agreement, we had the ability to sell up to $85.0 million as of December 31, 2009. There were not any accounts receivable sold under this facility as of December 31, 2009.

As of December 31, 2009, we had a combined $364.6 million of available liquidity under our $320.0 million committed line of credit, $75.0 million committed line of credit, and $85.0 million revolving accounts receivable sales facility.

In September 2009, we issued $250.0 million of 5.125 percent First Mortgage Bonds due in 2022. The net proceeds from the issuance of $249.4 million (net of discounts and before Avista Corp.’s expenses) were used to retire variable rate short-term borrowings outstanding under our $320.0 million committed line of credit, and for general corporate purposes. In conjunction with the issuance of long-term debt, we cash settled interest rate swap agreements and received a total of $10.8 million.

In April 2009, we redeemed the total amount outstanding ($61.9 million) of our Junior Subordinated Debt Securities held by AVA Capital Trust III (Long-term Debt to Affiliated Trusts). Concurrently, AVA Capital Trust III redeemed all of the Preferred Trust Securities issued to third parties ($60.0 million) and all of the Common Trust Securities issued to us ($1.9 million). The net redemption of $60.0 million was funded by borrowings under our $320.0 million committed line of credit agreement.

In December 2009, we purchased $17.0 million of our Pollution Control Bonds. We are planning, subject to market conditions, to refund these bonds in 2010 along with $66.7 million of our Pollution Control Bonds we purchased in December 2008.

In addition to the refunding of $83.7 million of our Pollution Control Bonds, we are planning to issue up to $45 million of common stock in 2010 in order to maintain our capital structure at an appropriate level for our business. After considering the refunding of our Pollution Control Bonds and issuances of common stock during 2010, we expect net cash flows from operating activities and our committed line of credit agreements (total of $395.0 million) to provide adequate resources to fund:

•

capital expenditures,

•

dividends, and

•

other contractual commitments.

In December 2009, we entered into an amended and restated sales agency agreement with a sales agent to issue up to 1.25 million shares of our common stock from time to time. We originally entered into a sales agency agreement to issue up to 2 million shares of our common stock in December 2006. In 2008, we issued 750,000 shares of our common stock under this sales agency agreement. We did not issue any common stock under this agreement in 2009.

Due to market conditions and the decline in the fair value of pension plan assets in 2008, we contributed $48 million to the pension plan in 2009 as compared to the $28 million we contributed in 2008. In 2009, the fair value of pension plan assets increased. We expect that our contribution for 2010 will be $21 million. The determination of pension plan contributions in future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation).

AVISTA CORPORATION

Avista Utilities – Regulatory Matters

General Rate Cases

We regularly review the need for electric and natural gas rate changes in each state in which we provide service. We will continue to file for rate adjustments to:

•

provide for recovery of operating costs and capital investments, and

•

more closely align earned returns with those allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items. We are planning to file general rate cases in Washington and Idaho by the end of the first quarter of 2010 and expect to file a general rate case in Oregon by the end of the second quarter of 2010 to more closely align earned returns with those authorized. The following is a summary of our 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 2010	8.25	%	10.2	%	46.5	%
Idaho electric and natural gas	August 2009	8.55	%	10.5	%	50.0	%
Oregon natural gas	November 2009	8.19	%	10.1	%	50.0	%

Washington General Rate Cases

In September 2008, we entered into a settlement stipulation in our general rate case that was filed with the WUTC in March 2008. This settlement stipulation was approved by the WUTC in December 2008. The new electric and natural gas rates became effective on January 1, 2009. As agreed to in the settlement, base electric rates for our Washington customers increased by an average of 9.1 percent, which was designed to increase annual revenues by $32.5 million. Base natural gas rates for our Washington customers increased by an average of 2.4 percent, which was designed to increase annual revenues by $4.8 million.

On January 27, 2009, the Public Counsel Section of the Washington Attorney General’s Office (Public Counsel) filed a Petition for Judicial Review (in Thurston County Superior Court) of the WUTC’s December 2008 order approving our multiparty settlement. Public Counsel raised a number of issues that were previously argued before the WUTC. These included whether the recovery of settlement costs associated with resolving a dispute with the Coeur d’Alene Tribe would constitute illegal “retroactive ratemaking” (the Washington portion of these costs was $25.2 million). Public Counsel also questioned whether the WUTC’s decision to entertain supplemental testimony to update our filing for power supply costs during the course of the proceedings was appropriate. Finally, Public Counsel argued that the settlement improperly included advertising costs, dues and donations, and certain other expenses. The appeal itself did not prevent the new rates from going into effect.

On December 18, 2009, the Thurston County Superior Court affirmed the decision of the WUTC and rejected the arguments of Public Counsel, with the exception of disallowing $0.1 million of miscellaneous expenses, including charitable donations. Public Counsel has until March 4, 2010 to further appeal the WUTC’s decision.

On December 22, 2009, the WUTC issued an order in our electric and natural gas general rate cases that were filed with the WUTC in January 2009. The WUTC approved a base electric rate increase for our Washington customers of 2.8 percent, which is designed to increase annual revenues by $12.1 million. Base natural gas rates for our Washington customers increased by an average of 0.3 percent, which is designed to increase annual revenues by $0.6 million. The new electric and natural gas rates became effective on January 1, 2010.

Following the execution of a partial settlement stipulation in September 2009, we revised our electric rate increase request downward from $69.8 million to $37.5 million, primarily due to the decline in the wholesale prices of electricity and natural gas. We also reduced our natural gas request from $4.9 million to $2.8 million. Under the partial settlement stipulation, we reached agreement with the other settling parties on issues in the areas of cost of capital, power supply, rate spread and rate design, and funding under the Low-Income Ratepayer Assistance Program. The WUTC approved this partial settlement stipulation in its order on December 22, 2009.

The WUTC did not allow us to include the costs associated with the power purchase agreement for the Lancaster Plant in rates, indicating we did not demonstrate compliance with certain requirements necessary for immediate inclusion in rates. However, the WUTC directed us to file to defer costs associated with the Lancaster Plant, with a carrying charge, for potential recovery in a future rate proceeding if we demonstrate that we have satisfied these requirements. Our proposed deferred accounting treatment for the net costs associated with the Lancaster Plant was

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approved by the WUTC in February 2010. The net costs associated with the power purchase agreement for the Lancaster Plant account for approximately half of the difference between our revised electric rate increase request of $37.5 million and the $12.1 million increase approved by the WUTC.

The WUTC also did not allow for certain pro forma future capital additions to rate base, as well as certain increases in labor costs, tree trimming costs and information systems costs. These costs account for the majority of the remaining difference between our revised electric rate increase request and the amount approved by the WUTC.

The partial settlement stipulation (as approved by the WUTC on December 22, 2009) is based on an overall rate of return of 8.25 percent with a common equity ratio of 46.5 percent and a 10.2 percent return on equity. Our original request was based on a proposed overall rate of return of 8.68 percent with a common equity ratio of 47.5 percent and an 11.0 percent return on equity.

Idaho General Rate Cases

In August 2008, we entered into an all-party settlement stipulation in our electric and natural gas general rate cases that were filed with the IPUC in April 2008. This settlement stipulation was approved by the IPUC in September 2008. The new electric and natural gas rates became effective on October 1, 2008. As agreed to in the settlement, base electric rates for our Idaho customers increased by an average of 12.0 percent, which was designed to increase annual revenues by $23.2 million. Base natural gas rates for our Idaho customers increased by an average of 4.7 percent, which was designed to increase annual revenues by $3.9 million.

In June 2009, we entered into an all-party settlement stipulation in our electric and natural gas general rate cases that were filed with the IPUC in January 2009. This settlement stipulation was approved by the IPUC in July 2009. The new electric and natural gas rates became effective on August 1, 2009. As agreed to in the settlement, base electric rates for our Idaho customers increased by an average of 5.7 percent, which was designed to increase annual revenues by $12.5 million. Offsetting the base electric rate increase was an overall 4.2 percent decrease in the Power Cost Adjustment (PCA) surcharge, which was designed to decrease annual PCA revenues by $9.3 million, resulting in a net increase in annual revenues of $3.2 million. Base natural gas rates for our Idaho customers increased by an average of 2.1 percent, which was designed to increase annual revenues by $1.9 million. Offsetting the natural gas rate increase for residential customers was an equivalent Purchased Gas Adjustment (PGA) decrease of 2.1 percent. Large general services received a PGA decrease of 2.4 percent and interruptible services received a PGA decrease of 2.8 percent. The overall PGA decrease resulted in a $2.0 million decrease in annual PGA revenues, resulting in a net decrease in annual revenues of $0.1 million. The PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin or net income.

Our original request was for an electric rate increase of 12.8 percent, which was designed to increase annual revenues by $31.2 million. Offsetting the electric rate increase was a decrease in the PCA surcharge of 5.0 percent, which was designed to decrease annual revenues by $12.3 million. We also requested to increase natural gas rates by an average of 3.0 percent, which was designed to increase annual revenues by $2.7 million.

Oregon General Rate Cases

As approved by the OPUC in March 2008, natural gas rates for our Oregon customers increased 0.4 percent effective April 1, 2008 (designed to increase annual revenues by $0.5 million) and increased an additional 1.1 percent effective November 1, 2008 (designed to increase annual revenues by an additional $1.4 million).

In September 2009, we entered into an all-party settlement stipulation in our general rate case that was filed with the OPUC in June 2009. This settlement stipulation was approved by the OPUC in October 2009. The new natural gas rates became effective on November 1, 2009. As agreed to in the settlement, base natural gas rates for our Oregon customers increased by an average of 7.1 percent, which was designed to increase annual revenues by $8.8 million. In our June 2009 general rate case filing, we requested a natural gas rate increase of 11.6 percent, designed to increase annual natural gas service revenues by $14.2 million. As part of the settlement agreement, we agreed to refund a total of $2.4 million to our Oregon customers related to Oregon Senate Bill 408 (see further discussion below).

Purchased Gas Adjustments

Effective November 1, 2009, natural gas rates decreased 22 percent in Oregon, 26 percent in Washington and 23 percent in Idaho. PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb (gain or loss) 10 percent of the difference between actual and projected gas costs for supply that is not hedged. Total net deferred natural gas costs were a liability of $40.0 million as of December 31, 2009, an increase from $18.6 million as of December 31, 2008. The liability at December 31, 2009 is being refunded to customers through the PGAs implemented in November 2009.

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Oregon Senate Bill 408

The OPUC established rules in September 2007 related to Oregon Senate Bill 408 (OSB 408), which was enacted into law in 2005. These rules direct the utility to establish an automatic adjustment clause to account for the difference between income taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. The automatic adjustment clause may result in either rate increases or rate decreases.

In October 2009, the OPUC approved a settlement stipulation in our general rate case that also resolved the refund liability for the 2007 tax report. The approved settlement provided for a refund of $2.4 million, including interest, over a two-month period, November and December of 2009. This refund was approximately equal to the new revenue from the general rate increase for this period.

In October 2009, we filed the tax report for 2008 showing taxes paid to be less than taxes collected by $0.9 million before interest. In January 2010, we filed an all-party settlement with the OPUC for this amount. We expect an order from the OPUC on the final level of refund by April 2010. We recorded a potential refund liability for the 2009 tax report of $0.8 million.

Natural Gas Decoupling

In January 2007, the WUTC approved the implementation of a natural gas decoupling mechanism as a pilot for a two and one-half-year period. The decoupling mechanism is designed to recover a portion of lost margin resulting from lower usage by Washington residential and small commercial customers primarily due to conservation. However, the mechanism does not provide rate adjustments related to abnormal weather. As part of the general rate case order in December 2009, the WUTC approved continuation of the natural gas decoupling mechanism on a permanent basis, with certain modifications. Beginning July 2009, we can defer 45 percent of the lost margin associated with lower customer usage, as compared to a deferral of 90 percent during the pilot period. In the fall of each year, we can file to recover the deferred amount accumulated over the most recent July-June period if our energy efficiency therm savings meet certain pre-established targets associated with our natural gas demand side management programs. If per-customer therm usage (weather-normalized) during a July-June period were to increase instead of decrease, it may result in a refund to customers of 45 percent of the margin associated with higher customer usage.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales, and the amount included in base retail rates for our Washington customers. In periods where we are a net seller of wholesale power, market prices lower than the prices included in rates negatively impact the ERM. In periods where we are a net purchaser, market prices lower than the amount included in retail rates have a beneficial impact under the ERM.

This difference in net power supply costs primarily results from changes in:

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short-term wholesale market prices and sales and purchase volumes,

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the level of hydroelectric generation,

•

the level of thermal generation (including changes in fuel prices), and

•

retail loads.

We absorb the cost or receive the benefit from the initial amount of power supply costs in excess of or below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. We incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. We share annual power supply cost variances between $4.0 million and $10.0 million with customers. There is a 50 percent customers/50 percent Company sharing when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing when actual power supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate. We absorb into power supply costs the remaining 10 percent of the annual variance beyond $10.0 million. The following is a summary of the ERM:


Annual Power Supply Cost Variability	Deferred for Future Surcharge or Rebate to Customers		Expense or Benefit to the Company
+/- $0 - $4 million	0	%	100	%
+ between $4 million - $10 million	50	%	50	%
- between $4 million - $10 million	75	%	25	%
+/- excess over $10 million	90	%	10	%

AVISTA CORPORATION

Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff 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. Additionally, we must make a filing (no sooner than January 1, 2011), to allow all interested parties the opportunity to review the ERM, and make recommendations to the WUTC related to the continuation, modification or elimination of the ERM.

In February 2010, the WUTC approved our request to eliminate the existing ERM surcharge. The surcharge was eliminated as the previous balance of deferred power costs has been substantially recovered. This will result in an overall rate reduction of 7 percent for our Washington customers with no impact on our income from operations or net income.

A provision of our ERM requires that in the case of a major plant outage (below 70 percent availability), there may be a disallowance of fixed costs during the outage period if the outage resulted from imprudent actions, or if actual fixed costs are below the level used to calculate base rates. During scheduled maintenance in March 2009, turbines in unit 4 of Colstrip, of which we are a 15 percent owner, were found to be in need of repair. These repairs extended the planned outage from May 2009 until November 2009. We believe the outage was not due to imprudent actions and we expect there will not be a reduction in fixed costs for the plant outage.

We have a Power Cost Adjustment (PCA) mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. The PCA rate surcharge was 0.61 cents per KWh for the period October 1, 2008 through September 30, 2009. However, the surcharge rate was lowered to 0.344 cents per KWh on August 1, 2009 to help mitigate the impact of the general rate increase that was also effective on that date. The surcharge rate is expected to remain in place until October 1, 2010, when it will be replaced by a new rate that will be proposed as part of the PCA report for the period July 1, 2009 through June 30, 2010.

The following table shows activity in deferred power costs for Washington and Idaho during 2008 and 2009 (dollars in thousands):


	Washington			Idaho			Total
Deferred power costs as of December 31, 2007	$	58,524		$	21,163		$	79,687
Activity from January 1 – December 31, 2008:
Power costs deferred		7,049			10,029			17,078
Interest and other net additions		2,231			1,153			3,384
Recovery of deferred power costs through retail rates		(30,852	)		(11,690	)		(42,542	)

Deferred power costs as of December 31, 2008		36,952			20,655			57,607
Activity from January 1 – December 31, 2009:
Power costs deferred		—			17,985			17,985
Interest and other net additions		879			388			1,267
Recovery of deferred power costs through retail rates		(31,567	)		(17,521	)		(49,088	)

Deferred power costs as of December 31, 2009	$	6,264		$	21,507		$	27,771

Results of Operations

The following provides an overview of changes in our Consolidated Statements of Income. More detailed explanations are provided, particularly for operating revenues and operating expenses, in the business segment discussions (Avista Utilities, Advantage IQ and the other businesses) that follow this section.

2009 compared to 2008

Utility revenues decreased $177.5 million to $1,395.2 million due to decreased natural gas revenues of $179.8 million, partially offset by increased electric revenues of $2.3 million. The decrease in natural gas revenues was primarily the result of decreased wholesale revenues of $138.1 million (due to decreased prices, offset by increased volumes) and retail natural gas revenues of $44.5 million (primarily due to decreased prices and partially due to decreased volumes). The increase in electric revenues was primarily due to increased retail revenues of $68.8 million (primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increases implemented on October 1, 2008 and August 1, 2009), partially offset by decreased wholesale revenues of $53.3 million (due to a decrease in prices, partially offset by an increase in volumes) and sales of fuel of $11.7 million.

AVISTA CORPORATION

Non-utility energy marketing and trading revenues decreased $0.8 million to $24.4 million. These revenues primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were conveyed to Shell Energy through the end of 2009. These rights and obligations were conveyed to our utility operations in January 2010.

Other non-utility revenues increased $14.1 million to $92.9 million as a result of an increase in revenues from Advantage IQ of $18.2 million primarily due to the acquisition of Cadence Network in the third quarter of 2008 and Ecos in the third quarter of 2009, as well as other customer billing services. These increases in revenues from Advantage IQ were partially offset by a decrease in interest earnings on funds held for customers (due to lower interest rates). The increase in revenues at Advantage IQ was partially offset by decreased revenues from our other businesses of $4.1 million, primarily due to decreased sales at AM&D.

Utility resource costs decreased $232.5 million due to decreases in natural gas resource costs of $186.1 million and electric resource costs of $46.3 million. The decrease in natural gas resource costs primarily reflects a decrease in the price of natural gas purchases. The decrease in electric resource costs was primarily due to a decrease in fuel costs (due to a decrease in thermal generation and natural gas fuel prices).

Utility other operating expenses increased $23.4 million primarily due to an $8.9 million increase in electric generation operating and maintenance expenses, a $4.3 million increase in natural gas distribution and service costs, as well as a $10.7 million increase in pension and other benefit costs.

Utility depreciation and amortization increased $5.9 million primarily due to additions to utility plant.

Utility taxes other than income taxes increased $4.5 million due to increased revenue related taxes and increased property taxes.

Non-utility resource costs decreased $0.1 million. These costs primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were conveyed to Shell Energy through the end of 2009. These rights and obligations were conveyed to our utility operations in January 2010.

The net change in other non-utility operating expenses was an increase of $17.6 million due to an increase of $16.6 million for Advantage IQ primarily due to the acquisition of Cadence Network in the third quarter of 2008 and the acquisition of Ecos in the third quarter of 2009. The increase was also partially due to an impairment of a commercial building of $3.0 million in the other businesses. These increases were partially offset by decreased operating expenses from AM&D.

Interest expense decreased $8.4 million due to the effect of long-term debt maturities and redemptions during 2008, which were funded primarily with proceeds from the issuance of long-term debt as well as borrowings under our $320.0 million committed line of credit at lower interest rates. The decrease was also partially due to interest expense of $1.4 million related to an income tax settlement recorded in the third quarter of 2008.

Interest expense to affiliated trusts decreased $4.2 million due to the redemption of $61.9 million of long-term debt due to affiliated trusts in April 2009 and a decrease in the variable interest rate.

Capitalized interest decreased $4.1 million primarily due to a decrease in the effective borrowing rate used to compute capitalized interest, as the average balance outstanding under our committed line of credit was significantly higher in 2009 as compared to 2008.

Other income-net decreased $9.6 million due to a decrease in interest income (primarily due to $5.7 million of interest income recorded on the Internal Revenue Service (IRS) settlement agreement in the third quarter of 2008). The decrease was also due to a decrease in equity-related AFUDC.

Income taxes increased $0.7 million and our effective tax rate was 34.3 percent for 2009 compared to 37.9 percent for 2008. The decrease in our effective tax rate was primarily due to adjustments related to IRS audits and adjustments for the 2008 filed federal tax return. In total, these adjustments (recorded in the third quarter of 2009) had a favorable impact to recorded income tax expense of $3.2 million (Avista Utilities).

2008 compared to 2007

Utility revenues increased $284.3 million to $1,572.7 million as a result of increases in natural gas revenues of $157.0 million and electric revenues of $127.3 million. The increase in natural gas revenues was primarily the result of increased wholesale revenues (due to increased prices and volumes) of $139.5 million and retail natural gas revenues (due to increased volumes) of $16.4 million. The increase in electric revenues was primarily due to

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increased retail revenues (primarily due to the Washington general rate increase implemented on January 1, 2008 and the Idaho general rate increase implemented on October 1, 2008) of $58.8 million, wholesale revenues of $36.0 million and sales of fuel of $31.8 million.

Non-utility energy marketing and trading revenues decreased $36.3 million to $25.2 million. This category of revenues decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

Other non-utility revenues increased $11.0 million to $78.9 million as a result of an increase in revenues from Advantage IQ of $11.8 million primarily due to customer growth and the acquisition of Cadence Network in the third quarter of 2008, partially offset by a decrease in interest earnings on funds held for customers (due to lower interest rates).

Utility resource costs increased $251.0 million due to increases in natural gas resource costs of $147.9 million and electric resource costs of $103.1 million. The increase in natural gas resource costs primarily reflects an increase in the volume and price of natural gas purchases and increased amortization of deferred natural gas costs. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case implemented on January 1, 2008 and the Idaho general rate case implemented on October 1, 2008, as well as higher purchased power and fuel costs.

Utility other operating expenses increased $7.8 million primarily due to a $4.0 million increase in electric generation operating and maintenance expenses, as well as a $3.4 million increase in electric distribution expenses. This was partially offset by the impairment of a turbine in the third quarter of 2007 of $2.3 million.

Utility depreciation and amortization increased $1.8 million primarily due to additions to utility plant.

Non-utility resource costs decreased $45.1 million. This category of expenses decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

The net change in other non-utility operating expenses was a decrease of $2.7 million due to:

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a decrease of $13.2 million in the other businesses due to the sale of Avista Energy’s ongoing operations, partially offset by

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an increase of $10.5 million for Advantage IQ due to expanding operations and the acquisition of Cadence Network in the third quarter of 2008.

Interest expense decreased $5.7 million due to the redemption of all outstanding preferred stock in September 2007 and the effect of long-term debt maturities during 2007 and 2008, which were primarily funded with proceeds from the sale and liquidation of Avista Energy’s assets and the issuance of long-term debt at lower interest rates. This was partially offset by interest expense of $1.4 million related to an income tax settlement.

Interest expense to affiliated trusts decreased $1.2 million due to a decrease in the variable interest rate.

Other income-net decreased $0.6 million primarily due to a decrease in interest income of $4.6 million. The decrease in interest income was primarily due to the disposition of Avista Energy’s ongoing operations. Also contributing to the decrease were losses on long-term venture fund investments. The net decrease was offset by $5.7 million of interest income recorded on the IRS settlement agreement for the 2001 through 2003 tax years and the resulting refund.

Income taxes increased $21.3 million primarily due to increased income before income taxes. Our effective tax rate was 37.9 percent for 2008 compared to 38.6 percent for 2007.

Avista Utilities

2009 compared to 2008

Net income for the utility was $86.7 million for 2009 compared to $70.0 million for 2008. Utility income from operations was $195.4 million for 2009 compared to $174.2 million for 2008. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses, depreciation and amortization and taxes other than income taxes.

AVISTA CORPORATION

The following table presents our operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in thousands):


	Electric				Natural Gas				Total
	2009		2008		2009		2008		2009		2008
Operating revenues	$	840,783	$	838,457	$	554,418	$	734,207	$	1,395,201	$	1,572,664
Resource costs		379,058		425,373		420,481		606,616		799,539		1,031,989

Gross margin	$	461,725	$	413,084	$	133,937	$	127,591	$	595,662	$	540,675

Utility operating revenues decreased $177.5 million and utility resource costs decreased $232.5 million, which resulted in an increase of $55.0 million in gross margin. The gross margin on electric sales increased $48.6 million and the gross margin on natural gas sales increased $6.3 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2009 and Idaho effective October 1, 2008 and August 1, 2009. We had a benefit of $3.0 million under the ERM in 2009 compared to an expense of $7.4 million in 2008, which increased electric gross margin and income from operations by $10.4 million in 2009 as compared to 2008.

The following table presents our utility 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
	2009		2008		2009	2008
Residential	$	315,649	$	279,641	3,791	3,744
Commercial		273,954		247,714	3,177	3,188
Industrial		107,741		101,785	1,948	2,059
Public street and highway lighting		6,607		5,962	26	26

Total retail		703,951		635,102	8,942	9,017
Wholesale		88,414		141,744	2,354	1,964
Sales of fuel		32,992		44,695	—	—
Other		15,426		16,916	—	—

Total	$	840,783	$	838,457	11,296	10,981

Retail electric revenues increased $68.8 million due to an increase in revenue per MWh (increased revenues $74.7 million) primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increases implemented on October 1, 2008 and August 1, 2009, offset by a decrease in total MWhs sold (decreased revenues $5.9 million) primarily due to a decrease in use per customer (commercial and industrial).

Wholesale electric revenues decreased $53.3 million due to a decrease in sales prices (decreased revenues $68.0 million), offset by an increase in sales volumes (increased revenues $14.7 million). The increase in sales volume primarily relates to resource optimization activities.

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel decreased $11.7 million due to a decrease in thermal generation resource optimization activities and lower natural gas prices in 2009 as compared to 2008.

The following table presents our utility 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
	2009		2008		2009	2008
Residential	$	251,022	$	276,386	207,979	210,125
Commercial		135,236		152,147	126,345	128,224
Interruptible		4,709		5,428	5,360	5,758
Industrial		5,236		6,731	5,558	6,438

Total retail		396,203		440,692	345,242	350,545
Wholesale		143,524		281,668	397,977	345,916
Transportation		6,067		6,327	144,580	148,723
Other		8,624		5,520	502	526

Total	$	554,418	$	734,207	888,301	845,710

AVISTA CORPORATION

The $44.5 million decrease in retail natural gas revenues was due to a decrease in volumes (decreased revenues $6.1 million), and lower retail rates (decreased revenues $38.4 million). We sold less retail natural gas in 2009 as compared to 2008, primarily due to warmer weather, as well as a decrease in commercial and industrial use per customer. The decrease in retail rates reflects the purchased gas adjustments implemented in 2009 offset by the Washington general rate increase implemented on January 1, 2009 and Idaho general rate increases implemented on October 1, 2008 and August 1, 2009.

The decrease in our wholesale natural gas revenues of $138.1 million was due to a decrease in prices (decreased revenues $156.9 million), partially offset by an increase in volumes (increased revenues $18.8 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Additionally, we engage in optimization of under-utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

The following table presents our average number of electric and natural gas retail customers for the year ended December 31:


	Electric Customers		Natural Gas Customers
	2009	2008	2009	2008
Residential	313,884	311,381	280,667	277,892
Commercial	39,276	39,075	33,214	32,901
Interruptible	—	—	42	40
Industrial	1,394	1,388	258	257
Public street and highway lighting	444	434	—	—

Total retail customers	354,998	352,278	314,181	311,090

The following table presents our utility resource costs for the year ended December 31 (dollars in thousands):


	2009		2008
Electric resource costs:
Power purchased	$	193,683	$	193,924
Power cost amortizations, net of deferrals		31,102		25,464
Fuel for generation		89,602		134,446
Other fuel costs		31,881		43,103
Other regulatory amortizations, net		19,602		10,490
Other electric resource costs		13,188		17,946

Total electric resource costs		379,058		425,373

Natural gas resource costs:
Natural gas purchased		389,034		579,248
Natural gas cost amortizations, net of deferrals		20,256		20,372
Other regulatory amortizations, net		11,191		6,996

Total natural gas resource costs		420,481		606,616

Total resource costs	$	799,539	$	1,031,989

Power purchased decreased $0.2 million due to a decrease in wholesale prices (decreased costs $35.4 million) offset by an increase in the volume of power purchases (increased costs $35.2 million), primarily due to purchasing power to cover for the outage at Colstrip and an increase in sales volumes related to optimization.

Net amortization of deferred power costs was $31.1 million for 2009 compared to $25.5 million for 2008. During 2009, we recovered (collected as revenue) $31.6 million of previously deferred power costs in Washington and $17.5 million in Idaho. During 2009, we deferred $18.0 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates. We did not defer any power costs in Washington during 2009, as power supply costs were within the $4.0 million deadband below the amount included in base retail rates under the ERM.

Fuel for generation decreased $44.8 million due to a decrease in natural gas fuel prices, as well as a decrease in thermal generation (primarily due to the outage at Colstrip).

Other fuel costs decreased $11.2 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economical to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel.

AVISTA CORPORATION

The increase in other regulatory amortizations of $9.1 million primarily relates to the amortization of costs under demand side management programs.

The expense for natural gas purchased decreased $190.2 million due to a decrease in the price of natural gas (decreased costs $214.7 million), partially offset by an increase in the total therms purchased (increased costs $24.5 million). The increase in total therms purchased was due to an increase in wholesale sales with the balancing of loads and resources as part of the natural gas procurement process, partially offset by a decrease in retail sales volumes. We engage in optimization of under-utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During 2009, we amortized $20.3 million of deferred natural gas costs compared to $20.4 million for 2008.

2008 compared to 2007

Net income for the utility was $70.0 million for 2008 compared to $43.8 million for 2007. Utility income from operations was $174.2 million for 2008 compared to $150.1 million for 2007. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses and depreciation and amortization.

The following table presents our operating revenues, resource costs and resulting gross margin for the year ended December 31 (dollars in thousands):


	Electric				Natural Gas				Total
	2008		2007		2008		2007		2008		2007
Operating revenues	$	838,457	$	711,130	$	734,207	$	577,233	$	1,572,664	$	1,288,363
Resource costs		425,373		322,237		606,616		458,761		1,031,989		780,998

Gross margin	$	413,084	$	388,893	$	127,591	$	118,472	$	540,675	$	507,365

Utility operating revenues increased $284.3 million and utility resource costs increased $251.0 million, which resulted in an increase of $33.3 million in gross margin. The gross margin on electric sales increased $24.2 million and the gross margin on natural gas sales increased $9.1 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2008 and in Idaho effective October 1, 2008. The increase was also partially due to colder weather in 2008, which increased customer usage, during the heating season and customer growth. The Company absorbed $7.4 million of expense under the ERM in 2008, compared to $8.5 million in 2007.

The following table presents our utility 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
	2008		2007		2008	2007
Residential	$	279,641	$	251,357	3,744	3,670
Commercial		247,714		224,179	3,188	3,132
Industrial		101,785		95,207	2,059	2,084
Public street and highway lighting		5,962		5,517	26	26

Total retail		635,102		576,260	9,017	8,912
Wholesale		141,744		105,729	1,964	1,594
Sales of fuel		44,695		12,910	—	—
Other		16,916		16,231	—	—

Total	$	838,457	$	711,130	10,981	10,506

Retail electric revenues increased $58.8 million due to an increase in:

•

total MWhs sold (increased revenues $7.3 million) primarily due to customer growth and an increase in use per customer (primarily due to colder weather), and

•

revenue per MWh (increased revenues $51.5 million) primarily due to the Washington general rate increase implemented on January 1, 2008 and the Idaho general rate increase implemented on October 1, 2008.

Wholesale electric revenues increased $36.0 million due to an increase in sales prices (increased revenues $9.3 million), and an increase in sales volumes (increased revenues $26.7 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel increased $31.8 million due to increased thermal generation resource optimization activities.

AVISTA CORPORATION

The following table presents our utility 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
	2008		2007		2008	2007
Residential	$	276,386	$	264,546	210,125	195,756
Commercial		152,147		148,416	128,224	121,557
Interruptible		5,428		5,040	5,758	5,003
Industrial		6,731		6,244	6,438	5,830

Total retail		440,692		424,246	350,545	328,146
Wholesale		281,668		142,167	345,916	223,084
Transportation		6,327		6,638	148,723	148,765
Other		5,520		4,182	526	438

Total	$	734,207	$	577,233	845,710	700,433

The $16.4 million increase in retail natural gas revenues was due to an increase in volumes (increased revenues $28.1 million), partially offset by lower retail rates (decreased revenues $11.7 million). We sold more retail natural gas in 2008 primarily due to colder weather during the heating season and customer growth. The decrease in retail rates reflects the purchased gas adjustments implemented in the fourth quarter of 2007, partially offset by the Washington general rate increase implemented on January 1, 2008 and Idaho general rate increase implemented on October 1, 2008.

The increase in our wholesale revenues of $139.5 million was due to an increase in prices (increased revenues $39.5 million) and an increase in volumes (increased revenues $100.0 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Additionally, we engage in optimization of under-utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. This activity increased significantly in 2008 as compared to 2007. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

The following table presents our average number of electric and natural gas retail customers for the year ended December 31:


	Electric Customers		Natural Gas Customers
	2008	2007	2008	2007
Residential	311,381	306,737	277,892	273,415
Commercial	39,075	38,488	32,901	32,327
Interruptible	—	—	40	41
Industrial	1,388	1,378	257	261
Public street and highway lighting	434	426	—	—

Total retail customers	352,278	347,029	311,090	306,044

The following table presents our utility resource costs for the year ended December 31 (dollars in thousands):


	2008		2007
Electric resource costs:
Power purchased	$	193,924	$	158,245
Power cost amortizations, net of deferrals		25,464		3,641
Fuel for generation		134,446		125,043
Other fuel costs		43,103		16,454
Other regulatory amortizations, net		10,490		4,437
Other electric resource costs		17,946		14,417

Total electric resource costs		425,373		322,237

Natural gas resource costs:
Natural gas purchased		579,248		433,140
Natural gas cost amortizations, net of deferrals		20,372		16,875
Other regulatory amortizations, net		6,996		8,746

Total natural gas resource costs		606,616		458,761

Total resource costs	$	1,031,989	$	780,998

AVISTA CORPORATION

Power purchased increased $35.7 million due in part to an increase in wholesale prices (increased costs $23.0 million). The increase was also due to an increase in the volume of power purchases (increased costs $12.7 million) primarily due to an increase in sales volumes (due to colder weather, customer growth and optimization).

Net amortization of deferred power costs was $25.5 million for 2008 compared to $3.6 million for 2007. During 2008, we recovered (collected as revenue) $30.9 million of previously deferred power costs in Washington and $11.7 million in Idaho. During 2008, we deferred $7.0 million of power costs in Washington and $10.0 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation increased $9.4 million due to an increase in thermal generation volumes and an increase in fuel prices.

Other fuel costs increased $26.6 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economic to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel. Other fuel costs were less than the revenues we received from selling the natural gas. We account for this difference under the ERM in Washington and the PCA in Idaho. The increase in other fuel costs was primarily due to increased thermal generation resource optimization activities and increased fuel prices.

Other regulatory amortizations increased $6.1 million primarily due to amortization of demand side management program expenses.

The expense for natural gas purchased increased $146.1 million due to an increase in total therms purchased and the price of natural gas. The increase in total therms purchased was due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process and an increase in retail sales volumes. We engage in optimization of under-utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. This activity increased significantly in 2008 as compared to 2007. During 2008, we amortized $20.4 million of deferred natural gas costs compared to $16.9 million for 2007.

Advantage IQ

2009 compared to 2008

Advantage IQ’s net income attributable to Avista Corporation was $5.3 million for 2009 compared to $6.1 million for 2008. Operating revenues increased $18.2 million and operating expenses increased $17.9 million. The increase in operating revenues and expenses was primarily due to the third quarter 2008 acquisition of Cadence Network and the third quarter 2009 acquisition of Ecos, as well as increased revenues from other customer billing services. These increases in operating revenues were partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). The increase in operating expenses was also due to the amortization of intangible assets from the acquisitions. As of December 31, 2009, Advantage IQ had 532 customers representing 421,000 billed sites in North America. In 2009, Advantage IQ managed bills totaling $17.4 billion, an increase of $0.7 billion, or 4 percent, as compared to 2008. The acquisition of Cadence Network added $1.7 billion in processed bills for 2009 as compared to 2008.

2008 compared to 2007

Advantage IQ’s net income attributable to Avista Corporation was $6.1 million for 2008 compared to $6.7 million for 2007. Operating revenues increased $11.8 million and operating expenses increased $11.5 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base and the third quarter acquisition of Cadence Network, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). As of December 31, 2008, Advantage IQ had 537 customers representing 417,000 billed sites in North America, a significant increase from the end of 2007 primarily due to the acquisition of Cadence Network. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base, as well as the third quarter acquisition of Cadence Network (including the amortization of intangible assets). In 2008, Advantage IQ processed bills totaling $16.7 billion, an increase of $4.2 billion, or 34 percent, as compared to 2007. The acquisition of Cadence Network (in July 2008) added $2.1 billion in processed bills for 2008 as compared to 2007.

Other Businesses

2009 compared to 2008

The net loss attributable to Avista Corporation from these operations was $5.0 million for 2009 compared to $2.5 million for 2008. Operating revenues decreased $4.9 million and operating expenses increased $0.8 million. The decrease in operating revenues was primarily due to a reduction in sales at AM&D. The increase in operating

AVISTA CORPORATION

expenses reflects the impairment of a commercial building of $3.0 million and increased litigation costs related to the remaining contracts and previous operations of Avista Energy, partially offset by decreased operating costs from AM&D. Losses on long-term venture fund investments were $0.8 million in 2009 compared to $1.4 million in 2008. AM&D had net income of $0.2 million for 2009 compared to $0.5 million for 2008.

2008 compared to 2007

The net loss attributable to Avista Corporation from these operations was $2.5 million for 2008 compared to $12.0 million for 2007. Operating revenues decreased $37.1 million and operating expenses decreased $59.1 million. Contributing to the net loss attributable to Avista Corporation in 2008 was losses on long-term venture fund investments and litigation costs. The net loss attributable to Avista Corporation for 2007 and the decrease in operating revenues and expenses were primarily due to the sale of Avista Energy in 2007.

Accounting Standards to Be Adopted in 2010

We will be adopting the following accounting standards in 2010, which could have an impact on our financial condition, results of operations and cash flows. For information on accounting standards adopted in 2009 and earlier periods, refer to “Note 2 of the Notes to Consolidated Financial Statements.”

In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets an amendment of FASB Statement No. 140” (Accounting Standards Codification (ASC) 860). This statement amends certain provisions of SFAS No. 140 (ASC 860) related to accounting for transfers of financial assets and a transferor’s continuing involvement in transferred financial assets. We are required to adopt this statement effective January 1, 2010. We are evaluating the impact this statement will have on our financial condition, results of operations and cash flows. In particular, we are evaluating our accounts receivable sales to determine whether or not the transactions meet the criteria of sales of financial assets. If the transactions did not meet the criteria, the transactions would be accounted for as secured borrowings. As of December 31, 2009, we had not sold any accounts receivable under the revolving agreement. We will finalize our evaluation during the first quarter of 2010 to determine the impact of adoption, if any, on our financial condition, results of operations and cash flows.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (ASC 810). This Statement carries forward the scope of FASB Interpretation No. 46(R) (ASC 810), with the addition of entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated in SFAS No. 166 (ASC 860). The amendments will significantly affect the overall consolidation analysis of variable interest entities (VIE). The amendments will require us to reconsider previous conclusions relating to the consolidation of VIEs, including whether an entity is a VIE, whether we are the VIE’s primary beneficiary, and what type of financial statement disclosures are required. We are required to adopt this statement effective January 1, 2010. We are evaluating the impact this statement will have on our financial condition, results of operations and cash flows. In particular, we are evaluating the potential consolidation of Spokane Energy LLC (see disclosure at “Spokane Energy LLC”). This would add approximately $85 million of assets and liabilities (consisting primarily of a long-term contract receivable and non-recourse debt) to the Consolidated Balance Sheet, with no material effect on our results of operations. In addition, we are evaluating certain long-term power purchase contracts under this guidance. We will finalize our evaluation during the first quarter of 2010 to determine the impact of adoption, if any, on our financial condition, results of operations and cash flows.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us 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 our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. The following accounting policies represent those that our 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 our utility related to the sale of energy are generally recorded when service is rendered or energy is delivered to our customers. The determination of 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, we estimate the amount of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue is estimated and recorded.

AVISTA CORPORATION

Our estimate of unbilled revenue is based on:

•

the number of customers,

•

current rates,

•

meter reading dates,

•

actual native load for electricity, and

•

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

We prepare our consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (ASC 980) for our regulated utility operations. ASC 980 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) be reflected as deferred charges on our Consolidated Balance Sheets and are not reflected in our Consolidated Statements of Income until the period during which matching revenues are recognized. We expect to recover our regulatory assets through future rates. Our regulatory assets are subject to review for prudence and recoverability. As such, certain deferred costs may be disallowed by our regulators. If at some point in the future we determine that we no longer meet the criteria for continued application of ASC 980 for all or a portion of our regulated operations, we could be:

•

required to write off regulatory assets, and

•

precluded from the future deferral of costs not recovered through rates when such costs are incurred, even if we expect to recover such costs in the future.

Utility Energy Commodity Derivative Assets and Liabilities

Our utility 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 our management of loads and resources and certain contracts are considered derivative instruments. The WUTC and the IPUC issued accounting orders authorizing us to offset commodity 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 us 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 in Washington, the PCA mechanism in Idaho, and periodic general rates cases. We use quoted market prices and forward price curves to estimate the fair value of our utility derivative commodity instruments. As such, the fair value of utility derivative commodity instruments recorded on our Consolidated Balance Sheets is sensitive to market price fluctuations that can occur on a daily basis.

Pension Plans and Other Postretirement Benefit Plans

We have a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities.

Our Finance Committee of the Board of Directors:

•

establishes investment policies, objectives and strategies that seek an appropriate return for the pension plan, and

•

reviews and approves changes to the investment and funding policies.

We have contracted with an investment consultant who is responsible for managing/monitoring the individual investment managers. The investment managers’ performance and related individual fund performance is reviewed at least quarterly by an internal benefits committee and by the Finance Committee to monitor compliance with our established investment policy objectives and strategies.

Our pension plan assets are invested primarily in marketable debt and equity securities. Pension plan assets may also be invested in real estate, absolute return, venture capital/private equity and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established investment allocation percentages by asset classes as disclosed in “Note 11 of the Notes to Consolidated Financial Statements.”

We also have a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to our 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.

AVISTA CORPORATION

Pension costs (including the SERP) were $25.8 million for 2009, $13.9 million for 2008 and $14.3 million for 2007. Of our pension costs, approximately 65 percent are expensed and 35 percent are capitalized consistent with labor charges. The costs related to the SERP are expensed. Our costs for the pension plan are determined in part by actuarial formulas that are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension costs are affected by:

•

employee demographics (including age, compensation and length of service by employees),

•

the amount of cash contributions we make to the pension plan, and

•

the return on pension plan assets.

Changes made to the provisions of our 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,

•

discount rate used in determining the projected benefit obligation and pension costs, and

•

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 our Consolidated Statement of Income, but we generally recognize the change in future years over the remaining average service period of pension plan participants. As such, our costs recorded in any period may not reflect the actual level of cash benefits provided to pension plan participants.

In 2009, the Company reviewed the mortality table utilized in the actuarial calculations. The Company determined that the RP-2000 combined healthy mortality tables for males and females should be replaced with the RP-2000 combined healthy mortality tables for males and females projected to 2010 using scale AA. The change resulted in an increase of $6.6 million to the pension benefit obligation as of December 31, 2009.

In 2008, the rates at which participants are assumed to retire by age were analyzed based upon historical trends and future projections. We revised the rates to assume that a greater percentage of participants would retire between the ages of 55 and 65. The assumed rates were revised to range from 5 percent to 40 percent and 100 percent at age 65. The previous rates ranged from 2 percent to 30 percent and 100 percent at age 65. The change resulted in an increase of $11.0 million to the pension benefit obligation as of December 31, 2008. The changes will also increase future years’ pension costs.

We have not made any changes to pension plan provisions in 2009, 2008 and 2007 that have had any significant effect on our recorded pension plan amounts. We have revised the key assumption of the discount rate in 2009, 2008 and 2007. Such changes had an effect on our pension costs in 2009, 2008 and 2007 and may affect future years, given the cost recognition approach described above. However, in determining pension obligation and cost amounts, our assumptions can change from period to period, and such changes could result in material changes to our future pension costs and funding requirements.

In selecting a discount rate, we consider yield rates for highly rated corporate bond portfolios with maturities similar to that of the expected term of pension benefits. We increased the pension plan discount rate from 6.25 percent in 2008 to 6.30 percent in 2009. In 2007 we used the 6.35 percent rate for estimating our benefit obligation.

The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by our plan. The expected long-term rate of return was 8.5 percent in each of 2009, 2008 and 2007. The actual return on plan assets, net of fees, was a gain of $50.1 million (or 24.4 percent) for 2009, a loss of $63.2 million (or -25.5 percent) for 2008 and a gain of $18.3 million (or 8.1 percent) for 2007. We periodically analyze the estimated long-term rate of return on assets based upon revisions to the investment portfolio.

Effective January 1, 2010, we decreased the expected long-term rate of return on plan assets from 8.5 percent to 7.75 percent. This will increase pension cost in 2010 by approximately $2.0 million. Of our pension costs, approximately 65 percent are expensed and 35 percent are capitalized consistent with labor charges.

AVISTA CORPORATION

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 Cost
Expected long-term return on plan assets	-0.5	%	$	—	*	$	1,036
Expected long-term return on plan assets	+0.5	%		—	*		(1,036	)
Discount rate	-0.5	%		23,677			2,287
Discount rate	+0.5	%		(21,353	)		(2,081	)

*	Changes in the expected return on plan assets would not have an effect on our total pension liability.

We provide certain health care and life insurance benefits for substantially all of our retired employees. We accrue the estimated cost of postretirement benefit obligations during the years that employees provide service. Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase our accumulated postretirement benefit obligation as of December 31, 2009 by $2.1 million and the service and interest cost by $0.2 million. A one-percentage-point decrease in the assumed health care cost trend rate for each year would decrease our accumulated postretirement benefit obligation as of December 31, 2009 by $1.9 million and the service and interest cost by $0.2 million.

Stock-Based Compensation

We recognize compensation costs relating to share-based payment transactions in our Consolidated Statements of Income based on the fair value of the equity or liability instruments issued. The fair value of each performance share award was estimated on the date of grant using a statistical model that incorporates the probability of meeting performance targets based on historical returns relative to a peer group. Expected volatility is based on the historical volatility of our common stock over a three-year period. The expected term of the performance shares is three years based on the performance cycle. The risk-free interest rate is based on the U.S. Treasury yield at the time of grant.

Contingencies

We have unresolved regulatory, legal and tax issues for which there is inherent uncertainty for the ultimate outcome of the respective matter. We accrue a loss contingency if it is probable that an asset is impaired or a liability has been incurred and the amount of the loss or impairment can be reasonably estimated. We also disclose losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be incurred.

For all material contingencies, we have made a judgment as to the probability of a loss occurring and as to whether or not the amount of the loss can be reasonably estimated. If the loss recognition criteria are met, liabilities are accrued or assets are reduced. However, no assurance can be given for the ultimate outcome of any particular contingency.

AVISTA CORPORATION

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During 2009, positive cash flows from operating activities of $258.8 million and proceeds from the issuance of long-term debt of $249.4 million were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $205.4 million, a net decrease (net repayment) in short-term borrowings of $159.5 million, redemption of long-term debt to affiliated trusts of $61.9 million and dividends of $44.4 million.

Operating Activities Net cash provided by operating activities was $258.8 million for 2009 compared to $115.4 million for 2008. Net cash provided by working capital components was $31.0 million for 2009, compared to cash used of $113.8 million for 2008. The net cash provided during 2009 primarily reflects an increase in cash flows from:

•

accounts receivable (representing a decrease in the receivables outstanding largely due to a decrease in wholesale prices, partially offset by a $17.0 million decrease in the amount of receivables that were sold),

•

other current liabilities, and

•

materials and supplies, fuel stock and natural gas stored (primarily reflecting a change in the price of natural gas stored).

This cash provided was partially offset by negative cash flows from accounts payable (primarily related to a decrease in the accounts payable for natural gas purchases due to a decrease in prices).

The net cash used during 2008 primarily reflects a decrease in cash flows from:

•

accounts receivable (representing an increase in the receivables outstanding and a $68.0 million decrease in the amount of receivables that were sold),

•

deposits from counterparties (representing the return to counterparties of cash posted as collateral at Avista Utilities), and

•

materials and supplies, fuel stock and natural gas stored (primarily representing an increase in natural gas that was stored).

This cash used in 2008 was partially offset by positive cash flows from accounts payable (representing an increase in accounts payable).

Significant non-cash items included $51.4 million of power and natural gas cost amortizations, net of deferrals, for 2009, an increase from $45.8 million for 2008. We also had deferred income tax expense of $13.9 million for 2009 compared to $44.2 million for 2008. Contributions to our defined benefit pension plan were $48.0 million for 2009 compared to $28.0 million for 2008. Income tax payments were $22.7 million in 2009, an increase compared to $10.0 million for 2008. Cash paid for interest decreased to $58.8 million for 2009, compared to $76.6 million in 2008.

Investing Activities Net cash used in investing activities was $215.6 million for 2009, an increase compared to $185.3 million for 2008. Utility property capital expenditures decreased for 2009 as compared to 2008, and funds held from customers at Advantage IQ decreased by $8.5 million.

Financing Activities Net cash used in financing activities was $30.5 million for 2009 compared to net cash provided of $82.4 million for 2008. In September 2009, we issued $250.0 million (net proceeds of $249.4 million) of long-term debt. In conjunction with the issuance of long-term debt, we cash settled interest rate swap agreements and received a total of $10.8 million. In April 2009, we redeemed $61.9 million of long-term debt to affiliated trusts. In December 2009, we purchased $17.0 million of our Pollution Control Bonds, which we are holding as bondholder. During 2009, our short-term borrowings decreased $159.5 million due to a net decrease of $163.0 million in the amount of debt outstanding under our $320.0 million committed line of credit, partially offset by a $3.5 million net increase in the amount borrowed under Advantage IQ’s credit agreement. Cash dividends paid increased to $44.4 million (or 81 cents per share) for 2009 from $37.1 million (or 69 cents per share) for 2008. Additionally, customer funds obligations at Advantage IQ decreased by $8.5 million.

During 2008, our short-term borrowings increased $252.2 million, which reflected a net increase in the amount of debt outstanding under our $320.0 million committed line of credit. Net proceeds from long-term debt issuances were $296.2 million in 2008 and common stock issuances were $28.6 million for 2008 (primarily $16.6 million from the issuance of 750,000 shares of common stock under a sales agency agreement). Debt maturities were $403.9 million and cash paid to settle interest rate swaps was $16.4 million in 2008. Additionally, customer funds obligations at Advantage IQ decreased by $30.8 million.

Overall Liquidity

Our consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for our utility operations is revenues from sales of electricity and natural gas.

AVISTA CORPORATION

Significant uses of cash flows from our utility operations include the purchase of electricity and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.

We design operating and capital budgets to control operating costs and optimize capital expenditures, particularly for our regulated utility operations. In addition to operating expenses, we have continuing commitments for capital expenditures for construction, improvement and maintenance of utility facilities.

Over time, our operating cash flows usually do not fully support the amount required for utility capital expenditures. As such, from time to time, we need to access capital markets in order to fund these needs as well as fund maturing debt. See further discussion at “Capital Resources.”

We periodically file for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align our earned returns with those allowed by regulators. Effective January 1, 2009, the WUTC authorized an increase in our rates in Washington designed to increase annual electric revenues by $32.5 million and annual natural gas revenues by $4.8 million. Effective August 1, 2009, the IPUC authorized an increase in our electric rates in Idaho designed to increase annual electric revenues by $12.5 million. Offsetting the electric revenue increase was an overall decrease in the current PCA surcharge, which is designed to decrease annual electric revenues by $9.3 million. Effective August 1, 2009, the IPUC authorized an increase in our natural gas rates in Idaho designed to increase annual revenues by $1.9 million. Offsetting the natural gas rate increase was an overall PGA decrease resulting in a $2.0 million decrease in annual revenues. Effective January 1, 2010, the WUTC authorized an increase in our rates in Washington designed to increase annual electric revenues by $12.1 million and annual natural gas revenues by $0.6 million. In addition, PGA decreases were implemented in all of our jurisdictions and a general rate increase was implemented in Oregon effective November 1, 2009. See further details in the section “Avista Utilities - Regulatory Matters.”

For our utility operations, when power and natural gas costs exceed the levels currently recovered from retail customers, net cash flows are negatively affected. Factors that could cause purchased power costs to exceed the levels currently recovered from our customers include, but are not limited to, higher prices in wholesale markets when we buy energy or an increased need to purchase power in the wholesale markets. Factors beyond our 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,

•

unplanned outages at generating facilities, and

•

failure of third parties to deliver on energy or capacity contracts.

We monitor the potential liquidity impacts of increasing energy commodity prices and other increased operating costs for our utility operations. We believe that we have adequate liquidity to meet the increased cash needs of higher energy commodity prices and other increased operating costs through our:

•

$320.0 million committed line of credit (which expires in April 2011),

•

$75.0 million committed line of credit (which expires in April 2011), and

•

$85.0 million revolving accounts receivable sales facility (which expires in March 2010).

As of December 31, 2009, we had a combined $364.6 million of available liquidity under the three facilities described above.

Our utility has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices rise above the level currently allowed in retail rates in periods when we are buying energy, deferral balances will increase, which will negatively affect our cash flow and liquidity until such costs, with interest, are recovered from customers.

Credit and Nonperformance Risk

Our contracts for the purchase and sale of energy commodities often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement in the event of a downgrade in our credit ratings or adverse changes in market prices. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below investment grade and energy prices decreased by 15 percent in the first year and 20 percent in subsequent years, we estimate, based on our positions outstanding at December 31, 2009, that we would potentially be required to post additional collateral up to $39 million. The additional collateral amount is higher than the amount disclosed in Note 7 of the Notes to Consolidated Financial Statements because this analysis includes contracts that are not considered derivatives and due to the assumptions about potential energy price changes.

AVISTA CORPORATION

Under the terms of interest rate swap agreements that we enter into periodically, we may be required to post cash collateral depending on fluctuations in the fair value of the instrument. This has not historically been significant to our liquidity position. As of December 31, 2009, we did not have any interest rate swap agreements outstanding.

Our utility held cash deposits from other parties in the amount of $3.2 million as of December 31, 2009 and $0.2 million as of December 31, 2008. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

In December 2009, the U.S. House of Representatives passed the Wall Street Reform and Consumer Protection Act of 2009 (the House Bill) which would establish regulatory jurisdiction by the Commodity Futures Trading Commission (CFTC) for certain swaps (which includes a variety of derivative instruments) and the users of such swaps. Under the House Bill, “major swap participants” would be required to register with the CFTC and, among other things, maintain minimum capital and margin requirements. “Major swap participants” would include entities with large swap positions, excluding swaps held primarily for hedging commercial risk. Since we use derivative instruments primarily for hedging commercial risks, it is unlikely that we would be subject to the proposed CFTC regulation.

The House Bill would also require a broad category of swaps to be cleared and traded on registered exchanges or special derivatives exchanges. Such clearing requirements could impose a significant change from our current practices of bilateral transactions and negotiated credit terms. Clearing requirements could involve greater liquidity as collateral. However, there would be an exemption, available on an individual basis, for an end user that is not a major swap participant, and we believe we would qualify for such an exemption. Although the House Bill may not have a material direct adverse effect on us, concern remains that our counterparties who are not exempt would pass along increased costs and margin requirements through higher prices and reductions in unsecured credit limits. In addition, there can be no assurance that any final legislation affecting derivatives, if enacted, would retain the exemptions contained in the House Bill.

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, and excluding noncontrolling interests, consisted of the following as of December 31, 2009 and 2008 (dollars in thousands):


	December 31, 2009				December 31, 2008
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	35,189	1.5	%	$	17,207	0.8	%
Short-term borrowings (1)		92,700	4.1			252,200	11.5
Long-term debt to affiliated trusts (2)		51,547	2.3			113,403	5.2
Long-term debt (1)		1,036,149	45.7			809,258	37.0

Total debt		1,215,585	53.6			1,192,068	54.5
Total Avista Corporation stockholders’ equity		1,051,287	46.4			996,883	45.5

Total	$	2,266,872	100.0	%	$	2,188,951	100.0	%

(1)

(2)

On April 1, 2009, we redeemed the total amount outstanding ($61.9 million) of our 6.5 percent Junior Subordinated Debt Securities held by AVA Capital Trust III (Long-term Debt to Affiliated Trusts). Concurrently, AVA Capital Trust III redeemed all of the Preferred Trust Securities issued to third parties ($60.0 million) and all of the Common Trust Securities issued to us ($1.9 million). The net redemption of $60.0 million was funded by borrowings under our $320.0 million committed line of credit agreement.

We need to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund capital expenditures, working capital, purchased power and natural gas costs, dividends and other requirements. Our stockholders’ equity increased $54.4 million during 2009 primarily due to net income, partially offset by dividends.

We generally fund 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 our utility operating activities is expected to be the primary source of funds for

AVISTA CORPORATION

operating needs, dividends and capital expenditures for 2010. Borrowings under our $320.0 million committed line of credit, $75.0 million committed line of credit and sales of accounts receivable under our $85.0 million revolving facility will supplement these funds to the extent necessary.

We have $35.0 million of scheduled long-term debt maturities in 2010. In December 2009, we purchased $17.0 million of our Pollution Control Bonds. We are planning, subject to market conditions, to refund these bonds in 2010 along with $66.7 million of our Pollution Control Bonds we purchased in December 2008.

We are planning to issue up to $45 million of common stock in 2010 in order to maintain our capital structure at an appropriate level for our business.

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 2011. Under the credit agreement, we can borrow or request the issuance of letters of credit in any combination up to $320.0 million. As of December 31, 2009, we had $87.0 million in borrowings outstanding under this committed line of credit, a decrease from $250.0 million in borrowings outstanding as of December 31, 2008. As of December 31, 2009, there were $28.4 million in letters of credit outstanding, an increase from $24.3 million as of December 31, 2008. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds 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 we default on obligations under the committed line of credit.

Additionally, in November 2009, we entered into a new committed line of credit in the total amount of $75.0 million with an expiration date of April 2011. The new committed line of credit replaced a $200.0 million committed line of credit that expired in November 2009. We reduced the facility based on our forecasted liquidity needs. As of December 31, 2009, we did not have any borrowings outstanding under this committed line of credit. The committed line of credit is secured by $75.0 million of non-transferable First Mortgage Bonds 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 we default on obligations under the committed line of credit.

Our committed line of credit agreements contain customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of December 31, 2009, we were in compliance with this covenant with a ratio of 4.23 to 1. The committed line of credit agreements also have a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 70 percent at any time. As of December 31, 2009, we were in compliance with this covenant with a ratio of 53.6 percent.

Any default on the line of credit or other financing arrangements of Avista Corp. or any of our significant subsidiaries could result in cross-defaults to other agreements of such entity, and/or to the line of credit or other financing arrangements of any other of such entities. Any defaults could also induce vendors and other counterparties to demand collateral. In the event of any such default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock. We do not guarantee the indebtedness of any of our subsidiaries. As of December 31, 2009, Avista Corp. and our subsidiaries were in compliance with all of the covenants of our financing agreements.

We are restricted under our Restated Articles of Incorporation as to the additional preferred stock we can issue. As of December 31, 2009, we could issue $611.0 million of additional preferred stock at an assumed dividend rate of 9.5 percent. We are not planning to issue preferred stock.

Under the Mortgage and Deed of Trust securing our First Mortgage Bonds (including Secured Medium-Term Notes), we may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of:

•

70 percent of the cost or fair value (whichever is lower) of property additions which have not previously been made the basis of any application under the Mortgage, or

•

an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any application under the Mortgage; or

•

deposit of cash.

provided, however, that we may not issue any additional First Mortgage Bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless our “net earnings” (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all indebtedness of prior rank. As of December 31, 2009, our property additions and retired bonds would have entitled us to issue $668.5 million in aggregate principal amount of additional First Mortgage Bonds. However, using an interest rate of 8 percent on additional First Mortgage Bonds, and based on net earnings for the 12 months ended December 31, 2009, the net earnings test would limit the principal amount of additional bonds we could issue to $607.5 million. We believe that we have adequate capacity to issue First Mortgage Bonds to meet our financing needs over the next several years.

AVISTA CORPORATION

Avista Utilities Capital Expenditures

Capital expenditures for our utility were $630.4 million for the years 2007 through 2009. We expect utility capital expenditures to be over $210 million for each of 2010, 2011 and 2012. In addition to ongoing needs for our distribution system, significant projects include upgrades to generating facilities. These estimates of capital expenditures are subject to continuing review and adjustment and do not include costs for projects associated with stimulus funding (see discussion below). Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

We are committed to investment in generation, transmission and distribution systems with a focus on increasing capacity and maintaining or improving reliability. We continue to upgrade hydroelectric plants to maintain reliable operations and improve output.

The American Recovery and Reinvestment Act (the ARRA) of 2009 includes almost $80 billion of stimulus funding in areas that have some relation to electric and natural gas utilities, such as Avista Corp. We applied to the Smart Grid Investment Grant program under the ARRA, proposing a 50 percent cost share for the deployment of smart grid enabling technologies in the Spokane area. The total project costs are estimated to be $42 million, which will be spent over a three-year period. In October 2009, we were one of 100 utilities selected to negotiate a grant under this stimulus program. The grant will be for $20 million and our contribution will be $22 million. We are working with the Department of Energy to finalize the grant in early 2010.

In August 2009, we applied with Battelle Northwest to participate in a Smart Grid Demonstration Project in Pullman, Washington under the ARRA. In November 2009, this project was selected by the Department of Energy for a grant, which it will negotiate with us and the other partners to reach a funding agreement. The Smart Grid Demonstration Project will partner with other regional utilities and proposes a 50 percent cost share for a group of projects. Our portion of the regional demonstration project is estimated to cost $16 million. The Smart Grid Demonstration Project will spend the funds over the course of five years.

We are subject to Washington state renewable energy portfolio standards and must obtain a portion of our electricity from qualifying renewable resources or through purchase of renewable energy credits. Our 2009 Integrated Resource Plan (IRP) identified that additional qualifying renewable energy is needed by 2016 and that new capacity and energy resources are needed by 2018. Based on resource acquisition goals identified in the 2009 IRP, we evaluated proposals from suppliers to provide us with up to 35 average megawatts (which equates to approximately 105 MW of wind power) of long-term qualified renewable energy by the end of 2012.

Future generation resource decisions may be further impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements as discussed at “Environmental Issues and Other Contingencies.”

We are participating in planning activities for the development of a proposed 3,000 MW transmission project that would extend from British Columbia, Canada to Northern California. Other participants include Pacific Gas and Electric Company and British Columbia Transmission Corporation. We have executed an agreement (stage one agreement) with the other participants in order to perform preliminary studies and assessments for the project, including electrical system studies and resource mapping of possible transmission line corridors. Under the stage one agreement, we have committed to contribute $0.6 million. The participants are working on a stage two agreement for the project that is expected to be completed in the second quarter of 2010, which, among other things, will determine our financial obligation and participation in the project. The stakeholders continue to have discussions to explore whether, in light of changing circumstances for other project participants, this project, a different version of this project or another transmission project in the region should be pursued.

AVISTA CORPORATION

Advantage IQ Credit Agreement

Advantage IQ has a committed credit agreement with an expiration date of February 2011. In July 2009, the committed amount was increased from $12.5 million to $15.0 million under the terms of the credit agreement. Advantage IQ may elect to increase the credit facility to $25.0 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $5.7 million of borrowings outstanding under the credit agreement as of December 31, 2009, compared to $2.2 million as of December 31, 2008. The increase in the amount borrowed primarily reflects the funding of the Ecos acquisition, partially offset by repayments.

Advantage IQ Operations

We do not expect capital expenditures for the years 2010 through 2012 for Advantage IQ to be significant to our consolidated cash flows and financial condition. These capital expenditures are expected to be funded by Advantage IQ’s cash flows from operations.

In 2007, Advantage IQ amended its employee stock incentive plan to provide an annual window at which time holders of common stock can put their shares back to Advantage IQ providing the shares are held for a minimum of six months. Stock is reacquired at fair market value at the date of reacquisition. This plan was amended to provide liquidity to participants of Advantage IQ’s stock option plan. As the repurchase feature is at the discretion of the minority shareholders and option holders, there was redeemable noncontrolling interests of $6.9 million as of December 31, 2009 for the intrinsic value of stock options outstanding, as well as outstanding redeemable stock. Additionally, there was redeemable noncontrolling interests of $27.9 million related to the Cadence Network acquisition, as the previous owners can exercise a right to put their stock back to Advantage IQ (refer to Note 5 of the Notes to Consolidated Financial Statements for further information). During 2009, $4.7 million of common stock was repurchased from Advantage IQ employees. In 2009, the Advantage IQ employee stock incentive plan was amended such that, on a prospective basis, not all options granted under the plan will have the annual put window.

Off-Balance Sheet Arrangements

Avista Receivables Corporation (ARC) is our wholly owned, bankruptcy-remote subsidiary formed for the purpose of acquiring or purchasing interests in certain of our accounts receivable, both billed and unbilled. On March 13, 2009, Avista Corp., ARC and Bank of America, N.A. amended a Receivables Purchase Agreement. The most significant amendment was to extend the termination date from March 13, 2009 to March 12, 2010. The Receivables Purchase Agreement was originally entered into on May 29, 2002 and provides us with cost-effective funds for:

•

working capital requirements,

•

capital expenditures, and

•

other general corporate needs.

Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of our 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. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of our committed line of credit agreements. As of December 31, 2009, we had the ability to sell up to $85.0 million of receivables (based on calculations of our eligible accounts receivable) and there were not any accounts receivable sold under this revolving agreement. We expect to renew this facility before the March 12, 2010 expiration.

We are evaluating accounts receivable sales under SFAS No. 166, which amends ASC 860, to determine whether or not the transactions meet the criteria of sales of financial assets. If the transactions did not meet the criteria, the transactions would be accounted for as secured borrowings.

As of December 31, 2009, we had $28.4 million in letters of credit outstanding under our $320.0 million committed line of credit, an increase from $24.3 million as of December 31, 2008.

Spokane Energy, LLC

In December 1998, we received cash proceeds of $143.4 million from a transaction in which we 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 the IPUC, we fully amortized this amount by the end of 2002.

Under this power exchange arrangement, Peaker, LLC (Peaker) purchases capacity from our utility and sells capacity to Spokane Energy LLC (Spokane Energy), our unconsolidated subsidiary 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

AVISTA CORPORATION

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 $70.3 million as of December 31, 2009) that matures in January 2015. Avista Corp. has no recourse related to this loan. Peaker makes monthly payments (which are not material to our financial statements) to Avista Corp. for its capacity purchase.

We are currently evaluating Spokane Energy under the provision of SFAS No. 167, which amends ASC 810. This could result in the consolidation of Spokane Energy beginning in 2010. The consolidation of Spokane Energy would add approximately $85 million of assets and liabilities (consisting primarily of a long-term contract receivable and non-recourse debt) to the Consolidated Balance Sheet, with no material effect on our results of operations.

Credit Ratings

The following table summarizes our credit ratings as of February 26, 2010:


	Standard & Poor’s (1)	Moody’s (2)	Fitch, Inc. (3)

Avista Corporation
Corporate/Issuer rating	BBB-	Baa3	BBB-
Senior secured debt (4)	BBB+	Baa1	BBB+
Senior unsecured debt	N/A (7)	Baa3	BBB
Avista Capital II (5)
Preferred Trust Securities	BB	Ba1	BB+ (8)
Rating outlook (6)	Positive	Positive	Stable

(1)	Ratings were upgraded in February 2008.

(2)	Ratings were upgraded in December 2007, and the senior secured debt rating was further upgraded to Baa1 from Baa2 in August 2009.

(3)	Ratings were upgraded in May 2009.

(4)

Based on our understanding of the methodology currently used by Standard & Poor’s, the rating on senior secured debt may depend on, among other things, the amount of our utility property (net of depreciation) relative to the amount of such debt outstanding and the amount currently issuable. Thus, the rating on senior secured debt as of any particular time may depend on factors affecting our utility property accounts, as well as factors affecting the principal amount of such debt issued and issuable, including factors affecting our net income.

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

(6)	Rating outlook for Standard & Poor’s and Moody’s was changed to “Positive” from “Stable” in August 2009.

(7)	Standard & Poor’s has not assigned a rating to our senior unsecured debt. We do not have any senior unsecured debt outstanding.

(8)	Rating outlook on these securities was changed to BB+ from BBB- in January 2010. Downgrade was a result of a corporate-wide change in methodology for Fitch, Inc. related to the rating of preferred trust securities.

A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

Pension Plan

As of December 31, 2009, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. Due to market conditions and the decline in the fair value of pension plan assets in 2008, we contributed $48 million to the pension plan in 2009. We contributed $28 million to the pension plan in 2008 and $15 million in both 2006 and 2007. In 2009, the fair value of pension plan assets increased. We expect that our contribution for 2010 will be $21 million. The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation).

Dividends

The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:

•

our results of operations, cash flows and financial condition,

•

the success of our business strategies, and

•

general economic and competitive conditions.

AVISTA CORPORATION

Our net income available for dividends is primarily derived from our regulated utility operations.

The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock contained in our Restated Articles of Incorporation, as amended.

In February 2010, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.25 per share on the Company’s common stock.

Contractual Obligations

The following table provides a summary of our future contractual obligations as of December 31, 2009 (dollars in millions):


	2010		2011		2012		2013		2014		Thereafter
Avista Utilities:
Long-term debt maturities	$	35	$	—	$	7	$	75	$	—	$	955
Long-term debt to affiliated trusts		—		—		—		—		—		52
Interest payments on long-term debt (1)		63		61		61		60		56		615
Short-term borrowings		87		—		—		—		—		—
Energy purchase contracts (2)		367		227		167		124		115		918
Public Utility District contracts (2)		3		3		3		2		2		31
Operating lease obligations (3)		1		1		1		1		1		3
Other obligations (4)		51		55		48		52		53		574
Information services contracts		13		13		12		—		—		—
Pension plan funding (5)		21		21		21		21		21		—
Avista Capital (consolidated):
Long-term debt		—		—		—		—		—		2
Short-term debt		6		—		—		—		—		—
Redeemable noncontrolling interests (6)		7		28		—		—		—		—
Venture funds investments (7)		2		2		1		—		—		—
Operating lease obligations (3)		3		3		3		2		2		4

Total contractual obligations	$	659	$	414	$	324	$	337	$	250	$	3,154

(1)	Represents our estimate of interest payments on long-term debt, which is calculated based on the assumption that all debt is outstanding until maturity. Interest on variable rate debt is calculated using the rate in effect at December 31, 2009.

(2)

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

(3)	Includes the interest component of the lease obligation. Future capital lease obligations are not material.

(4)	Represents operational agreements, settlements and other contractual obligations for our generation, transmission and distribution facilities. These costs are generally recovered through base retail rates.

(5)	Represents our estimated cash contributions to the pension plan through 2014. We cannot reasonably estimate pension plan contributions beyond 2014 at this time.

(6)

Under the transaction agreement, the previous owners of Cadence Network can exercise a right to have their shares of Advantage IQ common stock redeemed during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties. In addition, certain shares acquired under Advantage IQ’s employee stock incentive plan are redeemable at the option of the shareholder.

(7)	Represents our commitment to fund a limited partnership venture fund commitment made by a subsidiary of Avista Capital.

These contractual obligations do not include income tax payments.

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

Competition

Our utility electric and natural gas distribution business has historically been recognized as a natural monopoly. In each regulatory jurisdiction, our 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. Rates are designed to provide, after recovery of allowable operating expenses and capital investments, an opportunity for us to earn a reasonable return on investment as set by our regulators.

AVISTA CORPORATION

In retail markets, we compete with various rural electric cooperatives and public utility districts in and adjacent to our service territories in the provision of service to new electric customers. Alternate providers of energy may also compete with us for sales to existing customers. Similarly, our natural gas distribution operations compete with other energy sources including heating oil, propane and other fuels.

In wholesale markets, competition for available electric supply is influenced by the:

•

localized and system-wide demand for energy,

•

type, capacity, location and availability of generation resources, and

•

variety and circumstances of market participants.

These wholesale markets are regulated by the FERC, which requires electric utilities to:

•

transmit power and energy to or for wholesale purchasers and sellers,

•

enlarge or construct additional transmission capacity for the purpose of providing these services, and

•

transparently price and offer transmission services without favor to any party, including the merchant functions of the utility.

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.

We actively monitor and participate, as appropriate in energy industry developments, to maintain and enhance the ability to effectively participate in wholesale energy markets consistent with our business goals.

Advantage IQ is subject to competition for service to existing customers and as they develop products and services and enter new markets. Competition from other companies may mean challenges for Advantage IQ to be the first to market a new product or service to gain the advantage in market share. Other challenges for Advantage IQ include the availability of funding and resources to meet capital needs, and rapidly advancing technologies which requires continual product enhancement to avoid obsolescence.

Long-Term Economic and Utility Load Growth

Based on our forecast for electric customer growth to average 1.1 to 1.6 percent and natural gas customer growth to average 1.3 to 2.3 percent within our service area, we anticipate retail electric and natural gas load growth will average between 1.3 and 1.8 percent annually for the four-year period 2010-2013. While the number of electric customers is growing, the average annual usage by each residential electric customer has stabilized. Natural gas sales growth has slowed as retail prices have increased relative to historical prices and Company sponsored conservation programs have intensified. Population increases and business growth in our three-state service territory remains above the national average. Natural gas loads for space heating vary significantly with annual fluctuations in weather within our service territories.

The forward-looking projections set forth above regarding retail load growth are based, in part, upon purchased economic forecasts and publicly available population and demographic studies. The expectations regarding retail load growth are also based upon various assumptions, including:

•

assumptions relating to weather and economic and competitive conditions,

•

internal analysis of company-specific data, such as energy consumption patterns,

•

internal business plans, and

•

an assumption that we will incur no material loss of retail customers due to self-generation or retail wheeling.

Changes in actual experience can vary significantly from our forward-looking projections.

Environmental Issues and Other Contingencies

We monitor legislative and regulatory developments at all levels of government for environmental issues, particularly those with the potential to alter the operation and productivity of our generating plants and other assets.

AVISTA CORPORATION

Environmental laws and regulations may:

•

increase the operating costs of generating plants,

•

increase the lead time and capital costs for the construction of new generating plants,

•

require modification of our existing generating plants,

•

require existing generating plant operations to be curtailed or shut down,

•

reduce the amount of energy available from our generating plants, and

•

restrict the types of generating plants that can be built.

Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. We intend to seek recovery of any such costs through the ratemaking process.

Rising concerns about long-term global climate changes could have a significant effect on our business. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of global climate changes, including restrictions on the operation of our power generation resources. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of the streamflows, which impacts hydroelectric generation. Changing temperatures could also increase or decrease customer demand.

Greenhouse gas requirements could result in significant costs for us to comply with restrictions on carbon dioxide or other greenhouse gas emissions. Such requirements could also preclude us from developing, operating or contracting with certain types of generating plants.

We continue to monitor and evaluate the possible adoption of national, regional, or state greenhouse gas requirements. In particular, a greenhouse gas bill was passed by the legislature in the state of Washington and a bill was approved by the U.S. House of Representatives. There will most likely be continuing activity in the near future.

Although we are actively monitoring developments for climate change and restrictions on greenhouse gas emissions, it is important to note that we have relatively low emissions as compared to other investor-owned utilities in the U.S. With 56 percent of our net generation capability from hydroelectric and a majority of our thermal generation fueled with natural gas, plus a commitment to energy efficiency, we are among the lowest carbon-emitting utilities in the nation.

We have a Climate Change Committee (CCC) (an interdisciplinary team of management and other employees) which is designed to:

•

anticipate and evaluate strategic needs and opportunities relating to climate change;

•

analyze the company-wide implications of various trends and proposals;

•

develop recommendations on positions and action plans; and

•

facilitate internal and external communications regarding climate change issues.

Longer term issues involve emissions tracking and certification, providing recommendations for greenhouse gas reduction goals and activities, evaluating the merits of different reduction programs, actively participating in the development of legislation, and benchmarking climate change policies and activities against other organizations.

National Legislation

In June 2009, the U.S. House of Representatives approved the American Clean Energy and Security Act of 2009 (H.R. 2454), which includes a mandatory cap-and-trade program for reducing greenhouse gas emissions, a national renewable electricity standard and a number of other energy-related provisions. The cap-and-trade program would begin for electric generators in 2012 and for natural gas local distribution companies in 2016. H.R. 2454 requires that greenhouse gas emissions be reduced by 3 percent below 2005 levels by 2012, 17 percent by 2020, 42 percent by 2030 and 83 percent by 2050. Starting in 2012, covered entities such as fossil-fired power plants must submit to the EPA allowances to emit equal to their greenhouse gas emissions. A different bill (with similar greenhouse gas emissions reduction requirements) S. 1733 is now under consideration in the U.S. Senate.

State Activities

The states of Washington and Oregon have statutory targets to reduce greenhouse gas emissions. Washington requires reductions to 1990 levels by 2020; to 25 percent below 1990 levels by 2035; and to 50 percent below 1990 levels by 2050. Oregon’s goals would reduce greenhouse gas emissions to 10 percent below 1990 levels by 2020 and 75 percent below 1990 levels by 2050. Both states enacted their goals expecting that they would be met through a combination of renewable energy standards, cap-and-trade regulation, and “complementary policies,” such as energy efficiency codes for buildings and vehicle emission standards. Washington and Oregon continue to participate in the

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Western Climate Initiative (WCI), along with the states of Arizona, California, New Mexico, Utah and Montana, and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. The WCI has developed a regional cap-and-trade program with an overall regional goal for reducing greenhouse gas emissions to 15 percent below 2005 levels by 2020. In September 2008, the WCI members released recommendations for the design of such a program, which would apply cap-and-trade regulation to the electricity sector in 2012 and to emissions associated with the distribution of natural gas by 2015. A central element of the WCI’s recommendations is a requirement that its members regulate greenhouse gas emissions from sources of electricity that serve loads within their respective jurisdictions, even though those sources may be located beyond their boundaries. This measure is intended to minimize emissions “leakage” and is a principal feature of California Assembly Bill 32 (AB 32). AB 32 was enacted in California in 2006 and obligates the state to implement greenhouse gas emission regulations. The California Air Resources Board, which has been charged to implement and enforce greenhouse gas emission regulations under AB 32, is on schedule to adopt cap-and-trade regulations by January 1, 2012.

In 2009, the Governor of Washington issued an Executive Order (09-05) directing the Washington Department of Ecology to estimate greenhouse gas emissions by sector and source and to identify potential reduction requirements for them in preparation for the eventual imposition of state and/or federal greenhouse gas regulations. The Department of Ecology has identified “facilities” that emit more than 25,000 metric tons of greenhouse gases annually and has forecasted that those facilities will need to reduce their emissions by 9 percent in order for the state to achieve its greenhouse gas emissions reduction target for 2020. Our natural gas distribution system has been specifically identified as a “facility” and our thermal plants and contracts with thermal plants, including fossil-fueled generation outside of the state have been generically deemed a “facility” for the purposes of potentially regulating emissions associated with the importation of power to serve our Washington loads. The state of Washington has yet to disclose how it might intend to impose and enforce emission reductions.

Washington and Oregon apply a greenhouse gas emissions performance standard to electric generation facilities used to serve loads in their jurisdiction. The emissions performance standard prevents utilities from entering into long-term contracts (five years or more) to purchase energy produced by plants that have emission levels higher than the latest commercially available natural gas-fired combined-cycle combustion turbine technology. Washington’s emission performance standard has been set by statute at 1,100 pounds of greenhouse gases per MWh until 2012, at which time it will be reviewed and may be lowered by administrative rule to reflect the emissions profile of the latest commercially available combined-cycle combustion turbine.

Initiative Measure 937 (I-937), the Energy Independence Act, was passed into law through the 2006 General Election in Washington. I-937 requires investor-owned, cooperative, and government-owned electric utilities with over 25,000 customers to acquire qualified renewable energy resources and/or renewable energy credits in incremental amounts until those resources or credits equal 15 percent of the utility’s total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets, the first of which must be established in 2010. Failure to comply with renewable energy and energy efficiency standards will result in penalties of at least $50 per MWh being assessed against a utility for each MWh it is deficient in meeting a standard. A utility would be deemed to comply with the renewable energy standard if it invests at least 4 percent of its total annual retail revenue requirement on the incremental costs of renewable energy resources and/or renewable energy credits.

Electric Integrated Resource Plan

Our most recent Electric Integrated Resource Plan (IRP), which we filed with the WUTC and the IPUC in the third quarter 2009, includes the acquisition of additional renewable resources such that, if the IRP is implemented, we would be compliant with the requirements of I-937 by the various milestone dates. Highlights of the IRP include:

•

Up to 150 MW of wind power by 2012 (which equates to approximately 50 average megawatts),

•

An additional 200 MW of wind power by 2022,

•

750 MW of clean-burning natural gas-fired generation facilities,

•

Aggressive energy efficiency measures to reduce generation requirements by 26 percent or 339 MW,

•

Transmission upgrades are needed to integrate new generation resources into our system, and

•

Hydroelectric upgrades at existing facilities will generate additional renewable energy.

After a detailed analysis, we decided to postpone renewable resource acquisitions, including the potential construction of a wind generation project until the 2014-2015 timeframe. We plan to meet the state of Washington’s renewable energy standards until 2016 with a combination of qualified hydroelectric upgrades and the purchase of a small amount renewable energy credits from 2012 through 2015. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

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As part of our IRP, we included estimates of climate change into the retail load forecast. The recent trend has been a warming climate compared to the 30-year normal. Trends in heating and cooling degree days for Spokane are roughly equal to the scientific community’s predictions for this geographic area, implying a one degree warming every 25 years. Incorporating the warming trend finds that in 20 years summer load would be approximately 26 aMW higher than the 30-year average. In the winter, loads would be approximately 40 aMW lower in 2029, for a net impact of a 14 aMW load decrease. Our projected system load for 2010 is 1,101 aMW. We do not expect this trend to have a material impact on our results of operations. Estimated costs of greenhouse gas emissions credits were also included in the development of the IRP market prices.

Chicago Climate Exchange

In October 2007, we became a member of the Chicago Climate Exchange (CCX), North America’s only voluntary, verifiable and legally binding emissions reduction and trading marketplace for all six greenhouse gases. Members agree to reduce their greenhouse gas emissions by 6 percent from an established baseline by 2010. The CCX allows participants who exceed their reduction targets to bank or sell the excess CCX Carbon Financial Instruments. We liquidated our 2007 surplus credits in June and July 2009. The audit establishing our 2008 baseline emissions was completed and we received 1,519 of 2008 vintage CCX Carbon Financial Instruments in September 2009. The 2009 emissions audit data will be submitted in the second quarter of 2010. We anticipate having surplus credits for the 2009 compliance year, and expect to receive them in the fourth quarter of 2010.

National Ambient Air Quality Standards

We continue to monitor legislative and regulatory developments at both the state and national levels for potential further restrictions on National Ambient Air Quality Standards (NAAQS). New, more stringent ambient air quality standards were adopted or are being adopted by the EPA for nitrogen dioxide, ozone and particulate matter. We have thermal power plants in Washington, Idaho, Montana and Oregon. Even under the new standards, the EPA and the states have designated most of the western states in which we operate as attainment areas for the new standards. We do not anticipate any material impacts on our thermal plants from these new standards.

Recent EPA Initiatives Related to Climate Change

After a public comment and review period, in December 2009, the EPA Administrator signed two findings regarding greenhouse gases under section 202(a) of the Clean Air Act. The first finding is that the current and projected concentrations of the six key well-mixed greenhouse gases - carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride - in the atmosphere threaten the public health and welfare of current and future generations. The second finding is that the combined emissions of these well-mixed greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas pollution which threatens public health and welfare.

In September 2009, the EPA published a final rule to regulate facilities emitting over 25,000 metric tons of greenhouse gases (GHG) a year under existing Clean Air Act authority. The rule became effective on December 29, 2009. Data collection commenced January 1, 2010 and covered facilities will be required to submit their first GHG emissions report to the EPA by March 31, 2011. Based on rule applicability criteria, Colstrip, Coyote Springs 2, and the Rathdrum CT will be required to report GHGs. These facilities currently report carbon dioxide to the EPA under the Acid Rain Program and it is expected that the operators of Colstrip and Coyote Springs 2 will be responsible for any additional GHG reporting. Based on our evaluation of historical emissions from 2004-2008, none of our other electrical generation facilities meet the threshold requirements. The proposed rule also requires natural gas distribution system throughput be reported. Monitoring methods per the rule are currently in place and development of a GHG Monitoring Plan for covered facilities is currently underway and will be in place prior to the April 1, 2010 deadline for required monitoring method implementation. The purpose of the plan is to document the process and procedures for collecting and reviewing the data needed to estimate annual GHG emissions.

Coal Ash Management/Disposal

Currently, coal combustion byproducts (CCBs) are not regulated by the EPA as a hazardous waste. The EPA is currently reconsidering the classification of CCBs under the Resource Conservation and Recovery Act (RCRA). A draft proposal is under review at the Office of Budget and Management, but no proposal regarding such regulation has been issued for public review or comment. Should the EPA determine to regulate CCBs as a hazardous waste under the RCRA, such action could have a significant impact on future operations of Colstrip. However, given that no rulemaking proposal has been issued, it is impossible to evaluate the impact of a future regulatory action. We are tracking these developments as information becomes available.

Western Power Market Issues

The FERC continues to conduct proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds, and some of the FERC’s decisions have been appealed in Federal Courts. Certain parties have asserted claims for significant refunds from us, which could result in

AVISTA CORPORATION

liabilities for refunding revenues recognized in prior periods. We have joined other parties in opposing these proposals. We believe that we have adequate reserves established for refunds that may be ordered. The refund proceedings provide that any refunds would be offset against unpaid energy debts due to the same party. As of December 31, 2009, our accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties. See “California Refund Proceeding” and “Pacific Northwest Refund Proceeding” in “Note 24 of the Notes to Consolidated Financial Statements” for further information on the refund proceedings.

For other environmental issues and other contingencies see “Note 24 of the Notes to Consolidated Financial Statements.”

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

General

Our power supply cost varies because of several factors. We optimize the mix of power resources to meet our retail customer requirements and other obligations. We also use our resources and obtain resources from others in the wholesale power market (including natural gas fuel markets). Hydroelectric generation is typically the least cost source of supply, but the amount of hydroelectric generation depends on streamflow conditions (affected by both the volume and timing of precipitation, including snow melt patterns) and other factors in the watersheds for our hydroelectric facilities. Thermal generation resource costs vary with fuel costs and other factors. Wholesale market prices tend to vary with natural gas fuel costs to the extent that natural gas-fired resources are the least cost alternative in the region (which is often the case in recent years). Generating resource availability and regional demand tend to impact energy prices, which affect our net power supply costs.

Even with regulatory cost recovery mechanisms that address these power supply cost variations, a portion of the cost variation is not passed on to customers. In addition, the timing of incurring costs can be significantly different than the timing for recovering costs, resulting in the need for a significant liquidity cushion.

Our hydroelectric generation was slightly below normal (based on a 70-year average) in 2009 and in eight of the past ten years. We cannot determine if lower than normal hydroelectric generation will continue in future years. When we have excess hydroelectric generation, its value varies with market prices and other displaceable resources. When hydroelectric generation is below normal, the cost to obtain power from other sources is generally higher. When hydroelectric generation is above normal, prices in the wholesale market are often depressed which can adversely impact our surplus sales revenues. We are 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 our costs in future periods. See further information at “Avista Utilities - Regulatory Matters.”

Market prices for natural gas continue to be competitive compared to alternative fuel sources for customers, and we believe that natural gas should sustain its long-term market advantage over competing energy sources based on the levels of existing reserves and potential natural gas development in the future. Growth has occurred in the natural gas business in recent years due to increased demand for natural gas in new construction and conversions from competing space and water heating energy sources to natural gas.

Certain natural gas customers could by-pass our natural gas system, reducing both revenues and recovery of fixed costs. To reduce the potential for such by-pass, we price natural gas services, including transportation contracts, competitively and have varying degrees of flexibility to price transportation and delivery rates by means of individual contracts. These individual contracts are subject to state regulatory review and approval. We have long-term transportation contracts with several of our largest industrial customers. This reduces the risk of these customers by-passing our system in the foreseeable future and minimizes the impact on our earnings.

We 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

In general, price risk is driven by 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 impact on retail loads. We hedge our exposure to price risk by making forward commitments for energy purchases and sales as further described under “Risk Management.”

Electricity prices are affected by a number of factors, including:

•

demand for electricity,

•

the number of market participants and the willingness of market participants to trade,

•

adequacy of generating reserve margins,

AVISTA CORPORATION

•

scheduled and unscheduled outages of generating facilities,

•

availability of streamflows for hydroelectric generation,

•

price and availability of fuel for thermal generating plants, and

•

disruptions of or constraints on transmission facilities.

Natural gas prices are affected by a number of factors, including:

•

amount of North American production and production capacity that can be delivered to our service areas,

•

level of imports and exports, particularly from Canada by pipeline and to a growing extent by LNG,

•

level of inventories and regional accessibility,

•

demand for natural gas, including natural gas as fuel for electric generation,

•

the number of market participants and the willingness of market participants to trade,

•

global energy markets, including oil or other natural gas substitutes, and

•

availability of pipeline capacity to transport natural gas from region to region.

Any combination of these factors that results in a shortage of energy generally causes the market price to move upward. Factors such as a general economic downturn, increased proven energy reserves, or increased production generally reduce market prices for energy. In addition to these factors, wholesale power markets are subject to regulatory constraints including price controls.

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.

We have mechanisms in each regulatory jurisdiction that provide for recovery of the majority of the changes in our power and natural gas costs. The majority of power and natural gas costs exceeding the amount currently recovered through retail rates, excluding the ERM deadband (and other sharing components) in Washington, are deferred on our 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.

Substantially all forward contracts to purchase or sell power and natural gas are recorded as assets or liabilities at market value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are generally accounted for on the accrual basis 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.

The following table presents energy commodity derivative fair values presented as a net asset or (liability) as of December 31, 2009 that are expected to settle in each respective year (dollars in thousands):


	Purchases											Sales
	Electric Derivatives					Gas Derivatives						Electric Derivatives					Gas Derivatives
Year	Physical		Financial			Physical			Financial			Physical			Financial		Physical			Financial
2010	$	5,143	$	(1,513	)	$	(3,335	)	$	(2,877	)	$	209		$	35	$	(5,992	)	—
2011		5,899		332			(889	)		—			(193	)		84		(679	)	—
2012		5,481		—			(595	)		—			(321	)		—		—		—
2013		5,195		—			(59	)		—			(324	)		—		—		—
2014		4,979		—			—			—			(453	)		—		—		—
Thereafter		30,548		—			—			—			(6,393	)		—		—		—

Credit Risk

Credit risk relates to potential losses that we would incur as a result of non-performance of contractual obligations by counterparties to deliver energy or make financial settlements. We often extend credit to counterparties and customers, and we are exposed to the risk of not being able to collect amounts owed to us. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when we establish conservative credit limits. Credit risk includes potential counterparty default due to circumstances:

•

relating directly to the counterparty,

•

caused by market price changes, and

•

relating to other market participants that have a direct or indirect relationship with such counterparty.

AVISTA CORPORATION

Should a counterparty, customer or supplier fail to perform, we may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices.

We seek to mitigate credit risk by:

•

entering into bilateral contracts that specify credit terms and protections against default,

•

applying credit limits and duration criteria to existing and prospective counterparties,

•

actively monitoring current credit exposures, and

•

conducting some of our transactions on exchanges with clearing arrangements that essentially eliminate counterparty default risk.

Our credit 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. We also use standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty or affiliated group. However, despite mitigation efforts, defaults by our counterparties periodically occur.

We regularly evaluate counterparties’ credit exposure for future settlements and delivery obligations. We reduce or eliminate open (unsecured) credit limits and implement other credit risk reduction measures for parties perceived to have increased default risk. Counterparty collateral is used to offset our credit risk where unsettled net positions and future obligations by counterparties to pay us or deliver to us warrant.

We have concentrations of suppliers and customers in the electric and natural gas industries including:

•

electric utilities,

•

electric generators and transmission providers,

•

natural gas producers and pipelines,

•

financial institutions, and

•

energy marketing and trading companies.

In addition, we have concentrations of credit risk related to geographic location in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may affect our overall exposure to credit risk because the counterparties may be similarly affected by changes in conditions.

Credit risk also involves the exposure that counterparties perceive related to our ability 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.

Credit exposure can change significantly in periods of price volatility. As a result, sudden and significant demands may be made against our credit facilities and cash. We actively monitor the exposure to possible collateral calls and take steps to minimize capital requirements.

Counterparties’ credit exposure to us is dynamic in normal markets and may change significantly in more volatile markets. The amount of potential default risk to us, from each counterparty, depends on the extent of forward contracts, unsettled transactions and market prices. There is a risk that we may seek additional collateral from counterparties that are unable or unwilling to provide.

Credit risks related to our retail customer base include the extent to which customers do not pay or are slow to pay for energy we have delivered to them. We are allowed to recover normal credit losses in retail rates but economic conditions for our customers may result in unrecovered credit losses. We also extend credit (generally for up to five years) in certain circumstances to construction developers for the cost of utility infrastructure investment. The infrastructure costs are typically recovered when new customers begin receiving utility service but to the extent that customers do not connect as planned, we may carry credit risks with these developers.

We maintain credit reserves that are based on the evaluation of the credit risk of the overall portfolio. Based on our credit policies, exposures and credit reserves, we do not anticipate a materially adverse effect on our financial condition or results of operations as a result of counterparty nonperformance.

AVISTA CORPORATION

Interest Rate Risk

We are affected by fluctuating interest rates related to a portion of our existing debt and our future borrowing requirements. We manage interest rate exposure by limiting our variable-rate exposures to a percentage of total capitalization and by monitoring the effects of market changes in interest rates. Additionally interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. We also enter into financial derivative instruments, which may include interest rate swaps and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. We did not have any interest rate swap contracts outstanding as of December 31, 2009.

The interest rate on $51.5 million of long-term debt to affiliated trusts is adjusted quarterly, reflecting current market rates. Amounts borrowed under our $320.0 million and $75.0 million committed line of credit agreements have variable interest rates. The weighted average variable rate on outstanding short-term borrowings was 0.59 percent at December 31, 2009. The following table shows our long-term debt (including current portion) and related weighted average interest rates, by expected maturity dates as of December 31, 2009 (dollars in thousands):


	2010			2011	2012			2013			2014	Thereafter			Total			Fair Value
Fixed rate long- term debt	$	35,000		—	$	7,000		$	75,000		—	$	955,100		$	1,072,100		$	1,079,857
Weighted average interest rate		7.67	%	—		7.37	%		6.58	%	—		5.76	%		5.89	%
Variable rate long- term debt to affiliated trusts		—		—		—			—		—	$	51,547		$	51,547		$	43,534
Weighted average interest rate		—		—		—			—		—		1.22	%		1.22	%

Foreign Currency Risk

A significant portion of our utility natural gas supply (including fuel for electric generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of our short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within sixty days with U.S. dollars. In early 2009, we implemented a process to economically hedge a portion of the foreign currency risk by purchasing Canadian currency when such commodity transactions are initiated. This risk has not had a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking. As of December 31, 2009, we had a current derivative liability for foreign currency hedges of less than $0.1 million included in other current liabilities on the Consolidated Balance Sheet. As of December 31, 2009, we had entered into 24 Canadian currency forward contracts with a notional amount of $10.2 million ($10.6 million Canadian).

Risk Management

We use a variety of techniques to manage risks for energy resources and wholesale energy market activities. We have an energy resources risk policy and control procedures to manage these risks, both qualitative and quantitative. Our Risk Management Committee established our risk management policy for energy resources. The Risk Management Committee is comprised of certain officers and other management. The Audit Committee of the Company’s Board of Directors periodically reviews and discusses risk assessment and risk management policies, including the Company’s material financial and accounting risk exposures and the steps management has undertaken to control them. Our Risk Management Committee reviews the status of risk exposures through regular reports and meetings and it monitors compliance with our risk management policy and control procedures. 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.

Our Risk Management Committee also established 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 our liquidity as other parties may place credit limits or require cash collateral.

We measure the volume of monthly, quarterly and annual energy imbalances between projected power loads and resources. The measurement process is based on expected loads at fixed prices (including those subject to retail rates) and expected resources to the extent that costs are essentially fixed by virtue of known fuel supply costs or projected hydroelectric conditions. To the extent that expected costs are not fixed, either because of volume mismatches between loads and resources or because fuel cost is not locked in through fixed price contracts or derivative

AVISTA CORPORATION

instruments, our risk policy guides the process to manage this open forward position over a period of time. Normal operations result in seasonal mismatches between power loads and available resources. We are able to vary the operation of generating resources to match parts of hourly, daily and weekly load fluctuations. We use the wholesale power markets, including the natural gas market as it relates to power generation fuel, to sell projected resource surpluses and obtain resources when deficits are projected. We buy and sell fuel for thermal generation facilities based on comparative power market prices and marginal costs of fueling and operating available generating facilities and the relative economics of substitute market purchases for generating plant operation. Effective January 1, 2010, the natural gas-fired Lancaster power purchase agreement was added to our utility resource portfolio, with the potential to significantly increase the extent of transactions for natural gas fuel hedging and plant optimization.

To address the impact on our operations of energy market price volatility, our hedging practices for electricity (including fuel for generation) and natural gas extend beyond the current operating year. Executing this extended hedging program may increase our credit risks, particularly in consideration of the national economic conditions with resultant financial stress among energy market participants. Our credit risk management process is designed to mitigate such credit risks through limit setting, contract protections and counterparty diversification, among other practices.

Electric load/resource imbalances within a planning horizon up to 36 months ahead are compared against established volumetric guidelines. Management determines the timing and actions to manage the imbalances. We also assess available resource alternatives 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 our desired transaction size and shape. Therefore, open imbalance positions exist at any given time.

Our projected natural gas loads and resources are regularly reviewed by operating management and the Risk Management Committee. To manage the impacts of volatile natural gas prices, we seek to procure natural gas through a diversified mix of spot market purchases and forward fixed price purchases from various supply basins and time periods. We have an active hedging program that extends four years into the future with the goal of reducing price volatility in our natural gas supply costs. We use natural gas storage capacity to support high demand periods and to procure natural gas when prices are likely to be seasonally lower. Securing prices throughout the year and even into subsequent years at multiple basins mitigates potential adverse impacts of significant purchase requirements in a volatile price environment.

Further information for derivatives and fair values is disclosed at “Note 7 of the Notes to Consolidated Financial Statements” and “Note 20 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, 2009 and 2008, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the results of their op