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, 2010

¨	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

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 x No ¨

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

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 $1,081,138,342 based on the last reported sale price thereof on the consolidated tape on June 30, 2010.

As of January 31, 2011, 57,276,041 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 12, 2011

Part III, Items 10, 11,

12, 13 and 14

AVISTA CORPORATION

INDEX


Item No.		Page No.
	Acronyms and Terms		iv

	Part I

	Forward-Looking Statements		1
	Available Information		2
1.	Business		3
	Company Overview		3
	Avista Utilities		4
	General		4
	Electric Operations		4
	Electric Requirements		4
	Electric Resources		5
	Hydroelectric Licensing		6
	Future Resource Needs		7
	Natural Gas Operations		8
	Regulatory Issues		9
	Federal Laws Related to Wholesale Competition		9
	Regional Transmission Organizations		10
	Reliability Standards		10
	Avista Utilities Operating Statistics		11
	Advantage IQ		13
	Other Businesses		13
1A.	Risk Factors		14
1B.	Unresolved Staff Comments		17
2.	Properties		18
	Avista Utilities		18
3.	Legal Proceedings		19
4.	(Removed and Reserved)		19

	Part II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		20
6.	Selected Financial Data		21
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
	Business Segments		22
	Executive Level Summary		22
	Avista Utilities – Regulatory Matters		24
	Results of Operations		28
	Avista Utilities		30
	Advantage IQ		35
	Other Businesses		35
	Accounting Standards to Be Adopted in 2011		36
	Critical Accounting Policies and Estimates		36
	Liquidity and Capital Resources		39
	Review of Cash Flow Statement		39
	Overall Liquidity		40
	Credit and Nonperformance Risk		40
	Dodd-Frank Wall Street Reform and Consumer Protection Act		41
	Capital Resources		41
	Avista Utilities Capital Expenditures		43
	Advantage IQ Credit Agreement		43
	Advantage IQ Redeemable Stock		44
	Accounts Receivable Financing Facility		44
	Off-Balance Sheet Arrangements		44
	Pension Plan		44
	Credit Ratings		44
	Dividends		45
	Contractual Obligations		45

AVISTA CORPORATION


	Competition	46
	Economic Conditions and Utility Load Growth	46
	Environmental Issues and Other Contingencies	47
7A.	Quantitative and Qualitative Disclosures about Market Risk	52
8.	Financial Statements and Supplementary Data	56
	Report of Independent Registered Public Accounting Firm	57
	Financial Statements	58-64
	Consolidated Statements of Income	58
	Consolidated Statements of Comprehensive Income	59
	Consolidated Balance Sheets	60-61
	Consolidated Statements of Cash Flows	62-63
	Consolidated Statements of Equity and Redeemable Noncontrolling Interests	64
	Notes to Consolidated Financial Statements	65-109
	Note 1. Summary of Significant Accounting Policies	65
	Note 2. New Accounting Standards	70
	Note 3. Disposition of Avista Energy	72
	Note 4. Impairment of Assets	72
	Note 5. Advantage IQ Acquisitions	72
	Note 6. Derivatives and Risk Management	73
	Note 7. Jointly Owned Electric Facilities	77
	Note 8. Property, Plant and Equipment	78
	Note 9. Asset Retirement Obligations	78
	Note 10. Pension Plans and Other Postretirement Benefit Plans	79
	Note 11. Accounting for Income Taxes	84
	Note 12. Energy Purchase Contracts	86
	Note 13. Accounts Receivable Financing Facility	87
	Note 14. Short-Term Borrowings	87
	Note 15. Long-Term Debt	88
	Note 16. Long-Term Debt to Affiliated Trusts	89
	Note 17. Leases	90
	Note 18. Guarantees	90
	Note 19. Preferred Stock-Cumulative (Subject to Mandatory Redemption)	90
	Note 20. Fair Value	90
	Note 21. Common Stock	93
	Note 22. Earnings per Common Share Attributable to Avista Corporation	93
	Note 23. Stock Compensation Plans	94
	Note 24. Commitments and Contingencies	97
	Note 25. Information Services Contracts	103
	Note 26. Avista Utilities Regulatory Matters	103
	Note 27. Information by Business Segments	108
	Note 28. Selected Quarterly Financial Data (Unaudited)	109
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	110	*
9A.	Controls and Procedures	110
9B.	Other Information	112

	Part III

10.	Directors, Executive Officers and Corporate Governance	112
11.	Executive Compensation	113
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113
13.	Certain Relationships and Related Transactions, and Director Independence	114
14.	Principal Accounting Fees and Services	114

	Part IV

15.	Exhibits, Financial Statement Schedules	115
	Signatures	116
	Exhibit Index	117

* = not an applicable item in the 2010 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

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

Ecos		- a Portland, Oregon-based energy efficiency solutions provider acquired by Advantage IQ in 2009

Energy		- the amount of electricity produced or consumed over a period of time, measured in KWH or MWH

EPA		- Environmental Protection Agency

AVISTA CORPORATION


ERM		- the Energy Recovery Mechanism in the state of Washington

FASB		- Financial Accounting Standards Board

FERC		- Federal Energy Regulatory Commission

GHG		- greenhouse gas

IPUC		- Idaho Public Utilities Commission

IRP		- Integrated Resource Plan

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 Corporation

Noxon Rapids		- the Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana

OPUC		- the Public Utility Commission of Oregon

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

PGA		- Purchased Gas Adjustment

PLP		- Potentially liable party

PUD		- Public Utility District

PURPA		- the Public Utility Regulatory Policies Act of 1978

RTO		- Regional Transmission Organization

Spokane Energy		- Spokane Energy, LLC, a special purpose limited liability company and all of its membership capital is owned by Avista Corp.

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

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;

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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;

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

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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;

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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;

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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;

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

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

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the outcome of legal proceedings and other contingencies;

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

•

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;

AVISTA CORPORATION

•

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

•

explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation, transmission and distribution systems;

•

blackouts or disruptions of interconnected transmission systems;

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

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the potential for terrorist attacks, cyber security attacks or other malicious acts, that cause damage to our utility assets, as well as the national economy in general; including the impact of acts of terrorism or vandalism that damage or disrupt information technology systems;

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

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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;

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

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the loss of key suppliers for materials or services;

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

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deterioration in the creditworthiness of our customers and counterparties;

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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;

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

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

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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;

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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;

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

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changes in tax rates and/or policies; and

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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.

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.

AVISTA CORPORATION

PART I

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, 2010, we employed 1,554 people in our utility operations and 945 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 76 percent owned as of December 31, 2010) provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Advantage IQ’s primary product lines include expense management services for utility, telecom and lease needs as well as strategic energy management and efficiency services that include procurement , conservation, performance reporting, financial planning and energy efficiency program management for commercial enterprises and utilities.

We have ancillary businesses and investments that include a sheet metal fabrication business, emerging technology venture fund investments and commercial real estate investments, Spokane Energy, LLC (Spokane Energy) (which was consolidated effective January 1, 2010) 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. Total Avista Corp. stockholders’ equity was $1,125.8 million as of December 31, 2010, of which $77.7 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 2010, we supplied retail electric service to 359,000 customers and retail natural gas service to 319,000 customers across our entire service territory. Our service territory covers 30,000 square miles with a population of 1.5 million. See “Item 2. Properties” for further information on our utility assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Economic Conditions and Utility Load Growth” for information on economic conditions in our service territory.

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

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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:

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purchasing fuel for generation,

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

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other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity contracts.

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. Transmission revenues were $12.8 million in 2010, $9.3 million in 2009 and $9.5 million in 2008.

Electric Requirements

Our peak electric native load requirement for 2010 occurred on November 23, 2010 at which time our total obligation was 2,507 MW consisting of:

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native load of 1,704 MW,

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long-term wholesale obligations of 237 MW, and

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short-term wholesale obligations of 566 MW.

At that time our maximum resource capacity available was 2,905 MW, which included:

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company-owned electric generation of 1,537 MW,

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long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 152 MW,

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other long-term wholesale contracts of 563 MW, and

•

short-term wholesale purchases of 653 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 2010, our facilities had a total net capability of 1,791 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 2011 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 516 average megawatts (aMW) (or 4.5 million MWhs). Hydroelectric resources provided 476 aMW for 2010, 526 aMW for 2009 and 535 aMW for 2008.

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


	2010		2009		2008
Noxon Rapids		1,503		1,673		1,696
Cabinet Gorge		942		1,061		1,081
Post Falls		90		84		85
Upper Falls		71		52		78
Monroe Street		106		104		104
Nine Mile		101		106		105
Long Lake		480		487		497
Little Falls		201		199		205

Total company-owned hydroelectric generation		3,494		3,766		3,851
Long-term hydroelectric contracts with PUDs		685		839		833

Total hydroelectric generation		4,179		4,605		4,684

Thermal Resources We own:

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

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

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

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

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

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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. 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. 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:


	2010		2009		2008
Coyote Springs 2		1,661		1,559		1,696
Colstrip		1,749		1,277		1,758
Kettle Falls GS		312		184		201
Northeast CT and Rathdrum CT		12		44		15
Boulder Park and Kettle Falls CT		14		33		23

Total thermal generation		3,748		3,097		3,693

Lancaster Plant Power Purchase Agreement 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 us through 2026 under a power purchase agreement. The majority of the rights and obligations under this agreement were conveyed to Shell Energy through the end of 2009. These rights and obligations were conveyed 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 Idaho Public Utilities Commission (IPUC) and are currently being recovered through general rates and the Power Cost Adjustment mechanism. In Washington, the Washington Utilities and Transportation Commission (WUTC) initially did not allow us to include the costs associated with the power purchase agreement for the Lancaster Plant in rates. We subsequently filed for and received approval for deferred accounting treatment for these net costs. In the 2010 Washington general rate case settlement, the parties agreed that recovery of the deferred net costs associated with the power purchase agreement for the Lancaster Plant would be limited to $6.8 million for 2010. These net deferred costs will be recovered over a five-year amortization period with a rate of return on the unamortized balance. The parties agreed that the costs for the Lancaster Plant for 2011 and going forward are reasonable and should be recovered in rates. As part of the settlement related to the 2010 Lancaster Plant deferred net costs, the parties agreed that there would be no deferrals under the ERM for 2010.

Other 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, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the WUTC and the IPUC. Existing contracts expire at various times between 2011 and 2022.

See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2010, 2009 and 2008.

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 “Cabinet Gorge Total Dissolved Gas Abatement Plan” in “Note 24 of the Notes to Consolidated Financial Statements” for discussion 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) 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 in June 2009. For further information see “Spokane River Licensing” in “Note 24 of the Notes to Consolidated Financial Statements.”

AVISTA CORPORATION

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 1,075 aMW in 2010, 1,082 aMW in 2009 and 1,102 aMW in 2008. The following is a forecast of our average annual energy requirements and resources for 2011, 2012, 2013 and 2014:

Forecasted Electric Energy Requirements and Resources

(aMW)


	2011		2012		2013		2014
Requirements:
System load		1,094		1,109		1,131		1,148
Contracts for power sales		138		138		124		107

Total requirements		1,232		1,247		1,255		1,255

Resources:
Company-owned and contract hydro generation (1)		523		528		533		536
Company-owned base load thermal generation (2)		516		494		469		490
Contracts for power purchases		376		421		405		422

Total resources		1,415		1,443		1,407		1,448

Surplus resources		183		196		152		193
Additional available energy (3)		144		153		153		153

Total surplus resources		327		349		305		346

(1)	The forecast assumes near normal hydroelectric generation.

(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 2009 IRP include:

•

Up to 150 MW of wind power by 2012,

•

An additional 200 MW of wind power by 2022,

•

750 MW of 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 required to file an IRP every two years. We will file an IRP in August 2011 and our resource strategy may change from the highlights included above based upon market, legislative and regulatory developments.

We are subject to the Washington state Energy Independence Act, which includes renewable energy portfolio standards and we 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.

In February 2011, we issued a request for proposals (RFP) seeking qualifying renewable electric resources to meet a portion of our renewable energy portfolio standards requirements under the Washington state Energy Independence Act. We seek to acquire up to 35 aMW of renewable energy, or as much as 100 MW of nameplate wind capacity with deliveries beginning in 2012. We have issued this RFP due to recent market changes, tax incentives that remain in effect and a recent WUTC policy statement indicating support of the acquisition of renewable resources in advance of renewable portfolio standards deadlines, if early acquisition can be cost-justified. We completed the acquisition of the development rights for a wind generation site in 2008 . While this RFP does not include the development of this site, we will continue to study this site in preparation for later development. We plan to meet the state of Washington’s renewable energy standards until 2016 with a combination of qualified upgrades at our existing hydroelectric generation plants and the purchase of a small amount of renewable energy credits from 2012 through 2015.

AVISTA CORPORATION

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

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for information related to 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, can 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.

Like prices, natural gas loads can also be volatile. Daily natural gas loads can differ significantly from the monthly load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. 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 for multiple 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 leave a significant portion of our natural gas supply requirements unhedged for purchase in short-term and spot markets.

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. Natural gas resource optimization activities include, but are not limited to:

•

wholesale market sales of surplus natural gas supplies,

•

purchases and sales of natural gas to optimize use of pipeline and 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 2010, 2009 and 2008 was 142.1, 144.6 and 148.7 million therms, representing 15 percent, 16 percent and 18 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 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 249.5 million therms.

Avista Utilities will gain 30.3 million therms of additional capacity at Jackson Prairie on May 1, 2011 for use in its utility operations. This capacity was originally held by Avista Energy and as part of the asset sales agreement this capacity is assigned to Shell Energy through April 30, 2011.

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.

AVISTA CORPORATION

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.

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 services 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 in Washington and Idaho 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 in these states 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 historically has resulted in a lag between the time we incur costs and the time when we start recovering the costs through subsequent changes in rates. Oregon currently allows a forecasted test year, which generally is more effective in providing timely recovery of costs.

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. We typically propose such adjustments at least once per year. 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.

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 Open Access Same-Time Information System 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.

AVISTA CORPORATION

Regional Transmission Organizations

Beginning with FERC Orders No. 888 and No. 2000 (issued in 2000) and continuing with subsequent rulemakings and policies, the FERC has encouraged the formation of various forms of Regional Transmission Organizations (RTOs), including independent system operators (ISOs). While it has not mandated ISO formation, the FERC has issued orders and made public policy statements indicating its support for the development and formation of regional independently-governed transmission organizations, including those intended 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 ISO in the region. We ultimately became a member of ColumbiaGrid, a Washington nonprofit membership corporation with an independent slate of directors formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. ColumbiaGrid is not an ISO, but performs limited functions as set forth in specific agreements with ColumbiaGrid members and other stakeholders. ColumbiaGrid and its members also work with other western RTOs and groups to address operational efficiencies, including WestConnect and the Northern Tier Transmission Group. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid and/or participating in other forums to attain operational efficiencies and to meet FERC policy objectives.

The FERC requires RTOs to provide various data and is currently requesting non-RTO regions to report similar data for the purpose of establishing performance metrics. We expect the FERC to use this data to compare RTO and non-RTO regions. We cannot foresee what policy objectives the FERC may develop as a result of establishing such performance metrics.

Reliability Standards

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

The FERC subsequently certified the North American Electricity Reliability Corporation (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 2011, the FERC has approved 111 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. Annual self-certification and audit processes to date have demonstrated our substantial compliance with these standards.

AVISTA CORPORATION

AVISTA UTILITIES OPERATING STATISTICS


	Years Ended December 31,
	2010			2009			2008
ELECTRIC OPERATIONS
ELECTRIC OPERATING REVENUES (Dollars in Thousands):
Residential	$	296,627		$	315,649		$	279,641
Commercial		265,219			273,954			247,714
Industrial		114,792			107,741			101,785
Public street and highway lighting		6,702			6,607			5,962

Total retail		683,340			703,951			635,102
Wholesale		165,553			88,414			141,744
Sales of fuel		106,375			32,992			44,695
Other		19,015			15,426			16,916

Total electric operating revenues	$	974,283		$	840,783		$	838,457

ELECTRIC ENERGY SALES (Thousands of MWhs):
Residential		3,618			3,791			3,744
Commercial		3,100			3,177			3,188
Industrial		2,099			1,948			2,059
Public street and highway lighting		26			26			26

Total retail		8,843			8,942			9,017
Wholesale		3,803			2,354			1,964

Total electric energy sales		12,646			11,296			10,981

ELECTRIC ENERGY RESOURCES (Thousands of MWhs):
Hydro generation (from Company facilities)		3,494			3,766			3,851
Thermal generation (from Company facilities)		3,748			3,097			3,693
Purchased power - hydro generation from long-term contracts with PUDs		685			839			833
Purchased power - wholesale		5,315			4,152			3,253
Power exchanges		(15	)		(18	)		(17	)

Total power resources		13,227			11,836			11,613
Energy losses and Company use		(581	)		(540	)		(632	)

Total energy resources (net of losses)		12,646			11,296			10,981

NUMBER OF ELECTRIC RETAIL CUSTOMERS (Average for Period):
Residential		315,283			313,884			311,381
Commercial		39,489			39,276			39,075
Industrial		1,376			1,394			1,388
Public street and highway lighting		449			444			434

Total electric retail customers		356,597			354,998			352,278

ELECTRIC RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (KWh)		11,476			12,079			12,023
Revenue per KWh (in cents)		8.20			8.33			7.47
Annual revenue per customer	$	940.83		$	1,005.62		$	898.07
ELECTRIC AVERAGE HOURLY LOAD (aMW)		1,075			1,082			1,102

RESOURCE AVAILABILITY at time of system peak (MW):
Total requirements (winter):
Retail native load		1,704			1,763			1,821
Wholesale obligations		803			608			562

Total requirements (winter)		2,507			2,371			2,383

Total resource availability (winter)		2,905			2,514			2,480

Total requirements (summer):
Retail native load		1,556			1,522			1,602
Wholesale obligations		822			685			431

Total requirements (summer)		2,378			2,207			2,033

Total resource availability (summer)		2,662			2,499			2,250
COOLING DEGREE DAYS: (1)
Spokane, WA
Actual		380			589			478
30-year average		434			394			394
% of average		88	%		149	%		121	%

(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,
	2010			2009			2008
NATURAL GAS OPERATIONS
NATURAL GAS OPERATING REVENUES (Dollars in Thousands):
Residential	$	193,169		$	251,022		$	276,386
Commercial		98,257			135,236			152,147
Industrial and interruptible		6,494			9,945			12,159

Total retail		297,920			396,203			440,692
Wholesale		197,364			143,524			281,668
Transportation		6,470			6,067			6,327
Other		9,495			8,624			5,520

Total natural gas operating revenues	$	511,249		$	554,418		$	734,207

THERMS DELIVERED (Thousands of Therms):
Residential		188,546			207,979			210,125
Commercial		113,422			126,345			128,224
Industrial and interruptible		9,755			10,918			12,196

Total retail		311,723			345,242			350,545
Wholesale		468,887			397,977			345,916
Transportation		142,093			144,580			148,723
Interdepartmental and Company use		393			502			526

Total therms delivered		923,096			888,301			845,710

SOURCES OF NATURAL GAS SUPPLY (Thousands of Therms):
Purchases		787,836			751,057			710,137
Storage - injections		(86,750	)		(99,330	)		(76,491	)
Storage - withdrawals		83,333			95,183			66,271
Natural gas for transportation		142,093			144,580			148,723
Distribution system losses		(3,416	)		(3,189	)		(2,930	)

Total natural gas supply		923,096			888,301			845,710

NUMBER OF NATURAL GAS RETAIL CUSTOMERS (Average for Period):
Residential		282,721			280,667			277,892
Commercial		33,431			33,214			32,901
Industrial and interruptible		292			300			297

Total natural gas retail customers		316,444			314,181			311,090

NATURAL GAS RESIDENTIAL SERVICE AVERAGES:
Annual use per customer (therms)		667			741			756
Revenue per therm (in dollars)	$	1.02		$	1.21		$	1.32
Annual revenue per customer	$	683.25		$	894.37		$	994.58

HEATING DEGREE DAYS: (1)
Spokane, WA
Actual		6,320			6,976			7,052
30-year average		6,647			6,820			6,820
% of average		95	%		102	%		103	%
Medford, OR
Actual		4,119			4,485			4,569
30-year average		4,402			4,533			4,533
% of average		94	%		99	%		101	%

(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 and energy management solutions to multi-site companies across North America. 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 the expense management services, Advantage IQ analyzes and audits invoices, then presents consolidated bills on-line, and processes payments. 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 also provides comprehensive energy efficiency program management services to utilities across North America. As part of these management services, Advantage IQ helps utilities develop and execute energy efficiency programs with a complete turn-key solution.

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

•

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

•

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:


	2010		2009		2008
Customers at year-end		534		532		537
Billed sites at year-end		360,596		421,080		417,078
Dollars of customer bills processed (in billions)	$	17.3	$	17.4	$	16.7

The decrease in billed sites at year-end 2010 as compared to prior periods was due to the loss of a customer that had a significant number of billed sites, but represented only approximately 1 percent of annual revenues. On December 31, 2010, Advantage IQ acquired substantially all of the assets and liabilities of The Loyalton Group, a Minneapolis-based energy management firm known for its energy procurement and price risk management solutions. In January 2011, Advantage IQ acquired substantially all of the assets and liabilities of Building Knowledge Networks, a Seattle-based real-time building energy management services provider.

Other Businesses

Avista Energy still owns natural gas storage facilities and we expect these assets to be transferred to our utility operations on May 1, 2011. 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.

The implementation of amendments to accounting standards (See Note 2 of the Notes to Consolidated Financial Statements) resulted in the Company including Spokane Energy in its consolidated financial statements effective January 1, 2010. Spokane Energy is a special purpose limited liability company and all of its membership capital is owned by Avista Corp. Spokane Energy was formed in December 1998, to assume ownership of a fixed rate electric capacity contract between Avista Corp. and Portland General Electric Company. The consolidation of Spokane Energy results in an increase in operating revenues, operating expenses and interest expense with no impact on net income.

Our other businesses also 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:

•

real estate investments (primarily commercial office buildings),

•

investments in emerging technology venture capital funds and low income housing, and

•

the remaining investment in a fuel cell business that was previously a 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 “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, precipitation levels and storms) 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,

•

the cost of power supply, and

•

damages to facilities.

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 adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount then 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, its water content and 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 must be acquired 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.

Damages to facilities may be caused by severe weather, such as snow, ice or wind storms. The cost to implement rapid repair to such facilities can be significant. Overhead electric lines are most susceptible to such severe weather. Collateral damage from utility assets that are damaged by external forces may result in third party claims against the Company for property damage and/or personal injuries.

AVISTA CORPORATION

We are subject to commodity price risk.

A combination of factors exposes our operations to commodity price risks. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. 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 buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). 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.

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 an opportunity to earn a reasonable return for 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.

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 potential 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.

AVISTA CORPORATION

Financial market conditions may impact our results of operations and our liquidity.

We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in 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.

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.

Performance of 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. In February 2011, we entered into a new $400 million committed line of credit, which is scheduled to expire in February 2015. We cannot guarantee that 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.

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

If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating 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,

•

cyber security attacks or other disruptions to our information systems and other administrative resources required for normal operations,

•

explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation, transmission and distribution systems,

•

natural disasters that can disrupt energy generation, transmission and distribution, and

•

terrorism and other malicious threats.

As protection against operational and event risks, we maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect us against liability from all of the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform their obligations to us.

We are currently the subject of several regulatory proceedings, and we are named in multiple lawsuits related to our participation in western energy markets.

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 but not limited to 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.

Concerns over long-term global climate changes may affect our operational and financial performance.

Legislative developments and advocacy at the state, national and international levels about climate change and other environmental concerns may have significant impacts on our operations. The electric utility industry is one of the largest and most immediate industries to be more heavily regulated in some proposals. For example, various legislative proposals have been made to limit or place further restrictions on byproducts of combustion, including sulfur dioxide, nitrogen oxide, carbon dioxide, and other greenhouse gases and mercury emissions. Such proposals, if adopted, could restrict the operation and raise the cost of our power generation resources.

We expect continuing activity in the future and we are evaluating the extent that potential changes to 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,

•

restrict the types of generating plants that can be built, and

•

require construction of specific types of generation plants at higher cost.

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 alleged 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		87.0
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		562.4

Total Hydroelectric				913.6		999.4
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		61.2
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		791.4

Total Generation Properties				1,744.8		1,790.8

(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, 2010.

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

AVISTA CORPORATION

Electric Distribution and Transmission Plant

We operate approximately 18,200 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of 685 miles of 230 kV line and 1,535 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 systems also include 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, including Noxon Rapids, Cabinet Gorge and the Lancaster Plant, 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 Bonneville Power Administration (BPA), Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company. These interconnections also serve as points of delivery for power from generating facilities outside of our service area, 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 and Pend Oreille County PUD. 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, 1,950 miles in Idaho and 2,300 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 50 miles in Oregon. Our natural gas 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 249.5 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. (Removed and Reserved)

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, 2011, there were 11,102 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.

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 4, 2011, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.275 per share on the Company’s common stock. This was an increase of $0.025 per share, or 10 percent from the previous quarterly dividend of $0.25 per share.

For additional information, refer to “Notes 1, 21, 22 and 23 of Notes to Consolidated Financial Statements.”

The following table presents quarterly high and low stock prices, as well as dividend information:


	Three Months Ended
	March 31		June 30		September 30		December 31
2010
Dividends paid per common share	$	0.25	$	0.25	$	0.25	$	0.25
Trading price range per common share:
High	$	22.37	$	22.25	$	21.88	$	22.81
Low	$	19.19	$	18.46	$	19.05	$	20.90
2009
Dividends paid per common share	$	0.18	$	0.21	$	0.21	$	0.21
Trading price range per common share:
High	$	20.01	$	18.13	$	20.83	$	22.44
Low	$	12.67	$	13.44	$	17.59	$	18.48

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


(in thousands, except per share data and ratios)	Years Ended December 31,
	2010			2009			2008			2007			2006
Operating Revenues:
Avista Utilities	$	1,419,646		$	1,395,201		$	1,572,664		$	1,288,363		$	1,267,938
Advantage IQ		102,035			77,275			59,085			47,255			39,636
Other		61,067			40,089			45,014			82,139			198,737
Intersegment eliminations		(24,008	)		—			—			—			—

Total	$	1,558,740		$	1,512,565		$	1,676,763		$	1,417,757		$	1,506,311

Income (Loss) from Operations (pre-tax):
Avista Utilities	$	208,104		$	195,389		$	174,245		$	150,053		$	177,049
Advantage IQ		15,865			11,603			11,297			11,012			10,479
Other		6,219			(6,334	)		(631	)		(22,636	)		12,032

Total	$	230,188		$	200,658		$	184,911		$	138,429		$	199,560

Net income	$	94,948		$	88,648		$	74,757		$	38,727		$	72,941
Net income attributable to noncontrolling interests	$	(2,523	)	$	(1,577	)	$	(1,137	)	$	(252	)	$	—
Net Income (Loss) Attributable to Avista Corporation:
Avista Utilities	$	86,681		$	86,744		$	70,032		$	43,822		$	57,794
Advantage IQ		7,433			5,329			6,090			6,651			6,255
Other		(1,689	)		(5,002	)		(2,502	)		(11,998	)		8,892

Total	$	92,425		$	87,071		$	73,620		$	38,475		$	72,941

Average common shares outstanding, basic		55,595			54,694			53,637			52,796			49,162
Average common shares outstanding, diluted		55,824			54,942			54,028			53,263			49,897
Common shares outstanding at year-end		57,120			54,837			54,488			52,909			52,514
Earnings per Common Share Attributable to Avista Corporation:
Diluted	$	1.65		$	1.58		$	1.36		$	0.72		$	1.46

Basic	$	1.66		$	1.59		$	1.37		$	0.73		$	1.48

Dividends paid per common share	$	1.000		$	0.810		$	0.690		$	0.595		$	0.570
Book value per common share at year-end	$	19.71		$	19.17		$	18.30		$	17.27		$	17.41
Total Assets at Year-End:
Avista Utilities	$	3,589,235		$	3,400,384		$	3,434,844		$	3,009,499		$	2,895,883
Advantage IQ		221,086			143,060			125,911			108,929			100,431
Other		129,774			63,515			69,992			71,369			1,060,194

Total	$	3,940,095		$	3,606,959		$	3,630,747		$	3,189,797		$	4,056,508

Long-Term Debt (including current portion)	$	1,101,857		$	1,071,338		$	826,465		$	948,833		$	976,459
Nonrecourse Long-Term Debt of Spokane
Energy (including current portion) (1)	$	58,934		$	—		$	—		$	—		$	—
Long-Term Debt to Affiliated Trusts	$	51,547		$	51,547		$	113,403		$	113,403		$	113,403
Preferred Stock Subject to Mandatory Redemption	$	—		$	—		$	—		$	—		$	26,250
Total Avista Corporation Stockholders’ Equity	$	1,125,784		$	1,051,287		$	996,883		$	913,966		$	914,525

Ratio of Earnings to Fixed Charges (2)		2.86			2.95			2.43			1.67			2.14

(1)	Spokane Energy was consolidated effective January 1, 2010. See Note 2 of the Notes to Consolidated Financial Statements.

(2)	See Exhibit 12 for computations.

AVISTA CORPORATION

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

Business Segments

We have two reportable business segments as follows:

•

We have other businesses, including sheet metal fabrication, venture fund investments and real estate investments, Spokane Energy (which was consolidated effective January 1, 2010) as well as certain natural gas storage facilities held by Avista Energy. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including AM&D, doing business as METALfx.

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):


	2010			2009			2008
Avista Utilities	$	86,681		$	86,744		$	70,032
Advantage IQ		7,433			5,329			6,090
Other		(1,689	)		(5,002	)		(2,502	)

Net income attributable to Avista Corporation	$	92,425		$	87,071		$	73,620

Executive Level Summary

Overall

Net income attributable to Avista Corporation was $92.4 million for 2010, an increase from $87.1 million for 2009. This was primarily due to an increase in earnings at Advantage IQ and a decrease in the net loss from the other businesses. Earnings at Avista Utilities were positively impacted by general rate increases, offset by warmer weather in the heating season and an increase in interest expense, other operating expenses and depreciation and amortization.

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 reasonable 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

•

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.

In our utility operations, we continue to execute our regulatory strategy to regularly review the need for rate changes in each jurisdiction to improve the recovery of costs and capital investments in our generation, transmission and distribution infrastructure. We filed general rate increase requests in each of our jurisdictions in 2010. General rate increases went into effect in Idaho on October 1, 2010 and in Washington effective January 1, 2010 and December 1, 2010. In February 2011, we reached an all-party settlement in Oregon for a general rate increase that is subject to approval by the OPUC.

Our utility net income was $86.7 million for 2010 and 2009. Earnings for 2010 were positively impacted by an increase in gross margin (operating revenues less resource costs). The increase in gross margin was primarily due to general rate increases and power supply costs below the amount included in base retail rates in Washington, partially offset by lower retail loads (particularly for natural gas) caused by warmer weather during the heating season. The increase in gross margin was offset by an increase in interest expense, other operating expenses and depreciation and amortization.

AVISTA CORPORATION

We are continuing to invest in generation, transmission and distribution systems to enhance service reliability for our customers and replace aging infrastructure. Utility capital expenditures were $202.2 million for 2010. We expect utility capital expenditures to be about $250 million for 2011. These estimates of capital expenditures are subject to continuing review and adjustment (see discussion at “Avista Utilities Capital Expenditures”).

Advantage IQ

Advantage IQ had net income attributable to Avista Corporation of $7.4 million for 2010, an increase from $5.3 million for 2009. The increase was primarily due to moderate growth from expense management and energy management services coupled with the acquisition of Ecos Consulting, Inc. (Ecos) effective August 31, 2009. Advantage IQ’s earnings potential continues to be moderated by low short-term interest rates, which limits interest revenue on funds held for customers.

On December 31, 2010, Advantage IQ acquired substantially all of the assets and liabilities of The Loyalton Group, a Minneapolis-based energy management firm known for its energy procurement and price risk management solutions. The acquisition of The Loyalton Group was funded through available cash at Advantage IQ.

In January 2011, Advantage IQ acquired substantially all of the assets and liabilities of Building Knowledge Networks, a Seattle-based real-time building energy management services provider. The acquisition of Building Knowledge Networks was funded through available cash at 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 through the issuance of Advantage IQ common stock. The previous owners of Cadence Network can exercise a right to have their shares of Advantage IQ stock redeemed by Advantage IQ 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. As of December 31, 2010, there were redeemable noncontrolling interests of $38.1 million related to these redemption rights. Should the previous owners of Cadence Network exercise their redemption rights, Advantage IQ will seek the necessary funding through its credit facility, a capital request from existing owners, an infusion of capital from potential new investors or a combination of these sources. In January 2011, the other owners of Advantage IQ (including Avista Capital) purchased shares held by the one of the previous owners of Cadence Network (that owned 4.5 percent of Advantage IQ). Avista Capital’s portion of the purchase was $5.6 million.

We may seek to monetize all or part of our investment in Advantage IQ in the future, regardless of whether Advantage IQ’s minority owner redemption rights are exercised. The value of a potential monetization 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 such a transaction will be completed.

Other Businesses

The net loss for these operations was $1.7 million for 2010 compared to a net loss of $5.0 million for 2009. The improvement in results was due in part to increased earnings at METALfx and reduced litigation costs related to the remaining contracts and previous operations of Avista Energy. In 2010, we recorded a $2.2 million impairment of our investment in a fuel cell business that was previously a subsidiary of the Company. Also, in 2009 we recorded a $3.0 million impairment of a commercial building.

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 eliminate 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.

At December 31, 2010, we had a committed line of credit in the total amount of $320.0 million with an expiration date of April 5, 2011 under which there were $110.0 million of cash borrowings and $27.1 million in letters of credit outstanding. We also had a committed line of credit in the total amount of $75.0 million with an expiration date of April 5, 2011 under which there were no borrowings outstanding as of December 31, 2010.

As of December 31, 2010, we had a combined $257.9 million of available liquidity under our $320.0 million and $75.0 million committed lines of credit.

AVISTA CORPORATION

In February 2011, we entered into a new committed line of credit in the total amount of $400.0 million with an expiration date of February 2015 that replaced our $320.0 million and $75.0 million committed lines of credit.

In December 2010, we elected to terminate our $50.0 million accounts receivable financing facility prior to its scheduled termination date of March 2011 based on our forecasted liquidity needs. We did not borrow any funds under this facility during 2010.

In December 2010, we issued $52.0 million of 3.89 percent First Mortgage Bonds due in 2020 and $35.0 million of 5.55 percent First Mortgage Bonds due in 2040. The total net proceeds from the sale of the new bonds of $86.6 million (net of placement agent fees and before our expenses) were used to redeem $45.0 million of 6.125 percent First Mortgage Bonds due in December 2013 and $30.0 million of 7.25 percent First Mortgage Bonds due in September 2013. These First Mortgage Bonds were redeemed at par plus a make-whole redemption premium of $10.7 million. In accordance with regulatory accounting practices, the make-whole redemption premium will be amortized over the life of the new debt issued.

Also in December 2010, we issued $50.0 million of 1.68 percent First Mortgage Bonds due in 2013. The net proceeds from the issuance of the Bonds of $49.8 million (net of placement agent fees and before our expenses) were used to repay a portion of the borrowings outstanding under our committed line of credit.

We are planning, subject to market conditions, to cause the redemption of $83.7 million of Pollution Control Bonds and the refunding thereof with new bond issues in 2011. We are currently the holder of all bonds to be redeemed and refunded and, accordingly, would receive the redemption proceeds.

We are party to a sales agency agreement under which we sell shares of our common stock from time to time. In 2010, we sold 2.1 million shares for a total of $43.2 million. As of December 31, 2010, we had 1.0 million shares available to be issued under this agreement.

We expect to issue up to $25 million of common stock in 2011 in order to maintain our capital structure at an appropriate level for our business. After considering the issuances of common stock during 2011, we expect net cash flows from operating activities, together with cash available under our new $400.0 million committed line of credit agreement to provide adequate resources to fund:

•

capital expenditures,

•

dividends, and

•

other contractual commitments.

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

•

move our earned returns closer to 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 plan to file general rate cases in Washington and Idaho in the first half of 2011. 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	December 2010		7.91	%		10.2	%		46.5	%
Idaho electric and natural gas	October 2010		(1	)		(1	)		(1	)
Oregon natural gas	November 2009		8.19	%		10.1	%		50.0	%

(1)

The rate adjustment implemented on October 1, 2010 resulting from the Idaho electric and natural gas general rate case settlement did not have a specific authorized rate of return, return on equity or equity level. The prior rate case settlement implemented in August 2009 had an authorized rate of return of 8.55 percent, a return on equity of 10.5 percent and authorized equity level of 50.0 percent.

AVISTA CORPORATION

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.

In December 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 was 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 was designed to increase annual revenues by $0.6 million. The new electric and natural gas rates became effective on January 1, 2010. In this general rate case order, the WUTC did not allow us to include the costs associated with the power purchase agreement for the Lancaster Plant in rates. We subsequently filed for and received approval for deferred accounting treatment for these net costs.

In August 2010, we entered into an all-party settlement stipulation in our general rate case filed with the WUTC in March 2010. This settlement stipulation was approved by the WUTC in November 2010. As agreed to in the settlement stipulation, electric rates for Washington customers increased by an average of 7.4 percent, which was designed to increase annual revenues by $29.5 million. Natural gas rates for Washington customers increased by an average of 2.9 percent, which was designed to increase annual revenues by $4.6 million. The new electric and natural gas rates became effective on December 1, 2010. As part of the settlement, the parties agreed that Avista Corp. would not file a general rate case in the Washington jurisdiction before April 1, 2011.

The parties agreed that recovery of the deferred net costs associated with the power purchase agreement for the Lancaster Plant were limited to $6.8 million for 2010. These net deferred costs will be recovered over a five-year amortization period with a rate of return on the unamortized balance. The parties agreed that the costs for the Lancaster Plant for 2011 and going forward are reasonable and should be recovered in rates.

As part of the settlement related to the 2010 Lancaster Plant deferred net costs, the parties agreed that there would be no deferrals under the ERM for 2010 in either the surcharge or rebate direction. For 2010, we received all of the benefit from the amount of power supply costs below the level in retail rates in Washington. Deferrals under the ERM will resume in 2011. The net effect of the settlement for the Lancaster Plant deferrals and the ERM was slightly positive to 2010 earnings.

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 customers received a PGA decrease of 2.4 percent and interruptible services customers 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.

In September 2010, the IPUC approved a settlement agreement with respect to our general rate case filed in March 2010. The new electric and natural gas rates became effective on October 1, 2010. As agreed to in the settlement, base electric rates for our Idaho customers increased by an average of 9.3 percent, which was designed to increase annual revenues by $21.2 million. Base natural gas rates for our Idaho customers increased by an average of 2.6 percent, which was designed to increase annual revenues by $1.8 million.

AVISTA CORPORATION

The settlement agreement includes a rate mitigation plan under which the impact on customers of the new rates is reduced by amortizing $11.1 million ($17.5 million when grossed up for income taxes and other revenue-related items) of previously deferred state income taxes over a two-year period as a credit to customers. While our cash collections from customers are reduced by this amortization during the two-year period, the mitigation plan has no impact on our net income. Retail rates will increase on October 1, 2011 and October 1, 2012 as the previous deferred state income tax balance is amortized to zero.

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 February 2011, we entered into an all-party settlement stipulation in our general rate case that was filed with the OPUC in September 2010. The settlement, which is subject to approval by the OPUC, provides for an overall rate increase of 3.1 percent for our Oregon customers, designed to increase annual revenues by $3.0 million. Part of the rate increase would become effective March 15, 2011, with the remaining increase effective June 1, 2011. The settlement is based on an overall rate of return of 8.0 percent, with a common equity ratio of 50.0 percent and a 10.1 percent return on equity. Our original request was for an overall rate increase of 5.6 percent, designed to increase annual revenues by $5.4 million. Our original request was based on an overall rate of return of 8.61 percent, with a common equity ratio of 50.8 percent and a 10.9 percent return on equity.

Purchased Gas Adjustments

Effective November 1, 2010, natural gas rates increased 4.6 percent in Washington and 4.3 percent in Idaho, while decreasing 3.2 percent in Oregon. 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 $22.1 million as of December 31, 2010, a decrease from $40.0 million as of December 31, 2009.

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.

We recorded a potential refund liability for the 2009 tax report of $1.2 million (including interest). In October 2010, we filed the tax report for 2009 showing taxes collected to be less than taxes paid by $1.3 million before interest that would result in a surcharge (rate increase) for Oregon customers. The filing relied upon a deferred tax floor provision of the rules. In December 2010, we were notified by OPUC Staff that, although they agreed that our filing complied with the existing rules, an immediate rulemaking was necessary to eliminate the deferred tax floor provision that we used. In February 2011, we entered into a settlement stipulation that, if approved by the OPUC, would refund $1.2 million to Oregon customers for the 2009 tax report year.

Power Cost Deferrals and Recovery Mechanisms

The Energy Recovery Mechanism (ERM) is an accounting method used to track certain differences between actual power supply costs, net of the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for our Washington customers. In the 2010 Washington general rate case settlement, the parties agreed that there would be no deferrals under the ERM. Deferrals under the ERM will resume in 2011.

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:

•

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

•

the level of hydroelectric generation,

•

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

•

retail loads.

AVISTA CORPORATION

Under the ERM, 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	%

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 June 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 ERM surcharge. The surcharge was eliminated as the previous balance of deferred power costs was recovered. This resulted in a rate reduction of 7 percent for our Washington customers with no impact on our income from operations or net income.

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. In September 2010, the IPUC approved our request to increase the PCA surcharge rate to 0.532 cents per KWh effective October 1, 2010.

The following table shows activity in deferred power costs for Washington and Idaho during 2009 and 2010 (dollars in thousands):


	Washington			Idaho			Total
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
Activity from January 1 – December 31, 2010:
Power costs deferred		—			9,768			9,768
Interest and other net additions		538			26			564
Recovery of deferred power costs through retail rates		(6,802	)		(12,996	)		(19,798	)

Deferred power costs as of December 31, 2010	$	—		$	18,305		$	18,305

Natural Gas Transmission

In response to recent natural gas pipeline incidents (not within our service territory), members of the United States Congress are proposing various additional regulations to address public safety concerns.

AVISTA CORPORATION

Regulations have been proposed to require automatic shut-off valves on pipeline mains; increase installation of excess flow valves on gas service piping, increase “high consequence area” boundaries as well as to provide additional scrutiny on existing emergency preparedness plans, quality assurance plans and damage prevention programs and broader federal oversight including broader use of fines and penalties to pipeline operators.

In addition, the Pipeline and Hazardous Materials Safety Administration issued an Advisory Bulletin on January 4, 2011 to remind operators of gas and hazardous liquid pipeline facilities of their responsibilities, under federal integrity management regulations, to perform detailed threat and risk analyses especially with regards to their pipelines maximum allowable operating pressures. While we believe that we operate our pipeline systems in a safe manner, we cannot predict the impact of any future regulations or inspections of our natural gas system.

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.

2010 compared to 2009

Utility revenues increased $22.6 million due to increased electric revenues of $133.5 million, partially offset by decreased natural gas revenues of $43.2 million and intracompany revenues of $65.9 million. Wholesale electric revenues increased $77.1 million (primarily due to an increase in volumes and partially due to an increase in wholesale prices) and sales of fuel increased $73.4 million (reflecting increased thermal generation resource optimization). These increases in electric revenues were partially offset by a decrease in retail electric revenues of $20.6 million, due to a decrease in volumes and prices resulting from the elimination of the ERM surcharge, offset by general rate increases. Retail natural gas revenues decreased $98.3 million (due to decreased retail rates and decreased volumes), while wholesale natural gas revenues increased $53.8 million (due to increased volumes and wholesale prices).

Non-utility energy revenues decreased $4.4 million to $20.0 million. These revenues for 2010 primarily represent revenues for Spokane Energy (which was consolidated effective January 1, 2010) related to a long-term electric capacity contract. These revenues for 2009 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 Avista Utilities’ operations in January 2010.

Other non-utility revenues increased $27.9 million to $120.9 million primarily as a result of an Advantage IQ’s revenues increasing $24.7 million primarily due to the acquisition of Ecos in the third quarter of 2009, as well as moderate growth in expense management and energy management services. Revenues from our other businesses increased $3.2 million, primarily due to increased sales at METALfx.

Utility resource costs decreased $4.5 million as natural gas resource costs decreased $38.8 million and intracompany resource costs decreased $65.9 million, while electric resource costs increased $100.2 million. The decrease in natural gas resource costs primarily reflects the purchased gas cost adjustments implemented in the fourth quarter of 2009. The increase in electric resource costs was primarily due to an increase in fuel costs (due to an increase in thermal generation) and other fuel costs (reflecting an increase in thermal generation optimization activities).

Utility other operating expenses increased $12.6 million primarily due to increased outside services (primarily consulting costs) of $5.1 million, compensation costs of $3.6 million, as well as injuries and damages of $1.9 million.

Utility depreciation and amortization increased $6.8 million driven by additions to utility plant.

Utility taxes other than income taxes decreased $3.2 million primarily reflecting lower retail revenue related taxes, partially offset by increased property taxes.

Non-utility resource costs decreased $12.0 million. These costs for 2010 primarily represent expenses for Spokane Energy (which was consolidated effective January 1, 2010) related to a long-term electric capacity contract. These costs for 2009 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 Avista Utilities’ operations in January 2010.

Other non-utility operating expenses increased $15.9 million reflecting an increase of $19.1 million for Advantage IQ primarily due to the acquisition of Ecos in the third quarter of 2009, as well as moderate growth in expense management and energy management services. The increase was partially offset by decreased operating expenses from the other businesses due to an impairment of a commercial building of $3.0 million in 2009.

AVISTA CORPORATION

Interest expense increased $10.7 million primarily due to the consolidation of Spokane Energy (increased interest expense $5.5 million) and the issuance of $250.0 million of long-term debt in September 2009. During 2009, we carried relatively high balances on our committed line of credit at relatively low interest rates. This was replaced with long-term debt at a higher interest rate.

Interest expense to affiliated trusts decreased $1.3 million because of the redemption of $61.9 million of long-term debt to affiliated trusts in April 2009 and a decrease in the variable interest rate on the remaining debt outstanding.

Other expense-net increased $8.8 million primarily due to an increase in donations, a decrease in interest income (primarily interest on regulatory deferrals due to lower balances) and a $2.2 million impairment of our investment in a fuel cell business that was previously a subsidiary of the Company.

Income taxes increased $4.8 million and our effective tax rate was 35.0 percent for 2010 compared to 34.3 percent for 2009. This increase was due in part to an increase in income before income taxes. Adjustments associated with reconciling the 2009 federal income tax return to the amount included in the financial statements for 2009 and prior year income tax return amendments decreased income tax expense by $1.7 million for 2010 (recorded in the third quarter). In 2009, we recorded adjustments related to Internal Revenue Service (IRS) audits and adjustments for the 2008 filed federal tax return that had a favorable impact to income tax expense of $3.2 million (Avista Utilities) for 2009 (recorded in the third quarter).

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. Wholesale natural gas revenues decreased $138.1 million (due to decreased prices, offset by increased volumes) and retail natural gas revenues decreased $44.5 million (primarily due to decreased prices and partially due to decreased volumes). Retail electric revenues increased $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), while wholesale electric revenues decreased $53.3 million (due to a decrease in prices, partially offset by an increase in volumes) and sales of fuel decreased $11.7 million.

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 METALfx.

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.

AVISTA CORPORATION

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 METALfx.

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 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 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).

Avista Utilities

2010 compared to 2009

Net income for Avista Utilities was $86.7 million for 2010 and 2009. Avista Utilities’ income from operations was $208.1 million for 2010 compared to $195.4 million for 2009. The increase in income from operations was primarily due to an increase in gross margin (operating revenues less resource costs) and a decrease in taxes other than income taxes, partially offset by an increase in other 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				Intracompany					Total
	2010		2009		2010		2009		2010			2009		2010		2009
Operating revenues	$	974,283	$	840,783	$	511,249	$	554,418	$	(65,886	)	$	—	$	1,419,646	$	1,395,201
Resource costs		479,252		379,058		381,709		420,481		(65,886	)		—		795,075		799,539

Gross margin	$	495,031	$	461,725	$	129,540	$	133,937	$	—		$	—	$	624,571	$	595,662

Avista Utilities’ operating revenues increased $24.4 million and resource costs decreased $4.5 million, which resulted in an increase of $28.9 million in gross margin. The gross margin on electric sales increased $33.3 million and the gross margin on natural gas sales decreased $4.4 million. The increase in electric gross margin was due to general rate increases and power supply costs below the amount included in base retail rates in Washington, partially offset by warmer weather (during the heating season) that reduced retail loads. The decrease in our natural gas gross margin was primarily due to warmer weather that reduced retail loads, partially offset by general rate increases.

Intracompany revenues and resource costs represent purchases and sales of natural gas between our natural gas distribution operations and our electric generation operations (as fuel for our generation plants). The magnitude of these transactions in prior years was immaterial, but increased significantly in 2010 with the addition of the natural gas-fired Lancaster Plant to our electric resource mix.

AVISTA CORPORATION

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
	2010		2009		2010		2009
Residential	$	296,627	$	315,649		3,618		3,791
Commercial		265,219		273,954		3,100		3,177
Industrial		114,792		107,741		2,099		1,948
Public street and highway lighting		6,702		6,607		26		26

Total retail		683,340		703,951		8,843		8,942
Wholesale		165,553		88,414		3,803		2,354
Sales of fuel		106,375		32,992		—		—
Other		19,015		15,426		—		—

Total	$	974,283	$	840,783		12,646		11,296

Retail electric revenues decreased $20.6 million due to a decrease in total MWhs sold (decreased revenues $7.5 million) primarily due to a decrease in use per customer as a result of warmer weather in the heating season, and a decrease in revenue per MWh (decreased revenues $13.1 million). Compared to 2009, residential electric use per customer was down 5 percent and commercial use per customer decreased 3 percent. The decrease in revenue per MWh was primarily due to the elimination of the ERM surcharge in February 2010, partially offset by the Washington and Idaho general rate increases. The decrease in revenue per MWh was also due to a greater percentage of revenue derived from industrial customers.

Wholesale electric revenues increased $77.1 million due to an increase in sales prices (increased revenues $14.0 million) and an increase in sales volumes (increased revenues $63.1 million). The increase in sales volumes primarily related to increased resource optimization activities and lower than expected retail sales.

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 $73.4 million due to an increase in thermal generation resource optimization activities in 2010 as compared to 2009. In 2010, $24.7 million of these sales were made to our natural gas operations and are reflected as intracompany revenues and resource costs.

The net margin on wholesale sales and sales of fuel is applied to reduce or increase resource costs as accounted for under the ERM (no deferrals for 2010) and the PCA mechanism.

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
	2010		2009		2010		2009
Residential	$	193,169	$	251,022		188,546		207,979
Commercial		98,257		135,236		113,422		126,345
Interruptible		2,738		4,709		4,443		5,360
Industrial		3,756		5,236		5,312		5,558

Total retail		297,920		396,203		311,723		345,242
Wholesale		197,364		143,524		468,887		397,977
Transportation		6,470		6,067		142,093		144,580
Other		9,495		8,624		393		502

Total	$	511,249	$	554,418		923,096		888,301

Retail natural gas revenues decreased $98.3 million due to lower retail rates (decreased revenues $66.2 million) and volumes (decreased revenues $32.0 million). We sold less retail natural gas in 2010 as compared to 2009 primarily due to warmer weather. Compared to 2009, residential natural gas use per customer was down 10 percent and commercial use per customer decreased 11 percent. The decrease in retail rates reflects purchased gas adjustments, partially offset by general rate increases.

Wholesale natural gas revenues increased $53.8 million due to an increase in prices (increased revenues $24.0 million) and volumes (increased revenues $29.8 million). Wholesale sales reflect the sale of natural gas in excess of load requirements as part of the natural gas procurement and resource optimization process. Part of the increase in the volume of wholesale natural gas sales reflects lower than expected retail loads and the sale of excess natural gas purchased. In 2010, $41.2 million of these sales were made to our electric generation operations and are reflected as intracompany revenues and resource costs. Additionally, we engage in optimization of available interstate pipeline

AVISTA CORPORATION

transportation and storage capacity through wholesale purchases and sales of natural gas. With lower retail loads in 2010 as compared to 2009, we had more opportunity to optimize transportation resources. Differences between revenues and costs from sales of resources in excess of retail load requirements and from resource optimization 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
	2010		2009		2010		2009
Residential		315,283		313,884		282,721		280,667
Commercial		39,489		39,276		33,431		33,214
Interruptible		—		—		38		42
Industrial		1,376		1,394		254		258
Public street and highway lighting		449		444		—		—

Total retail customers		356,597		354,998		316,444		314,181

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


	2010			2009
Electric resource costs:
Power purchased	$	186,312		$	193,683
Power cost amortizations, net		2,798			31,102
Fuel for generation		142,154			89,602
Other fuel costs		114,211			31,881
Other regulatory amortizations, net		17,772			19,602
Other electric resource costs		16,005			13,188

Total electric resource costs		479,252			379,058

Natural gas resource costs:
Natural gas purchased		386,828			389,034
Natural gas cost amortizations, net		(18,741	)		20,256
Other regulatory amortizations, net		13,622			11,191

Total natural gas resource costs		381,709			420,481

Intracompany resource costs		(65,886	)		—

Total resource costs	$	795,075		$	799,539

Power purchased decreased $7.4 million due to a decrease in wholesale prices (decreased costs $38.9 million), partially offset by an increase in the volume of power purchases (increased costs $31.5 million). The increase in volumes was primarily due to purchasing power to cover for below normal hydroelectric generation, the purchased power agreement for the Lancaster Plant and an increase in wholesale sales volumes related to optimization.

Net amortization of deferred of power costs was $2.8 million for 2010 compared $31.1 million for 2009. During 2010, we recovered (collected as revenue) $6.8 million of previously deferred power costs in Washington and $13.0 million in Idaho. The Washington ERM surcharge was eliminated in February 2010, since the previous balance of deferred power costs had been recovered. During 2010, we deferred $9.8 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates. In Washington, we deferred $6.8 million of costs (included in other regulatory assets) associated with the Lancaster Project. This was the maximum deferral for 2010 as agreed to in the Washington general rate case settlement. In that settlement, the parties agreed that there would not be any deferrals under the ERM for 2010. The net effect of the settlement for the Lancaster Plant deferrals and the ERM was slightly positive to 2010 earnings.

Fuel for generation increased $52.6 million primarily due to an increase in thermal generation, including fuel for the Lancaster Plant. In 2009, we experienced an outage at Colstrip, which reduced thermal generation.

Other fuel costs increased $82.3 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 for generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel.

The expense for natural gas purchased decreased $2.2 million due to a decrease in the price of natural gas (decreased costs $20.7 million), partially offset by an increase in the total therms purchased (increased costs $18.5 million). Total therms purchased increased due to wholesale sales with the balancing of loads and resources as part of the natural gas procurement process, partially offset by decreased retail sales volumes. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During 2010, natural gas resource costs were reduced by $18.7 million reflecting the rebate of a deferred liability for natural gas costs through the purchased gas adjustments implemented in November 2009.

AVISTA CORPORATION

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.

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 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 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.

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.

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.

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
	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

Retail natural gas revenues decreased $44.5 million 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.

Wholesale natural gas revenues decreased $138.1 million due to a decrease in prices (decreased revenues $156.9 million), partially offset by an increase in volumes (increased revenues $18.8 million).

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		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		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.

AVISTA CORPORATION

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 for generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel.

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. During 2009, we amortized $20.3 million of deferred natural gas costs compared to $20.4 million for 2008.

Advantage IQ

2010 compared to 2009

Advantage IQ’s net income attributable to Avista Corporation was $7.4 million for 2010 compared to $5.3 million for 2009. Operating revenues increased $24.8 million and operating expenses increased $20.5 million. The increase in net income attributable to Avista Corporation, operating revenues and expenses was primarily due the third quarter 2009 acquisition of Ecos, as well as moderate growth in expense management and energy management services. The increase in operating expenses was also due to the amortization of intangible assets from the acquisition of Ecos. As of December 31, 2010, Advantage IQ had 534 customers representing 361,000 billed sites in North America. The decrease in billed sites at year-end 2010 as compared to year-end 2009 billed sites of 421,000 was due to the loss of a customer that had a significant number of billed sites, but represented only approximately 1 percent of annual revenues. In 2010, Advantage IQ managed bills totaling $17.3 billion, a decrease of $0.1 billion, or 0.8 percent, as compared to 2009. This decrease was primarily due to a decrease in the average value of each bill processed.

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.

Other Businesses

2010 compared to 2009

The net loss attributable to Avista Corporation from these operations was $1.7 million for 2010 compared to $5.0 million for 2009. Operating revenues increased $21.0 million, operating expenses increased $8.4 million, and interest expense increased $5.3 million. The increase in operating revenues, operating expenses and interest expense was primarily due to the consolidation of Spokane Energy effective January 1, 2010, which had no impact on the net loss attributable to Avista Corporation. The improvement in results for these businesses in 2010 was due in part to increased earnings at METALfx, which had net income of $0.8 million for 2010, compared to $0.2 million for 2009. We also had decreased litigation costs related to the remaining contracts and previous operations of Avista Energy. Losses on long-term investments were $3.3 million for 2010 compared to $0.8 million for 2009. The loss for 2010 includes a $2.2 million impairment of our investment in a fuel cell business that was previously a subsidiary of the Company. In 2009, we recorded an impairment of a commercial building of $3.0 million.

AVISTA CORPORATION

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 METALfx. The increase in operating 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 METALfx. Losses on long-term venture fund investments were $0.8 million in 2009 compared to $1.4 million in 2008. METALfx had net income of $0.2 million for 2009 compared to $0.5 million for 2008.

Accounting Standards to be Adopted in 2011

At this time, we are not expecting the adoption of accounting standards to have a material impact on our financial condition, results of operations and cash flows in 2011. For information on accounting standards adopted in 2010 and earlier periods, refer to “Note 2 of the Notes to Consolidated Financial Statements.”

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. 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 regulatory accounting practices. This 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 regulatory accounting 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

AVISTA CORPORATION

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 10 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.

Pension costs (including the SERP) were $21.3 million for 2010, $25.8 million for 2009 and $13.9 million for 2008. 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.

We have not made any changes to pension plan provisions in 2010, 2009 and 2008 that have had any significant effect on our recorded pension plan amounts. We have revised the key assumption of the discount rate in 2010, 2009 and 2008. Such changes had an effect on our pension costs in 2010, 2009 and 2008 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.

AVISTA CORPORATION

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. In 2010, we decreased the pension plan discount rate to 5.70 percent from 6.30 percent in 2009. We used a discount rate of 6.25 percent in 2008.

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. We used an expected long-term rate of return of 7.75 percent in 2010, a decrease from 8.5 percent used in 2009 and 2008. This increased pension costs in 2010 by approximately $2.0 million. The actual return on plan assets, net of fees, was a gain of $30.1 million (or 10.9 percent) for 2010, a gain of $50.1 million (or 24.4 percent) for 2009 and a loss of $63.2 million (or -25.5 percent) for 2008. We periodically analyze the estimated long-term rate of return on assets based upon revisions to the investment portfolio.

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	%	$	—	*	$	1,379
Expected long-term return on plan assets		+0.5	%		—	*		(1,379	)
Discount rate		-0.5	%		28,878			2,450
Discount rate		+0.5	%		(25,904	)		(2,226	)

*	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, 2010 by $5.2 million and the service and interest cost by $0.3 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, 2010 by $4.4 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 to the ultimate outcome of any particular contingency.

AVISTA CORPORATION

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During 2010, positive cash flows from operating activities of $228.4 million were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $202.2 million and dividends of $55.7 million. In December 2010, we issued $137.0 million of long-term debt. The net proceeds of $136.4 million from the issuance were used to redeem $75.0 million of long-term debt (plus a redemption premium of $10.7 million) and repay borrowings outstanding on our committed line of credit.

Operating Activities Net cash provided by operating activities was $228.4 million for 2010 compared to $258.8 million for 2009. Net cash used in working capital components was $20.8 million for 2010, compared to net cash provided of $31.0 million for 2009. The net cash used during 2010 primarily reflects negative cash flows from:

•

accounts receivable (representing an increase in receivables outstanding at Avista Utilities and Advantage IQ), and

•

an increase in materials and supplies, fuel stock and natural gas stored.

These negative cash flows were partially offset by net cash inflows related to accounts payable.

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).

Significant non-cash items included $9.8 million of power and natural gas cost net deferrals for 2010, a change from net amortization of $51.4 million for 2009. We also had deferred income tax expense of $37.7 million for 2010 compared to $13.9 million for 2009.

Contributions to our defined benefit pension plan were $21.0 million for 2010 compared to $48.0 million for 2009. Income tax payments were $14.2 million in 2010, a decrease compared to $22.7 million for 2009. Cash paid for interest increased to $74.2 million for 2010, compared to $58.5 million for 2009.

Investing Activities Net cash used in investing activities was $253.2 million for 2010, an increase compared to $210.2 million for 2009. Utility property capital expenditures decreased slightly for 2010 as compared to 2009, and funds held from customers at Advantage IQ increased by $48.9 million (compared to a decrease of $8.5 million for 2009). Typically, funds held from customers represents one day of deposits from customers, which are disbursed the following business day. As December 31, 2010 was a business holiday, Advantage IQ was holding two days of deposits from customers at the end of 2010.

Financing Activities Net cash provided by financing activities was $57.2 million for 2010 compared to net cash used of $35.9 million for 2009. During 2010, our short-term borrowings increased $23.0 million due to a net increase in the amount of debt outstanding under our committed line of credit. Cash dividends paid increased to $55.7 million (or $1.00 per share) for 2010 from $44.4 million (or 81 cents per share) for 2009. We issued $46.2 million of common stock during 2010, including $43.2 million under a sales agency agreement. Additionally, customer funds obligations at Advantage IQ increased by $48.9 million (see explanation under “Investing Activities”). In December 2010, we issued $137.0 million (net proceeds of $136.4 million) of long-term debt. A portion of the proceeds were used to redeem $75.0 million of long-term debt scheduled to mature in 2013. In conjunction with the redemption of long-term debt, we paid a make-whole redemption premium of $10.7 million.

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. Additionally, customer funds obligations at Advantage IQ decreased by $8.5 million.

AVISTA CORPORATION

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. Significant uses of cash flows from our utility operations include the purchase of power, fuel 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 move our earned returns closer to those allowed by regulators. 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 and natural gas 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 new $400.0 million committed line of credit.

As of December 31, 2010, we had a combined $257.9 million of available liquidity under our committed lines of credit. As we have secured a new $400.0 million credit facility with an expiration date of February 2015, we believe that we have adequate liquidity to meet our needs for the next 12 months.

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 can require collateral in the form of cash or letters of credit. Adverse price movements and/or a downgrade in our credit ratings may impact further the amount of collateral required. See “Credit Ratings” for further information. 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, 2010, that we would potentially be required to post additional collateral up to $163 million. The additional collateral amount is higher than the amount disclosed in Note 6 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.

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, 2010, we had two interest rate swap agreements outstanding with a notional amount totaling $50 million and a mandatory cash settlement date of July 2012. We have not posted any collateral under these interest rate swap agreements.

AVISTA CORPORATION

Dodd-Frank Wall Street Reform and Consumer Protection Act

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law by President Obama on July 21, 2010. The Dodd-Frank Act establishes regulatory jurisdiction by the Commodity Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) for certain swaps (which include a variety of derivative instruments) and the users of such swaps, that otherwise would have been exempted under the Commodity Exchange Dodd-Frank Act, federal securities laws and federal banking laws.

A variety of rules must be adopted by federal agencies (including the CFTC, SEC and the FERC) to implement the Dodd-Frank Act. These rules, which will be developed and implemented over timeframes as defined in the Dodd-Frank Act, could have a significant impact on Avista Corp. that was not clearly defined in the Act itself.

Under the Dodd-Frank Act, “Swap Dealers” and “Major Swap Participants” will be required to post collateral to meet minimum capital requirements as well as minimum initial and variation margin requirements, the purpose of which is to ensure the safety and soundness of the capital markets by addressing concerns brought about by the global financial crisis of 2007 and 2008. Swap Dealers and/or Major Swap Participants are persons who serve as dealers in swaps or who maintain a substantial position in swaps, for reasons other than mitigating commercial risk.

The Dodd-Frank Act also requires a broad category of swaps to be cleared and traded on registered exchanges or special derivatives exchanges. Such clearing requirements would result in a significant change from our current practice of bilateral transactions and negotiated credit terms. An exemption to such clearing requirements is outlined in the Dodd-Frank Act for end users that are not Major Swap Participants or Swap Dealers and enter into hedges to mitigate commercial risk. We expect to qualify under the end user exemption; however, concern remains that counterparties that are Swap Dealers or Major Swap Participants will pass along the increased cost and margin requirements through higher prices and reductions in unsecured credit limits.

We will continue to monitor developments and cannot predict the impact the Dodd-Frank Act may ultimately have on our operations.

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, 2010 and December 31, 2009 (dollars in thousands):


	December 31, 2010					December 31, 2009
	Amount		Percent of total			Amount		Percent of total
Current portion of long-term debt	$	358		—	%	$	35,189		1.5	%
Current portion of nonrecourse long-term debt (1)		12,463		0.5			—		—
Short-term borrowings		110,000		4.5			92,700		4.1
Long-term debt to affiliated trusts		51,547		2.1			51,547		2.3
Nonrecourse long-term debt (1)		46,471		1.9			—		—
Long-term debt		1,101,499		45.0			1,036,149		45.7

Total debt		1,322,338		54.0			1,215,585		53.6
Total Avista Corporation stockholders’ equity		1,125,784		46.0			1,051,287		46.4

Total	$	2,448,122		100.0	%	$	2,266,872		100.0	%

(1)

Nonrecourse long-term debt (including current portion) represents the long-term debt of Spokane Energy, which was consolidated effective January 1, 2010. To provide funding to acquire a long-term fixed rate electric capacity contract from Avista Corp., Spokane Energy borrowed $145.0 million from a funding trust in December 1998. The long-term debt has scheduled monthly installments and interest at a fixed rate of 8.45 percent with the final payment due in January 2015. Spokane Energy bears full recourse risk for the debt, which is secured by the electric capacity contract and $1.6 million of funds held in a trust account.

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, fuel and natural gas costs, dividends and other requirements. Our stockholders’ equity increased $74.5 million during 2010 primarily due to net income and the issuance of common stock, 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 operating needs, dividends and capital expenditures for 2011. Borrowings under our new $400.0 million committed line of credit will supplement these funds to the extent necessary.

AVISTA CORPORATION

We are planning to issue up to $25 million of common stock in 2011 in order to maintain our capital structure at an appropriate level for our business. We are party to a sales agency agreement under which we sell shares of our common stock from time to time. In 2010 we sold a total of 2.1 million shares for a total of $43.2 million. As of December 31, 2010, we had 1.0 million shares available to be issued under this agreement.

At December 31, 2010, we had a committed line of credit in the total amount of $320.0 million with an expiration date of April 2011. Additionally, at December 31, 2010, we had a committed line of credit in the total amount of $75.0 million with an expiration date of April 2011.

Our committed line of credit agreements contain customary covenants and default provisions. The $320.0 million and $75.0 million credit agreements had a covenant that required 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, 2010, we were in compliance with this covenant with a ratio of 4.13 to 1. The new $400.0 million committed line of credit does not have this covenant. The $320.0 million and $75.0 million committed line of credit agreements had a covenant which did 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, 2010, we were in compliance with this covenant with a ratio of 54.0 percent. Under the new $400.0 million committed line of credit, this ratio must not be greater than 65 percent at any time.

Balances outstanding and interest rates of borrowings (excluding letters of credit) under our revolving committed lines of credit were as follows as of and for the years ended December 31 (dollars in thousands):


	2010			2009			2008
Balance outstanding at end of period	$	110,000		$	87,000		$	250,000
Letters of credit outstanding at end of period	$	27,126		$	28,448		$	24,325
Maximum balance outstanding during the period	$	170,000		$	275,000		$	250,000
Average balance outstanding during the period	$	80,230		$	186,474		$	48,426
Average interest rate during the period		0.60	%		0.65	%		3.04	%
Average interest rate at end of period		0.57	%		0.59	%		0.81	%

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. Avista Corp. does not guarantee the indebtedness of any of its subsidiaries. As of December 31, 2010, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements.

We are restricted under our Restated Articles of Incorporation as to the additional preferred stock we can issue. As of December 31, 2010, we could issue $724.9 million of additional preferred stock at an assumed dividend rate of 8.5 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.

However, 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, 2010, our property additions and retired bonds would have allowed us to issue $795.3 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, 2010, the net earnings test would limit the principal amount of additional bonds we could issue to $758.8 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 $626.9 million for the years 2008 through 2010. We expect utility capital expenditures to be $250 million for 2011, and between $230 million and $240 million for each of 2012 and 2013. The increase in capital expenditures from $202.2 million in 2010 to $250 million in 2011 is primarily due to hydroelectric generation plant upgrades, smart grid projects and a slight increase in customer growth. Our capital budget for 2011 includes the following (dollars in millions):


Transmission and distribution	$	68
Generation		42
Customer growth		40
Information technology		28
Smart grid		19
Natural gas		16
Environmental		12
Other		25

Total	$	250

These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

We applied to the Smart Grid Investment Grant program under the American Recovery and Reinvestment Act (the ARRA) of 2009, proposing a 50 percent cost share for the deployment of smart grid enabling technologies in the Spokane area. In October 2009, we were selected to negotiate a grant under this stimulus program. The grant is for $20 million and our contribution will be $22 million, the majority of which will be spent over a three-year period. We finalized the grant agreement with the Department of Energy in March 2010.

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. The funding agreement was finalized in September 2010. 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 $15 million, the majority of which will be spent over a three-year period.

In February 2011, we issued a request for proposals (RFP) seeking to acquire up to 35 aMW of renewable energy, or as much as 100 MW of nameplate wind capacity with deliveries beginning in 2012. We completed the acquisition of the development rights for a wind generation site in 2008. While this RFP does not include the development of this site, we will continue to study this site in preparation for later development.

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

We are continuing our participation in planning activities for the development of a proposed 1,000-3,000 MW transmission project that would extend from British Columbia, Canada to Northern California. The project would be implemented in two sections; one from Canada to northeastern Oregon (the northern section) and then on into California (the southern section). Western Area Power Administration is leading the development on the southern section and is working with Pacific Gas and Electric, Transmission Agency of Northern California and others. British Columbia Transmission Corporation is leading the development effort on the northern section. The participants have received a Western Electricity Coordinating Council (WECC) Phase I Rating for both sections of the project, and Avista Corp. is working on a WECC Phase II Rating for an interconnection from the project to the Avista Corp. transmission system. We have contributed $0.7 million to the project to date with no additional funding anticipated in 2011.

Advantage IQ Credit Agreement

As of December 31, 2010, Advantage IQ had a $15.0 million committed credit agreement with an expiration date of February 2011 that had no borrowings outstanding. 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. In February 2011, Advantage IQ extended the expiration date of this credit agreement to May 2011. Advantage IQ is in the process of evaluating alternatives and expects to have a new credit facility in place prior to the May 2011 expiration of its current credit agreement.

AVISTA CORPORATION

Advantage IQ Redeemable Stock

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. As the repurchase feature is at the discretion of the minority shareholders and option holders, there were redeemable noncontrolling interests of $8.6 million as of December 31, 2010 for the intrinsic value of stock options outstanding, as well as outstanding redeemable stock. In 2009, the Advantage IQ employee stock incentive plan was amended such that, on a prospective basis, not all options granted under the plan have the put right. Additionally, there were redeemable noncontrolling interests of $38.1 million related to the Cadence Network acquisition, as the previous owners can exercise a right to put their stock back to Advantage IQ in 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. Should the previous owners of Cadence Network exercise their redemption rights, Advantage IQ will seek the necessary funding through its credit facility, a capital request from existing owners, an infusion of capital from potential new investors or a combination of these sources. In January 2011, the other owners of Advantage IQ (including Avista Capital) purchased shares held by the one of the previous owners of Cadence Network (that owned 4.5 percent of Advantage IQ). Avista Capital’s portion of the purchase was $5.6 million.

Accounts Receivable Financing Facility

On December 30, 2010, Avista Corp., Avista Receivables Corporation (ARC), Bank of America, N.A. and Ranger Funding Company, LLC terminated a Receivables Purchase Agreement at the direction of the Company. ARC is a wholly owned, bankruptcy-remote subsidiary of the Company formed in 1997 for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. We elected to terminate the Receivables Purchase Agreement prior to its March 11, 2011 expiration date based on our forecasted liquidity needs. The Receivables Purchase Agreement was originally entered into on May 29, 2002 (and was renewed on an annual basis) and provided us with funds for general corporate needs. Under the Receivables Purchase Agreement, we could borrow up to $50.0 million based on calculations of eligible receivables. We did not borrow any funds under this revolving agreement in 2010.

Off-Balance Sheet Arrangements

As of December 31, 2010, we had $27.1 million in letters of credit outstanding under our $320.0 million committed line of credit, a decrease from $28.4 million as of December 31, 2009.

Pension Plan

As of December 31, 2010, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. In 2009 and 2010, the fair value of pension plan assets increased due to market returns and our contributions, offset by benefit payments. We contributed $21 million to the pension plan in 2010. We expect to contribute $26 million to the pension plan in 2011. 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 benefit obligation).

Credit Ratings

Our access to capital markets and our cost of capital are directly affected by our credit ratings. In addition, many of our contracts for the purchase and sale of energy commodities contain terms dependent upon our credit ratings. See “Credit and Nonperformance Risk” and “Note 6 of the Notes to Consolidated Financial Statements.” The following table summarizes our credit ratings as of February 25, 2011:


	Standard & Poor’s (1)		Moody’s (2)
Avista Corporation
Corporate/Issuer rating		BBB-		Baa3
Senior secured debt		BBB+		Baa1
Senior unsecured debt		N/A (3)		Baa3

Rating outlook		Positive		Positive (4)

(1)	Standard & Poor’s lowest level of “investment grade” credit rating is BBB-.

(2)	Moody’s lowest level of “investment grade” credit rating is Baa3.

AVISTA CORPORATION

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

(4)	In February 2011, Moody’s placed the ratings for Avista Corporation on review for possible upgrade.

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 in the context of the applicable methodology, independent of all other ratings. The rating agencies provide ratings at the request of Avista Corporation and charge us fees for their services.

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.

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

In February 2011, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.275 per share on the Company’s common stock. This was an increase of $0.025 per share, or 10 percent from the previous quarterly dividend of $0.25 per share.

Contractual Obligations

The following table provides a summary of our future contractual obligations as of December 31, 2010 (dollars in millions):


	2011		2012		2013		2014		2015		Thereafter
Avista Utilities:
Long-term debt maturities	$	—	$	7	$	50	$	—	$	—	$	1,042
Long-term debt to affiliated trusts		—		—		—		—		—		52
Interest payments on long-term debt (1)		61		61		60		60		60		611
Short-term borrowings		110		—		—		—		—		—
Energy purchase contracts (2)		356		260		203		171		154		1,299
Public Utility District contracts (2)		3		3		3		3		2		28
Operating lease obligations (3)		1		1		1		1		—		2
Other obligations (4)		22		23		23		23		25		252
Information services contracts		13		12		9		8		7		14
Pension plan funding (5)		26		30		33		28		21		—
Spokane Energy:
Nonrecourse long-term debt maturities		12		14		15		16		1		—
Interest payments on nonrecourse long-term debt		5		3		2		1		—		—
Avista Capital (consolidated):
Redeemable noncontrolling interests (6)		47		—		—		—		—		—
Venture funds investments (7)		2		2		—		—		—		—
Operating lease obligations (3)		3		3		3		3		1		4

Total contractual obligations	$	661	$	419	$	402	$	314	$	271	$	3,304