10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)

Washington	91-0462470
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1411 East Mission Avenue, Spokane, Washington	99202-2600
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: 509-489-0500

Web site: http://www.avistacorp.com

None

(Former name, former address and former fiscal year, if changed since last report)

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 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):

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):    Yes  ¨    No  x

As of April 30, 2011, 57,629,393 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.

AVISTA CORPORATION

Index

			Page No.
Part I.	Financial Information:
	Item 1.	Condensed Consolidated Financial Statements
		Condensed Consolidated Statements of Income - Three Months Ended March 31, 2011 and 2010		5
		Condensed Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2011 and 2010		6
		Condensed Consolidated Balance Sheets - March 31, 2011 and December 31, 2010		7
		Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2011 and 2010		9
		Condensed Consolidated Statements of Equity and Redeemable Noncontrolling Interests- Three Months Ended March 31, 2011 and 2010		10
		Notes to Condensed Consolidated Financial Statements		11
		Report of Independent Registered Public Accounting Firm		30
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk		49
	Item 4.	Controls and Procedures		50
Part II.	Other Information:
	Item 1.	Legal Proceedings		51
	Item 1A.	Risk Factors		51
	Item 6.	Exhibits		51
Signature				52

2

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 Quarterly Report on Form 10-Q), 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 Quarterly Report on Form 10-Q) are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and they could have a significant effect on our operations, results of operations, financial condition or cash flows. This could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:

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

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

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

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

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

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

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

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

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

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

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

• the outcome of legal proceedings and other contingencies;

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

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

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

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

• 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;

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

• 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, cyber security attacks or vandalism that damage or disrupt information technology systems;

3

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

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

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

• the loss of key suppliers for materials or services;

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

• deterioration in the creditworthiness of our customers and counterparties;

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

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

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

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

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

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

• changes in tax rates and/or policies; and

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

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.

4

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands, except per share amounts

(Unaudited)

	2011			2010
Operating Revenues:
Utility revenues	$	437,697		$	423,581
Other non-utility revenues		38,889			32,834
Total operating revenues		476,586			456,415
Operating Expenses:
Utility operating expenses:
Resource costs		248,121			259,567
Other operating expenses		59,682			55,749
Depreciation and amortization		25,852			24,330
Taxes other than income taxes		24,993			21,171
Non-utility operating expenses:
Other operating expenses		31,246			25,958
Depreciation and amortization		1,867			1,816
Total operating expenses		391,761			388,591
Income from operations		84,825			67,824
Interest expense		(18,440	)		(19,115	)
Interest expense to affiliated trusts		(151	)		(146	)
Capitalized interest		438			320
Other expense-net		(632	)		(1,699	)
Income before income taxes		66,040			47,184
Income tax expense		23,637			17,867
Net income		42,403			29,317
Less: Net income attributable to noncontrolling interests		(485	)		(507	)
Net income attributable to Avista Corporation	$	41,918		$	28,810
Weighted-average common shares outstanding (thousands), basic		57,342			54,869
Weighted-average common shares outstanding (thousands), diluted		57,414			55,115
Earnings per common share attributable to Avista Corporation:
Basic	$	0.73		$	0.53
Diluted	$	0.73		$	0.52
Dividends paid per common share	$	0.275		$	0.25

The Accompanying Notes are an Integral Part of These Statements.

5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2011			2010
Net income	$	42,403		$	29,317
Other Comprehensive Income (Loss):
Change in unfunded benefit obligation for pension and other postretirement benefit plans - net of taxes of $(106) and $19, respectively		(196	)		36
Total other comprehensive income (loss)		(196	)		36
Comprehensive income		42,207			29,353
Comprehensive income attributable to noncontrolling interests		(485	)		(507	)
Comprehensive income attributable to Avista Corporation	$	41,722		$	28,846

The Accompanying Notes are an Integral Part of These Statements.

6

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)

	March 31,		December 31,
	2011		2010
Assets:
Current Assets:
Cash and cash equivalents	$	61,837	$	69,413
Accounts and notes receivable-less allowances of $44,165 and $44,883		218,436		230,229
Utility energy commodity derivative assets		3,176		2,592
Regulatory asset for utility derivatives		33,966		48,891
Funds held for customers		52,908		100,543
Materials and supplies, fuel stock and natural gas stored		38,397		48,530
Deferred income taxes		26,298		28,822
Income taxes receivable		384		19,069
Other current assets		29,757		31,476
Total current assets		465,159		579,565
Net Utility Property:
Utility plant in service		3,725,511		3,713,885
Construction work in progress		66,593		62,051
Total		3,792,104		3,775,936
Less: Accumulated depreciation and amortization		1,060,961		1,061,699
Total net utility property		2,731,143		2,714,237
Other Non-current Assets:
Investment in exchange power-net		20,621		21,233
Investment in affiliated trusts		11,547		11,547
Goodwill		25,965		25,935
Long-term energy contract receivable of Spokane Energy		69,835		62,525
Other property and investments-net		75,652		74,553
Total other non-current assets		203,620		195,793
Deferred Charges:
Regulatory assets for deferred income tax		88,667		90,025
Regulatory assets for pensions and other postretirement benefits		176,382		178,985
Other regulatory assets		107,107		112,830
Non-current utility energy commodity derivative assets		17,789		15,261
Non-current regulatory asset for utility derivatives		2,079		15,724
Power deferrals		10,283		18,305
Other deferred charges		21,556		19,370
Total deferred charges		423,863		450,500
Total assets	$	3,823,785	$	3,940,095

The Accompanying Notes are an Integral Part of These Statements.

7

CONDENSED CONSOLIDATED BALANCE SHEETS (continued)

Avista Corporation

Dollars in thousands

(Unaudited)

	March 31,			December 31,
	2011			2010
Liabilities and Equity:
Current Liabilities:
Accounts payable	$	150,648		$	171,707
Customer fund obligations		52,908			100,543
Current portion of long-term debt		360			358
Current portion of nonrecourse long-term debt of Spokane Energy		12,754			12,463
Short-term borrowings		65,000			110,000
Utility energy commodity derivative liabilities		37,142			51,483
Natural gas deferrals		15,466			22,074
Other current liabilities		119,837			110,547
Total current liabilities		454,115			579,175
Long-term debt		1,101,814			1,101,499
Nonrecourse long-term debt of Spokane Energy		43,164			46,471
Long-term debt to affiliated trusts		51,547			51,547
Regulatory liability for utility plant retirement costs		224,403			223,131
Pensions and other postretirement benefits		157,698			161,189
Deferred income taxes		492,295			495,474
Other non-current liabilities and deferred credits		96,125			109,703
Total liabilities		2,621,161			2,768,189
Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Redeemable Noncontrolling Interests		42,817			46,722
Equity:
Avista Corporation Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 57,622,218 and 57,119,723 shares outstanding		833,617			827,592
Accumulated other comprehensive loss		(4,522	)		(4,326	)
Retained earnings		331,284			302,518
Total Avista Corporation stockholders’ equity		1,160,379			1,125,784
Noncontrolling Interests		(572	)		(600	)
Total equity		1,159,807			1,125,184
Total liabilities and equity	$	3,823,785		$	3,940,095

The Accompanying Notes are an Integral Part of These Statements.

8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2011			2010
Operating Activities:
Net income.	$	42,403		$	29,317
Non-cash items included in net income:
Depreciation and amortization		27,719			26,146
Provision for deferred income taxes		966			4,155
Power and natural gas cost amortizations (deferrals), net		3,950			(6,342	)
Amortization of debt expense and premium		1,236			1,051
Equity-related AFUDC		(842	)		(410	)
Other		12,650			12,573
Contributions to defined benefit pension plan		(8,500	)		(7,000	)
Changes in working capital components:
Accounts and notes receivable		12,505			10,344
Materials and supplies, fuel stock and natural gas stored		10,222			5,602
Other current assets		10,509			12,599
Accounts payable		(16,674	)		(9,174	)
Other current liabilities		7,118			2,193
Net cash provided by operating activities		103,262			81,054
Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(49,654	)		(42,552	)
Other capital expenditures		(474	)		(465	)
Federal grant payments received		4,353			—
Cash paid by subsidiary for acquisition, net of cash received		(199	)		—
Decrease (increase) in funds held for customers		47,635			(2,584	)
Other		(1,502	)		(1,733	)
Net cash provided by (used in) investing activities		159			(47,334	)
Financing Activities:
Net decrease in short-term borrowings		(45,000	)		(17,000	)
Borrowings from Advantage IQ line of credit		—			1,000
Repayment of borrowings from Advantage IQ line of credit		—			(1,400	)
Redemption and maturity of long-term debt		(95	)		(59	)
Maturity of nonrecourse long-term debt of Spokane Energy		(3,016	)		(2,752	)
Long-term debt and short-term borrowing issuance costs		(2,303	)		(33	)
Issuance of common stock		8,458			374
Cash dividends paid		(15,780	)		(13,753	)
Purchase of subsidiary noncontrolling interest		(5,639	)		—
Increase (decrease) in customer fund obligations		(47,635	)		2,584
Other		13			(113	)
Net cash used in financing activities		(110,997	)		(31,152	)
Net increase (decrease) in cash and cash equivalents		(7,576	)		2,568
Cash and cash equivalents at beginning of period		69,413			37,035
Cash and cash equivalents at end of period	$	61,837		$	39,603
Supplemental Cash Flow Information:
Cash paid (received) during the year:
Interest	$	6,433		$	8,075
Income taxes		2,200			(136	)
Non-cash financing and investing activities:
Accounts payable for capital expenditures		3,963			3,481
Utility property acquired under capital leases		—			5,300
Redeemable noncontrolling interests		(2,429	)		4,579

The Accompanying Notes are an Integral Part of These Statements.

9

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

AND REDEEMABLE NONCONTROLLING INTERESTS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)

	2011			2010
Common Stock, Shares:
Shares outstanding at beginning of period		57,119,723			54,836,781
Issuance of common stock		502,495			57,559
Shares outstanding at end of period		57,622,218			54,894,340
Common Stock, Amount:
Balance at beginning of period	$	827,592		$	778,647
Equity compensation expense		889			729
Issuance of common stock, net of issuance costs		8,458			375
Equity transactions of consolidated subsidiaries		(3,322	)		77
Balance at end of period	$	833,617		$	779,828
Accumulated Other Comprehensive Income (Loss):
Balance at beginning of period	$	(4,326	)	$	(2,350	)
Other comprehensive income (loss)		(196	)		36
Balance at end of period	$	(4,522	)	$	(2,314	)
Retained Earnings:
Balance at beginning of period	$	302,518		$	274,990
Net income attributable to Avista Corporation		41,918			28,810
Cash dividends paid (common stock)		(15,780	)		(13,753	)
Valuation adjustments and other noncontrolling interests activity		2,628			(4,109	)
Balance at end of period	$	331,284		$	285,938
Total Avista Corporation stockholders’ equity	$	1,160,379		$	1,063,452
Noncontrolling Interests:
Balance at beginning of period	$	(600	)	$	(673	)
Net income (loss) attributable to noncontrolling interests		33			(3	)
Other		(5	)		6
Balance at end of period	$	(572	)	$	(670	)
Total equity	$	1,159,807		$	1,062,782
Redeemable Noncontrolling Interests:
Balance at beginning of period	$	46,722		$	34,833
Net income attributable to noncontrolling interests		452			510
Purchase of subsidiary noncontrolling interests		(5,639	)		—
Valuation adjustments and other noncontrolling interests activity		1,282			4,606
Balance at end of period	$	42,817		$	39,949

The Accompanying Notes are an Integral Part of These Statements.

10

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

The accompanying condensed consolidated financial statements of Avista Corporation (Avista Corp. or the Company) for the interim periods ended March 31, 2011 and 2010 are unaudited; however, in the opinion of management, the statements reflect all adjustments necessary for a fair statement of the results for the interim periods. The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company’s audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (2010 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2010 Form 10-K for definitions of terms. The acronyms and terms are an integral part of these condensed consolidated financial statements.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy, as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeast and southwest Oregon. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses, except Spokane Energy, LLC. Avista Capital’s subsidiaries include Advantage IQ, Inc. (Advantage IQ), a 79 percent owned subsidiary as of March 31, 2011. Advantage IQ is a provider of energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities throughout North America. See Note 12 for business segment information.

Basis of Reporting

The condensed consolidated financial statements include the assets, liabilities, revenues and expenses of the Company and its subsidiaries, including Advantage IQ and other majority owned subsidiaries and variable interest entities for which the Company or its subsidiaries are the primary beneficiaries. Intercompany balances were eliminated in consolidation. The accompanying condensed consolidated financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

Taxes Other Than Income Taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled the following amounts for the three months ended March 31 (dollars in thousands):

	2011		2010
Utility taxes	$	18,123	$	16,021

Other Expense - Net

Other expense - net consisted of the following items for the three months ended March 31 (dollars in thousands):

	2011			2010
Interest income	$	289		$	298
Interest on regulatory deferrals		45			71
Equity-related AFUDC		842			410
Net gain (loss) on investments		103			(633	)
Other expense		(1,911	)		(1,967	)
Other income		—			122
Total	$	(632	)	$	(1,699	)

11

AVISTA CORPORATION

Goodwill

Goodwill arising from acquisitions represents the excess of the purchase price over the estimated fair value of net assets acquired. The Company evaluates goodwill for impairment using a discounted cash flow model on at least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for potential impairment as of November 30, 2010 for the other businesses and as of December 31, 2010 for Advantage IQ and determined that goodwill was not impaired at that time. The changes in the carrying amount of goodwill are as follows (dollars in thousands):

					Accumulated
	Advantage				Impairment
	IQ		Other		Losses			Total
Balance as of the December 31, 2010	$	20,689	$	12,979	$	(7,733	)	$	25,935
Adjustments		30		—		—			30
Balance as of the March 31, 2011	$	20,719	$	12,979	$	(7,733	)	$	25,965

Accumulated impairment losses are attributable to the other businesses.

Other Intangibles

Other Intangibles primarily represent the amounts assigned to client relationships related to the Advantage IQ acquisition of Cadence Network in 2008 (estimated amortization period of 12 years), Ecos in 2009 (estimated amortization period of 3 years) and The Loyalton Group in 2010 (estimated amortization period of 6 years), software development costs (estimated amortization period of 5 to 7 years) and other. Other Intangibles are included in other property and investments - net on the Condensed Consolidated Balance Sheets. Amortization expense related to Other Intangibles was as follows for the three months ended March 31 (dollars in thousands):

	2011		2010
Other intangible amortization	$	900	$	941

The following table details the future estimated amortization expense related to Other Intangibles for each of the five years ending December 31 (dollars in thousands):

	2011		2012		2013		2014		2015
Estimated amortization expense	$	3,421	$	4,099	$	3,384	$	2,727	$	1,696

The gross carrying amount and accumulated amortization of Other Intangibles as of March 31, 2011 and December 31, 2010 are as follows (dollars in thousands):

	March 31,			December 31,
	2011			2010
Client relationships	$	11,459		$	11,459
Software development costs		19,598			19,139
Other		1,450			1,450
Total other intangibles		32,507			32,048
Client relationships accumulated amortization		(2,517	)		(2,156	)
Software development costs accumulated amortization		(9,487	)		(8,985	)
Other accumulated amortization		(832	)		(806	)
Total accumulated amortization		(12,836	)		(11,947	)
Total other intangibles - net	$	19,671		$	20,101

Regulatory Deferred Charges and Credits

The Company prepares its condensed consolidated financial statements in accordance with regulatory accounting practices because:

• rates for regulated services are established by or subject to approval by independent third-party regulators,

• the regulated rates are designed to recover the cost of providing the regulated services, and

• in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged to and collected from customers at levels that will recover costs.

Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not currently included in rates, but expected to be recovered or refunded in the future) are reflected as deferred charges or credits on the Condensed Consolidated Balance Sheets. These costs and/or obligations are not reflected in the Condensed Consolidated Statements of Income until the period during which matching revenues are recognized.

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If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:

• required to write off its regulatory assets, and

• precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the Company expected to recover such costs in the future.

NOTE 2. NEW ACCOUNTING STANDARDS

Effective January 1, 2010, the Company adopted Accounting Standards Update (ASU) No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” This ASU amends guidance related to the disclosures of fair value measurements. In particular, it amends Accounting Standards Codification (ASC) 820-10 to clarify existing disclosures and provides for further disaggregation within classes of assets and liabilities, and further disclosure about inputs and valuation techniques. It also requires disclosure of significant transfers between Level 1 and Level 2 within the fair value hierarchy and separate disclosure of purchases, sales, issuances and settlements in the reconciliation of Level 3 activity (this is required beginning in 2011). See Note 9 for the Company’s fair value disclosures.

NOTE 3. VARIABLE INTEREST ENTITIES

The Company has a power purchase agreement (PPA) for the purchase of all the output of the Lancaster Plant, a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party (Rathdrum Power LLC), through 2026. Beginning in July 2007 through the end of 2009, the majority of the rights and obligations under the PPA were conveyed to Shell Energy in connection with the sale of the majority of Avista Energy’s contracts and ongoing operations to Shell Energy. These rights and obligations were conveyed to Avista Corp. (Avista Utilities) beginning in January 2010. Effective December 1, 2010, the rights and obligations under the PPA were assigned to Avista Corp.

Avista Corp. has a variable interest in the PPA. Accordingly, Avista Corp. made an evaluation of which interest holders have the power to direct the activities that most significantly impact the economic performance of the entity and which interest holders have the obligation to absorb losses or receive benefits that could be significant to the entity. Avista Corp. pays a fixed capacity and operations and maintenance payment and certain monthly variable costs under the PPA. Under the terms of the PPA, Avista Corp. makes the dispatch decisions, provides all natural gas fuel and receives all of the electric energy output from the Lancaster Plant. However, Rathdrum Power LLC (the owner) controls the daily operation of the Lancaster Plant and makes operating and maintenance decisions. Rathdrum Power LLC controls all of the rights and obligations of the Lancaster Plant after the expiration of the PPA in 2026. It is estimated that the plant will have 15 to 25 years of useful life after that time. Rathdrum Power LLC bears the maintenance risk of the plant and will receive the residual value of the Lancaster Plant. Avista Corp. has no debt or equity investments in the Lancaster Plant and does not provide financial support through liquidity arrangements or other commitments (other than the PPA). Based on its analysis, Avista Corp. does not consider itself to be the primary beneficiary of the Lancaster Plant. Accordingly, neither the Lancaster Plant nor Rathdrum Power LLC is included in Avista Corp.’s condensed consolidated financial statements. The Company has a future contractual obligation of approximately $357 million under the PPA (representing the fixed capacity and operations and maintenance payments through 2026) and believes this would be its maximum exposure to loss. However, the Company believes that such costs will be recovered through retail rates.

The implementation of amendments to ASC 810 resulted in the Company including Spokane Energy, LLC (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.

Spokane Energy borrowed $145.0 million from a funding trust and paid $143.4 million to Avista Corp. to acquire its rights under the contract. The loan, which matures in January 2015, is structured so that Spokane Energy is the sole obligor. Avista Corp. has no obligation or liability related to this loan.

The cost of acquiring the energy contract is being amortized and matched with sales revenue over the life of the contract using the effective interest method. Avista Corp. acts as the servicer under the contract and performs scheduling, billing and collection functions.

Pursuant to orders from the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC), Avista Corp. fully amortized the $143.4 million received by the end of 2002.

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Prior to 2010, Avista Corp. did not consolidate Spokane Energy because Spokane Energy met the definition of a qualified special purpose entity (QSPE). As the amendments to ASC 810 and 860 eliminated the concept of a QSPE, Avista Corp. evaluated Spokane Energy for consolidation as a variable interest entity and determined that it was required to consolidate the entity. This determination was based primarily on Avista Corp. controlling the activities of Spokane Energy, owning all of the member capital of Spokane Energy, and receiving the majority of the residual benefits upon liquidation of the entity.

NOTE 4. REDEEMABLE NONCONTROLLING INTERESTS AND ADVANTAGE IQ ACQUISITIONS

Advantage IQ’s acquisition of Cadence Network effective July 2, 2008 was funded with the issuance of Advantage IQ common stock. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to have their shares of Advantage IQ common stock redeemed during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties. Additionally, certain minority shareholders and option holders of Advantage IQ have the right to put their shares back to Advantage IQ at their discretion during an annual put window. The following details redeemable noncontrolling interests as of March 31, 2011 and December 31, 2010 (dollars in thousands):

	March 31,		December 31,
	2011		2010
Previous owners of Cadence Network	$	33,567	$	38,098
Stock options and other outstanding redeemable stock		9,250		8,624
Total redeemable noncontrolling interests	$	42,817	$	46,722

In January 2011, Avista Capital purchased shares held by one of the previous owners of Cadence Network for $5.6 million.

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

The acquired assets and liabilities assumed of Loyalton were preliminarily recorded at their respective estimated fair values as of the date of acquisition. Final accounting is pending the completion of further review of the fair values of the relevant assets and liabilities identified as of the acquisition date. The results of operations of Loyalton are included in the condensed consolidated financial statements beginning January 1, 2011. Pro forma disclosures reflecting the effects of the acquisition of Loyalton are not presented, as the acquisition is not material to Avista Corp.’s condensed consolidated financial condition or results of operations.

In January 2011, Advantage IQ acquired substantially all of the assets and liabilities of Building Knowledge Networks (BKN), a Seattle-based real-time building energy management services provider. The acquisition of BKN was funded through available cash at Advantage IQ. Pro forma disclosures reflecting the effects of the acquisition of BKN are not presented, as the acquisition is not material to Avista Corp.’s condensed consolidated financial condition or results of operations.

NOTE 5. DERIVATIVES AND RISK MANAGEMENT

Energy Commodity Derivatives

Avista Utilities is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Market risk may also be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of, or demand for, the commodity. Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. The Company’s Risk Management Committee establishes the Company’s energy resources risk policy and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other members of management. The Audit Committee of the Company’s Board of Directors periodically reviews and discusses risk assessment and risk management policies, including the Company’s material financial and accounting risk exposures and the steps management has undertaken to control them.

As part of its resource procurement and management operations in the electric business, Avista Utilities engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Utilities’ load obligations and the use of these resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy and fuel as part of the process of acquiring and balancing resources to serve its load obligations. These transactions range from terms of one hour up to multiple years.

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Avista Utilities makes continuing projections of:

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

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

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

• purchasing fuel for generation,

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

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

Avista Utilities’ optimization process includes entering into hedging transactions to manage risks.

As part of its resource procurement and management operations in the natural gas business, Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations to Avista Utilities’ distribution system. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, Avista Utilities plans and executes a series of transactions to hedge a significant portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as much as four natural gas operating years (November through October) into the future. Avista Utilities also leaves a significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets. Natural gas resource optimization activities include:

• wholesale market sales of surplus natural gas supplies,

• optimization of interstate pipeline transportation capacity not needed to serve daily load, and

• sales of excess natural gas storage capacity.

Derivatives are recorded as either assets or liabilities on the balance sheet measured at estimated fair value. In certain defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on the intended use of the derivatives and the resulting designation.

The WUTC and the IPUC issued accounting orders authorizing Avista Utilities 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 Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Condensed Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA) mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through future rates.

Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary.

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The following table presents the underlying energy commodity derivative volumes as of March 31, 2011 that are expected to settle in each respective year (in thousands of MWhs and mmBTUs):

	Purchases								Sales
	Electric Derivatives				Gas Derivatives				Electric Derivatives				Gas Derivatives
	Physical		Financial		Physical		Financial		Physical		Financial		Physical		Financial
Year	MWH		MWH		mmBTUs		mmBTUs		MWH		MWH		mmBTUs		mmBTUs
2011		860		792		31,968		61,343		407		68		13,641		63,858
2012		788		1,215		12,963		41,427		286		194		1,528		41,972
2013		398		1,082		6,190		37,873		254		614		1,533		31,947
2014		366		—		2,483		1,655		286		—		1,050		—
2015		379		—		675		450		286		—		—		—
Thereafter		1,315		—		—		—		1,017		—		—		—

Foreign Currency Exchange Contracts

A significant portion of Avista Utilities’ natural gas supply (including fuel for power generation) is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Utilities’ short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within sixty days with U.S. dollars. Avista Utilities economically hedges a portion of the foreign currency risk by purchasing Canadian currency contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company’s financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of March 31, 2011 and December 31, 2010 (dollars in thousands):

	March 31,		December 31,
	2011		2010
Number of contracts		42		29
Notional amount (in United States dollars)	$	20,487	$	10,916
Notional amount (in Canadian dollars)		20,021		10,989
Derivative in other current assets		72		116

Interest Rate Swap Agreements

Avista Corp. enters into forward-starting interest rate swap agreements to manage the risk associated with changes in interest rates and the impact on future interest payments. These interest rate swap agreements relate to the interest payments for anticipated debt issuances. These interest rate swap agreements are considered economic hedges against fluctuations in future cash flows associated with changes in interest rates.

The following table summarizes the interest rate swaps that the Company has entered into as of March 31, 2011 and December 31, 2010 (dollars in thousands):

			Number of	Mandatory Cash
Entered	Notional		Contracts	Settlement Date
May/June 2010	$	50,000	2		July 2012

Under the terms of the outstanding interest rate swap agreements, the value of the interest rate swaps is determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of ten years. Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) will be amortized as a component of interest expense over the life of the forecasted interest payments.

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Derivative Instruments Summary

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of March 31, 2011 (in thousands):

		Fair Value
							Net Asset
Derivative	Balance Sheet Location	Asset		Liability			(Liability)
Foreign currency contracts	Other current assets	$	72	$	—		$	72
Interest rate contracts	Other property and investments -net		362		—			362
Commodity contracts	Current utility energy commodity derivative assets		10,550		(7,374	)		3,176
Commodity contracts	Non-current utility energy commodity derivative assets		26,680		(8,891	)		17,789
Commodity contracts	Current utility energy commodity derivative liabilities		4,775		(41,917	)		(37,142	)
Commodity contracts	Other non-current liabilities and deferred credits		9,296		(29,164	)		(19,868	)
Total derivative instruments recorded on the balance sheet		$	51,735	$	(87,346	)	$	(35,611	)

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of December 31, 2010 (in thousands):

		Fair Value
							Net Asset
Derivative	Balance Sheet Location	Asset		Liability			(Liability)
Foreign currency contracts	Other current assets	$	116	$	—		$	116
Interest rate contracts	Other property and investments -net		127		—			127
Interest rate contracts	Other non-current liabilities and deferred credits		—		(53	)		(53	)
Commodity contracts	Current utility energy commodity derivative assets		6,293		(3,701	)		2,592
Commodity contracts	Non-current utility energy commodity derivative assets		21,249		(5,988	)		15,261
Commodity contracts	Current utility energy commodity derivative liabilities		5,934		(57,417	)		(51,483	)
Commodity contracts	Other non-current liabilities and deferred credits		1,386		(32,371	)		(30,985	)
Total derivative instruments recorded on the balance sheet		$	35,105	$	(99,530	)	$	(64,425	)

Exposure to Demands for Collateral

The Company’s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company’s credit ratings or adverse changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made against the Company’s credit facilities and cash. The Company actively monitors the exposure to possible collateral calls and takes steps to minimize capital requirements.

Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an investment grade credit rating from the major credit rating agencies. If the Company’s credit ratings were to fall below “investment grade,” it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a liability position as of March 31, 2011 was $62.6 million. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2011, the Company would be required to post $33.3 million of collateral to its counterparties.

Credit Risk

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

• relating directly to it,

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AVISTA CORPORATION

• caused by market price changes, and

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

Should a counterparty, customer or supplier fail to perform, the Company may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. The Company seeks to mitigate credit risk by:

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

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

• actively monitoring current credit exposures, and

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

These credit policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company also uses standardized agreements that allow for the netting or offsetting of positive and negative exposures associated with a single counterparty or affiliated group.

The Company has concentrations of suppliers and customers in the electric and natural gas industries including:

• electric utilities,

• electric generators and transmission providers,

• natural gas producers and pipelines,

• financial institutions, and

• energy marketing and trading companies.

In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company’s overall exposure to credit risk, either positively or negatively, because the counterparties may be similarly affected by changes in conditions.

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

Cash deposits from counterparties totaled $1.2 million as of March 31, 2011 and December 31, 2010. These funds were held by Avista Utilities to mitigate the potential impact of counterparty default risk. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of non-cash collateral.

NOTE 6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Utilities. Individual benefits under this plan are based upon the employee’s years of service, date of hire and average compensation as specified in the plan. The Company’s funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The Company contributed $21 million in cash to the pension plan in 2010. The Company expects to contribute $26 million in cash to the pension plan in 2011 ($8.5 million was contributed in the first quarter).

The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note.

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The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.

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

The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement. Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension benefit). The liability and expense for this plan are included as other postretirement benefits.

The Company uses a December 31 measurement date for its pension and other postretirement benefit plans. The following table sets forth the components of net periodic benefit costs for the three months ended March 31 (dollars in thousands):

							Other Post-
	Pension Benefits						retirement Benefits
	2011			2010			2011			2010
Service cost	$	2,942		$	2,878		$	227		$	202
Interest cost		6,109			5,823			919			619
Expected return on plan assets		(5,591	)		(5,347	)		(443	)		(341	)
Transition obligation recognition		—			—			126			126
Amortization of prior service cost		119			163			(37	)		(37	)
Net loss recognition		2,105			1,791			435			338
Net periodic benefit cost	$	5,684		$	5,308		$	1,227		$	907

NOTE 7. SHORT-TERM BORROWINGS

In February 2011, Avista Corp. entered into a new committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2015 that replaced its $320.0 million and $75.0 million committed lines of credit.

The committed line of credit is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.

The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65 percent at any time. As of March 31, 2011, the Company was in compliance with this covenant.

Balances outstanding under the Company’s revolving committed lines of credit were as follows as of March 31, 2011 and December 31, 2010 (dollars in thousands):

	March 31,		December 31,
	2011		2010
Balance outstanding at end of period	$	65,000	$	110,000
Letters of credit outstanding at end of period	$	22,123	$	27,126

Advantage IQ

In April 2011, Advantage IQ entered into a new $40.0 million three-year committed line of credit agreement with a financial institution that replaced its $15.0 million committed credit agreement that had an expiration date of May 2011. The credit agreement is secured by substantially all of Advantage IQ’s assets. There were no borrowings outstanding under Advantage IQ’s previous credit agreement as of March 31, 2011 and December 31, 2010.

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NOTE 8. LONG-TERM DEBT

The following details long-term debt outstanding as of March 31, 2011 and December 31, 2010 (dollars in thousands):

Maturity		Interest	March 31,			December 31,
Year	Description	Rate	2011			2010
2012	Secured Medium-Term Notes	7.37%	$	7,000		$	7,000
2013	First Mortgage Bonds	1.68%		50,000			50,000
2018	First Mortgage Bonds	5.95%		250,000			250,000
2018	Secured Medium-Term Notes	7.39%-7.45%		22,500			22,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2020	First Mortgage Bonds	3.89%		52,000			52,000
2022	First Mortgage Bonds	5.13%		250,000			250,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Secured Pollution Control Bonds (1)	(1)		66,700			66,700
2034	Secured Pollution Control Bonds (2)	(2)		17,000			17,000
2035	First Mortgage Bonds	6.25%		150,000			150,000
2037	First Mortgage Bonds	5.70%		150,000			150,000
2040	First Mortgage Bonds	5.55%		35,000			35,000
	Total secured long-term debt			1,178,700			1,178,700
2023	Unsecured Pollution Control Bonds	6.00%		4,100			4,100
	Capital leases and other long-term debt			5,555			5,500
	Settled interest rate swaps			(731	)		(951	)
	Unamortized debt discount			(1,750	)		(1,792	)
	Total			1,185,874			1,185,557
	Secured Pollution Control Bonds held by Avista Corporation (1) (2)			(83,700	)		(83,700	)
	Current portion of long-term debt			(360	)		(358	)
	Total long-term debt		$	1,101,814		$	1,101,499

(1) In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue (Series 2010A). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, these bonds will be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.’s Condensed Consolidated Balance Sheet.

(2) In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue (Series 2010B). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date, subject to market conditions, the bonds will be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.’s Condensed Consolidated Balance Sheet.

Nonrecourse Long-Term Debt

Nonrecourse long-term debt (including current portion) represents the long-term debt of Spokane Energy. 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 fixed rate electric capacity contract and $1.6 million of funds held in a trust account.

NOTE 9. FAIR VALUE

Fair value represents the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The carrying values of cash and cash equivalents, accounts and notes receivable, accounts payable and short-term borrowings are reasonable estimates of their fair values. Long-term debt (including current portion, but excluding capital leases), nonrecourse long-term debt and long-term debt to affiliated trusts are reported at carrying value on the Condensed Consolidated Balance Sheets.

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The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010 (dollars in thousands):

	March 31, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
	Value		Fair Value		Value		Fair Value
Long-term debt	$	1,099,100	$	1,151,438	$	1,099,100	$	1,139,765
Nonrecourse long-term debt		55,918		62,218		58,934		64,795
Long-term debt to affiliated trusts		51,547		43,866		51,547		37,114

These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market information. Due to the unique nature of the long-term fixed rate electric capacity contract securing the long-term debt of Spokane Energy (nonrecourse long-term debt), the estimated fair value of nonrecourse long-term debt was determined based on a discounted cash flow model using available market information.

Energy commodity derivative assets and liabilities, funds held for customers, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. U.S. GAAP defines a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its liabilities.

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AVISTA CORPORATION

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010 at fair value on a recurring basis (dollars in thousands):

							Counterparty
	Level 1		Level 2		Level 3		Netting (1)			Total
March 31, 2011
Assets:
Energy commodity derivatives	$	—	$	31,292	$	20,009	$	(30,336	)	$	20,965
Interest rate swaps		—		362		—		—			362
Foreign currency derivatives		—		72		—		—			72
Funds held for customers (2)		52,908		—		—		—			52,908
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (3)		1,885		—		—		—			1,885
Equity securities (3)		6,896		—		—		—			6,896
Total	$	63,289	$	31,726	$	20,009	$	(30,336	)	$	84,688
Liabilities:
Energy commodity derivatives	$	—	$	81,666	$	5,680	$	(30,336	)	$	57,010
December 31, 2010
Assets:
Energy commodity derivatives	$	—	$	15,124	$	19,739	$	(17,010	)	$	17,853
Interest rate swaps		—		127		—		—			127
Foreign currency derivatives		—		116		—		—			116
Funds held for customers (2)		100,543		—		—		—			100,543
Funds held in trust account of Spokane Energy		1,600		—		—		—			1,600
Deferred compensation assets:
Fixed income securities (3)		1,854		—		—		—			1,854
Equity securities (3)		6,211		—		—		—			6,211
Total	$	110,208	$	15,367	$	19,739	$	(17,010	)	$	128,304
Liabilities:
Energy commodity derivatives	$	—	$	93,198	$	6,280	$	(17,010	)	$	82,468
Interest rate swaps		—		53		—		—			53
Total	$	—	$	93,251	$	6,280	$	(17,010	)	$	82,521

(1) The Company is permitted to net derivative assets and derivative liabilities when a legally enforceable master netting agreement exists.

(2) Represents amounts held in money market funds.

(3) These assets are trading securities.

Avista Utilities enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Utilities’ management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2. The Company also has certain contracts that, primarily due to the length of the respective contract, require the use of internally developed forward price estimates, which include significant inputs that may not be observable or corroborated in the market. These derivative contracts are included in Level 3. Refer to Note 5 for further discussion of the Company’s energy commodity derivative assets and liabilities.

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AVISTA CORPORATION

Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an Executive Deferral Plan. These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table above excludes cash and cash equivalents of $1.2 million as of March 31, 2011 and December 31, 2010.

The following table presents activity for energy commodity derivative assets and (liabilities) measured at fair value using significant unobservable inputs (Level 3) for the three months ended March 31 (dollars in thousands):

	Assets					Liabilities
	2011		2010			2011			2010
Balance as of January 1	$	19,739	$	57,276		$	(6,280	)	$	(7,806	)
Total gains or losses (realized/unrealized):
Included in net income		—		—			—			—
Included in other comprehensive income		—		—			—			—
Included in regulatory assets/liabilities (1)		270		(24,192	)		(356	)		2,910
Purchases		—		—			—			—
Issuances		—		—			—			—
Settlements		—		(2,296	)		956			—
Transfers to other categories		—		—			—			—
Ending balance as of March 31	$	20,009	$	30,788		$	(5,680	)	$	(4,896	)

(1) The WUTC and the IPUC issued accounting orders authorizing Avista Utilities 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 Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Condensed Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases.

NOTE 10. EARNINGS PER COMMON SHARE ATTRIBUTABLE TO AVISTA CORPORATION

The following table presents the computation of basic and diluted earnings per common share attributable to Avista Corporation for the three months ended March 31 (in thousands, except per share amounts):

	2011			2010
Numerator:
Net income attributable to Avista Corporation	$	41,918		$	28,810
Subsidiary earnings adjustment for dilutive securities		(74	)		(35	)
Adjusted net income attributable to Avista Corporation for computation of diluted earnings per common share	$	41,844		$	28,775
Denominator:
Weighted-average number of common shares outstanding-basic		57,342			54,869
Effect of dilutive securities:
Performance and restricted stock awards		12			162
Stock options		60			84
Weighted-average number of common shares outstanding-diluted		57,414			55,115
Potential shares excluded in calculation		—			207
Earnings per common share attributable to Avista Corporation:
Basic	$	0.73		$	0.53
Diluted	$	0.73		$	0.52

Certain stock options were excluded from the calculation because they were antidilutive as the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

NOTE 11. COMMITMENTS AND CONTINGENCIES

In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters, including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. After consultation with legal counsel, the Company accrues 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. For matters that affect Avista Utilities’ operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

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AVISTA CORPORATION

Federal Energy Regulatory Commission Inquiry

In April 2004, the Federal Energy Regulatory Commission (FERC) approved the contested Agreement in Resolution of Section 206 Proceeding (Agreement in Resolution) between Avista Corp. doing business as Avista Utilities, Avista Energy and the FERC’s Trial Staff which stated that there was: (1) no evidence that any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy during 2000 and 2001; (2) no evidence that Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) no finding that Avista Utilities or Avista Energy withheld relevant information from the FERC’s inquiry into the western energy markets for 2000 and 2001 (Trading Investigation). The Attorney General of the State of California (California AG), the California Electricity Oversight Board, and the City of Tacoma, Washington challenged the FERC’s decisions approving the Agreement in Resolution, which are now pending before the United States Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2004, the FERC provided notice that Avista Energy was no longer subject to an investigation reviewing certain bids above $250 per MW in the short-term energy markets operated by the California Independent System Operator (CalISO) and the California Power Exchange (CalPX) from May 1, 2000 to October 2, 2000 (Bidding Investigation). That matter is also pending before the Ninth Circuit, after the California AG, Pacific Gas & Electric (PG&E), Southern California Edison Company (SCE) and the California Public Utilities Commission (CPUC) filed petitions for review in 2005.

Based on the FERC’s order approving the Agreement in Resolution in the Trading Investigation and order denying rehearing requests, the Company does not expect that this proceeding will have any material adverse effect on its financial condition, results of operations or cash flows. Furthermore, based on information currently known to the Company regarding the Bidding Investigation and the fact that the FERC Staff did not find any evidence of manipulative behavior, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

California Refund Proceeding

In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CalISO and the CalPX during the period from October 2, 2000 to June 20, 2001 (Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices for each hour. The FERC ruled that if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may document these costs and limit their refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim pursuant to the FERC’s August 2005 order. That filing was accepted in orders issued by the FERC in January 2006 and November 2006. In June 2009, the FERC reversed, in part, its previous decision and ordered a compliance filing requiring an adjustment to the return on investment component of Avista Energy’s cost filing. That compliance filing was made in July 2009. Responding to arguments made by the California AG, the CPUC, PG&E and SCE in March 2010, Avista Energy corrected a technical error in its compliance filing in April 2010. That correction increased its cost filing claim. In March 2011, the FERC rejected any return on equity in Avista Energy’s compliance filing, directing Avista Energy to submit its cost filing to the CalISO, removing the return on equity component. Avista Energy complied in April 2011, and the California AG, the CPUC, PG&E and SCE filed for rehearing of the FERC’s order in April 2011.

The CalISO continues to work on its compliance filing for the Refund Period, which will show “who owes what to whom.” In April 2010 and May 2010, the CalISO and CalPX, respectively, filed updated compliance reports concerning preparatory re-run activity. The CalPX filing requested guidance from the FERC on issues related to completing the final determination of “who owes what to whom.” The CalPX supplemented its compliance filing in October 2010. In June 2010, Avista Energy filed comments with the FERC asking the FERC to assist the parties in bringing this matter to a close by expeditiously: 1) approving the compliance filings made by the CalISO and the CalPX; 2) ruling on the outstanding issues presented by the CalPX; and 3) setting milestones for next steps regarding the final compliance filing.

In July 2010, the CalISO filed its 45th status report on the California recalculation process confirming that the calculations related to fuel cost allowance offsets and emission offsets are complete, and identifying several open issues related to the refund rerun calculations that need to be resolved by the FERC. The CalISO states that it will need to revise certain calculations related to cost-recovery offsets and interest calculations. In addition, the CalISO stated that it is in the process of making adjustments to the CalISO data to remove refunds associated with sales made by non-jurisdictional entities. The CalISO also says that it will need to work with parties to the various global settlements to make appropriate adjustments to the CalISO’s data in order to properly reflect those adjustments. In a March 2010 filing, the CalISO stated that it does not intend to make any compliance filing until, inter alia, the FERC resolves issues related to the Ninth Circuit’s remand regarding possible remedies for alleged tariff violations pursuant to Federal Power Act (FPA) section 309, prior to the Refund Period (discussed below).

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AVISTA CORPORATION

The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CalPX. As a result, Avista Energy has not been paid for all of its energy sales during the Refund Period. Those funds are now in escrow accounts and will not be released until the FERC issues an order directing such release in the California refund proceeding. As of March 31, 2011, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from the defaulting parties.

Many of the orders that the FERC has issued in the California refund proceedings were appealed to the Ninth Circuit. In October 2004, the Ninth Circuit ordered that briefing proceed in two rounds. The first round was limited to three issues: (1) which parties are subject to the FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the FPA; (2) the temporal scope of refunds under section 206 of the FPA; and (3) which categories of transactions are subject to refunds. The second round of issues and their corresponding briefing schedules have not yet been set by the Ninth Circuit.

In September 2005, the Ninth Circuit held that the FERC did not have the authority to order refunds for sales made by municipal utilities in the California refund proceeding. In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 refund proceeding, but remanded to the FERC its decision not to consider an FPA section 309 remedy for tariff violations prior to that date. Petitions for rehearing were denied in April 2009. In July 2009, Avista Energy and Avista Utilities filed a motion at the FERC, asking that the companies be dismissed from any further proceedings arising under section 309 pursuant to the remand. The filing pointed out that section 309 relief is based on tariff violations of the seller, and as to Avista Energy and Avista Utilities, these allegations had already been fully adjudicated in the proceeding that gave rise to the Agreement in Resolution, discussed above. There, the FERC absolved both companies of all allegations of market manipulation or wrongdoing that would justify or permit FPA sections 206 or 309 remedies during 2000 and 2001. In November 2009, the FERC issued an order establishing an evidentiary hearing before an administrative law judge to address the issues remanded by the Ninth Circuit without addressing the Company’s pending motion. In December 2009, the Company again brought the issue to the FERC’s attention but its motion remains pending, as do a number of rehearing requests regarding the November 2009 hearing order. In September 2010, the FERC issued a “Supplemental Order Soliciting Comments” on the scope of the hearing. The Company responded in filings made on September 22, 2010 and October 6, 2010, and the parties are awaiting further rulings by the FERC before the hearing commences.

Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent of the Company’s liability, if any. However, based on information currently known, the Company does not expect that the refunds ultimately ordered for the Refund Period will have a material adverse effect on its financial condition, results of operations or cash flows. This is primarily due to the fact that the FERC orders have stated that any refunds will be netted against unpaid amounts owed to the respective parties and the Company does not believe that refunds would exceed unpaid amounts owed to the Company.

Pacific Northwest Refund Proceeding

In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. In August 2007, the Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC’s findings must be reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential relief for transactions involving energy that was purchased by the California Department of Water Resources (CERS) in the Pacific Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. The Ninth Circuit denied petitions for rehearing by various parties, and remanded the case to the FERC in April 2009.

In May 2009, the California AG filed a complaint against both Avista Energy and Avista Utilities seeking refunds on sales made to CERS during the period January 18, 2001 to June 20, 2001 under section 309 of the FPA (the Brown Complaint). The sales at issue are limited in scope and are duplicative of claims already at issue in the Pacific Northwest proceeding, discussed above. In August 2009, the City of Tacoma and the Port of Seattle filed a motion asking the FERC to summarily re-price sales of energy in the Pacific Northwest during 2000 and 2001. In October 2009, Avista Corp. filed, as part of the Transaction Finality Group, an answer to that motion and, in addition, made its own recommendations for further proceedings in this docket. Those pleadings are pending before the FERC.

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AVISTA CORPORATION

Both Avista Utilities and Avista Energy were buyers and sellers of energy in the Pacific Northwest energy market during the period between December 25, 2000 and June 20, 2001 and, if refunds were ordered by the FERC, could be liable to make payments, but also could be entitled to receive refunds from other FERC-jurisdictional entities. The opportunity to make claims against entities not subject to the FERC’s jurisdiction may be limited based on existing law. The Company cannot predict the outcome of this proceeding or the amount of any refunds that Avista Utilities or Avista Energy could be ordered to make or could be entitled to receive. Therefore, the Company cannot predict the potential impact the outcome of this matter could ultimately have on the Company’s results of operations, financial condition or cash flows.

California Attorney General Complaint (the “Lockyer Complaint”)

In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the California AG that alleged violations of the FPA by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The complaint alleged that the FERC’s adoption and implementation of market-based rate authority was flawed and, as a result, individual sellers should refund the difference between the rate charged and a just and reasonable rate. In May 2002, the FERC issued an order dismissing the complaint but directing sellers to re-file certain transaction summaries. It was not clear that Avista Corp. and its subsidiaries were subject to this directive but the Company took the conservative approach and re-filed certain transaction summaries in June and July of 2002. In September 2004, the Ninth Circuit upheld the FERC’s market-based rate authority, but held that the FERC erred in ruling that it lacked authority to order refunds for violations of its reporting requirement. The Court remanded the case for further proceedings, but did not order any refunds, leaving it to the FERC to consider appropriate remedial options.

In March 2008, the FERC issued an order establishing a trial-type hearing to address “whether any individual public utility seller’s violation of the FERC’s market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.” Purchasers in the California markets will be allowed to present evidence that “any seller that violated the quarterly reporting requirement failed to disclose an increased market share sufficient to give it the ability to exercise market power and thus cause its market-based rates to be unjust and unreasonable.” In particular, the parties were directed to address whether the seller at any point reached a 20 percent generation market share threshold, and if the seller did reach a 20 percent market share, whether other factors were present to indicate that the seller did not have the ability to exercise market power. The California AG, CPUC, PG&E, and SCE filed their testimony in July 2009. Avista Utilities and Avista Energy’s answering testimony was filed in September 2009. On the same day, the FERC staff filed its answering testimony taking the position that, using the test the FERC directed to be applied in this proceeding, neither Avista Utilities nor Avista Energy had market power for the period in question. Cross answering testimony and rebuttal testimony were filed in November 2009. In January 2010, Avista Utilities and Avista Energy filed a motion for summary disposition, as did other parties to the proceeding. In March 2010, the Presiding Administrative Law Judge (ALJ) granted the motions for summary disposition and found that a hearing was “unnecessary” because the California AG, CPUC, PG&E and SCE “failed to apply the appropriate test to determine market power during the relevant time period.” The judge determined that “[w]ithout a proper showing of market power, the California Parties failed to establish a prima facie case.” In May 2011, the FERC affirmed “in all respects” the ALJ’s decision.

Based on information currently known to the Company’s management, the fact that neither Avista Utilities nor Avista Energy ever reached a 20 percent generation market share during 2000 or 2001 and the ALJ’s granting of Avista Utilities and Avista Energy’s summary disposition motion, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Colstrip Generating Project Complaint

In March 2007, two families that own property near the holding ponds from Units 3 & 4 of the Colstrip Generating Project (Colstrip) filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The plaintiffs allege that the holding ponds and remediation activities have adversely impacted their property. They allege contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to their property. They also seek punitive damages, attorney’s fees, an order by the court to remove certain ponds, and the forfeiture of profits earned from the generation of Colstrip. In September 2010, the owners of Colstrip filed a motion with the court to enforce a settlement agreement that would resolve all issues between the parties. Under the settlement, Avista Corp.’s portion of payment (which was accrued in the second quarter of 2010) to the plaintiffs was not material to its financial condition, results of operations or cash flows. The plaintiffs have contested the existence of any settlement, and filed a response to the motion, with the matter to be decided by the court. Although the final resolution of this complaint remains uncertain, based on information currently known to the Company’s management, the Company does not expect this complaint will have a material adverse effect on its financial condition, results of operations or cash flows.

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AVISTA CORPORATION

Harbor Oil Inc. Site

Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early 1990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to Avista Corp. and several other parties, as customers of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal “Superfund” law, which provides for joint and several liability. The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible parties, including Avista Corp., signed an Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS), which is expected to be finalized in the second quarter of 2011. The actual cleanup, if any, will not occur until the RI/FS is complete. Based on the review of its records related to Harbor Oil, the Company does not believe it is a major contributor to this potential environmental contamination based on the small volume of waste oil it delivered to the Harbor Oil site. However, there is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred. The Company has accrued its share of the RI/FS ($0.5 million) for this matter.

Spokane River Licensing

The Company owns and operates 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. The license incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the United States Department of Interior and the Coeur d’Alene Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality Certifications and in the amended Washington 401 Water Quality Certification.

As part of the Settlement Agreement with the Washington Department of Ecology (DOE), the Company participated in the Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. On May 20, 2010, the EPA approved the TMDL and on May 27, 2010, the DOE filed an amended 401 Water Quality Certification with the FERC for inclusion into the license. The amended 401 Water Quality Certification includes the Company’s level of responsibility, as defined in the TMDL, for low dissolved oxygen levels in Lake Spokane. The Company has until May 27, 2012 to develop mitigation strategies to address the low levels of dissolved oxygen. It is not possible to provide cost estimates at this time because the mitigation measures have not been fully identified or approved by the DOE. On July 16, 2010, the City of Post Falls and the Hayden Area Regional Sewer Board filed an appeal with the United States District Court for the District of Idaho with respect to the EPA’s approval of the TMDL. The Company, the City of Coeur d’Alene, Kaiser Aluminum and the Spokane River Keeper subsequently moved to intervene in the appeal. The EPA, the City of Post Falls and the Hayden Area Regional Sewer Board are currently in settlement negotiations in an attempt to resolve the appeal. On April 8, 2011, the District Court granted the EPA a new deadline of June 10, 2011 to file its response to the plaintiffs. The other parties are assessing possible solutions to the Idaho dischargers’ concerns, as well as those subsequently voiced by Inland Empire Paper Company.

The IPUC and the WUTC approved the recovery of licensing costs through the general rate case settlements in 2009. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to implementing the license for the Spokane River Project.

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AVISTA CORPORATION

Cabinet Gorge Total Dissolved Gas Abatement Plan

Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. In 2002, the Company submitted a Gas Supersaturation Control Program (GSCP) to the Idaho Department of Environmental Quality (Idaho DEQ) and U.S. Fish and Wildlife Service (USFWS). This submission was part of the Clark Fork Settlement Agreement for licensing the use of Cabinet Gorge. The GSCP provided for the opening and modification of possibly two diversion tunnels around Cabinet Gorge to allow streamflow to be diverted when flows are in excess of powerhouse capacity. In 2007, engineering studies determined that the tunnels would not sufficiently reduce Total Dissolved Gas (TDG). In consultation with the Idaho DEQ and the USFWS, the Company developed an addendum to the GSCP. The GSCP addendum abandons the concept to reopen the two diversion tunnels and requires the Company to evaluate a variety of different options to abate TDG over the next several years. In March 2010, the FERC approved the GSCP addendum of preliminary design for alternative abatement measures. In April 2011, the Company completed preliminary feasibility assessments for several alternative abatement measures, the results of which will be reviewed in May 2011 to determine which alternatives will be considered for continued development. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.

Fish Passage at Cabinet Gorge and Noxon Rapids

In 1999, the USFWS listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the USFWS, the Company is evaluating the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of these studies will help the Company and other parties determine the best use of funds toward continuing fish passage efforts or other bull trout population enhancement measures. In the fall of 2009, the Company selected a contractor to design a permanent upstream passage facility at Cabinet Gorge. The Company anticipates that the design and cost estimates will be completed by the end of 2011.

In January 2010, the USFWS proposed to revise its 2005 designation of critical habitat for the bull trout. The proposed revisions include the lower Clark Fork River as critical habitat. In April 2010, the Company submitted comments recommending the lower Clark Fork River be excluded from critical habitat designation based in part on the extensive bull trout recovery efforts the Company is already undertaking. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids.

Aluminum Recycling Site

In October 2009, the Company (through its subsidiary Pentzer Venture Holdings II, Inc. (Pentzer)) received notice from the DOE proposing to find Pentzer liable for a release of hazardous substances under the Model Toxics Control Act, under Washington state law. Pentzer owns property that adjoins land owned by the Union Pacific Railroad (UPR). UPR leased their property to operators of a facility designated by DOE as “Aluminum Recycling – Trentwood.” Operators of the UPR property maintained piles of aluminum “black dross,” which can be designated as a state-only dangerous waste in Washington State. In the course of its business, the operators placed a portion of the aluminum dross pile on the property owned by Pentzer. Pentzer does not believe it is a contributor to any environmental contamination associated with the dross pile, and submitted a response to the DOE’s proposed findings in November 2009. In December 2009, Pentzer received notice from the DOE that it had been designated as a potentially liable party for any hazardous substances located on this site. UPR completed a RI/FS Work Plan in June 2010. At that time, UPR requested a contribution from Pentzer towards the cost of performing the RI/FS and also an access agreement to investigate the material deposited on the Pentzer property. Pentzer concluded an access agreement with UPR in October 2010. UPR commenced the remedial investigation during the fourth quarter of 2010, which is expected to be completed in 2011. There is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred.

Injury from Overhead Electric Line (Munderloh v. Avista)

On March 4, 2010, the plaintiff and his wife filed a complaint against Avista Corp. in Spokane County Superior Court. Plaintiffs allege that while the plaintiff was employed by a third party as a laborer at their construction site, he came into contact with Avista Corp.’s electric line, was injured and suffered economic and non-economic damages. Plaintiffs further allege that Avista Corp. was at fault for failing to relocate the overhead electric line which it controlled and operated adjacent to the construction site. In addition to economic and non-economic damages, plaintiffs also seek damages for loss of consortium, attorney’s fees and costs, prejudgment interest and punitive damages. Trial has been scheduled to begin in September 2011. The plaintiffs have not yet provided a statement specifying damages. Because the resolution of this claim remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect this complaint will have a material adverse effect on its financial condition, results of operations or cash flows.

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Damages from Fire in Stevens County, Washington

In August 2010, a fire in Stevens County, Washington occurred during a wind storm. The apparent cause of the fire may be a tree located outside of Avista Corp.’s right-of-way that came in contact with an electric line owned by Avista Corp. The fire area is a rural farm and timber landscape. The fire destroyed two residences and six outbuildings. The Company is not aware of any personal injuries resulting from the fire. Although no lawsuits have been filed, Avista Corp. has received several claims and it is possible that additional claims may be made and lawsuits may be filed against the Company. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect this complaint will have a material adverse effect on its financial condition, results of operations or cash flows.

Other Contingencies

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

NOTE 12. INFORMATION BY BUSINESS SEGMENTS

The business segment presentation reflects the basis used by the Company’s management to analyze performance and determine the allocation of resources. Avista Utilities’ business is managed based on the total regulated utility operation. Advantage IQ is a provider of energy efficiency and cost management programs and services for multi-site customers throughout North America. The Other category, which is not a reportable segment, includes sheet metal fabrication, venture fund investments and real estate investments, Spokane Energy, as well as certain other operations of Avista Capital. The following table presents information for each of the Company’s business segments (dollars in thousands):

								Total
	Avista		Advantage					Non-		Intersegment
	Utilities		IQ		Other			Utility		Eliminations (1)			Total
For the three months ended March 31, 2011:
Operating revenues	$	438,147	$	29,158	$	9,731		$	38,889	$	(450	)	$	476,586
Resource costs		248,121		—		—			—		—			248,121
Other operating expenses		59,682		24,008		7,688			31,696		(450	)		90,928
Depreciation and amortization		25,852		1,664		203			1,867		—			27,719
Income from operations		79,499		3,486		1,840			5,326		—			84,825
Interest expense (2)		17,356		11		1,597			1,608		(373	)		18,591
Income taxes		22,255		1,254		128			1,382		—			23,637
Net income attributable to Avista Corporation		40,117		1,707		94			1,801		—			41,918
Capital expenditures		49,654		315		159			474		—			50,128
For the three months ended March 31, 2010:
Operating revenues	$	424,031	$	23,942	$	15,074		$	39,016	$	(6,632	)	$	456,415
Resource costs		259,567		—		—			—		—			259,567
Other operating expenses		55,749		19,257		13,333			32,590		(6,632	)		81,707
Depreciation and amortization		24,330		1,524		292			1,816		—			26,146
Income from operations		63,214		3,161		1,449			4,610		—			67,824
Interest expense (2)		17,828		27		1,466			1,493		(60	)		19,261
Income taxes		16,960		1,144		(237	)		907		—			17,867
Net income (loss) attributable to Avista Corporation		27,776		1,447		(413	)		1,034		—			28,810
Capital expenditures		42,552		268		197			465		—			43,017
Total Assets:
As of March 31, 2011	$	3,522,914	$	172,328	$	128,543		$	300,871	$	—		$	3,823,785
As of December 31, 2010	$	3,589,235	$	221,086	$	129,774		$	350,860	$	—		$	3,940,095

(1) Intersegment eliminations reported as operating revenues and resource costs represent intercompany purchases and sales of electric capacity and energy. Intersegment eliminations reported as interest expense represent intercompany interest.

(2) Including interest expense to affiliated trusts.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Avista Corporation

Spokane, Washington

We have reviewed the accompanying condensed consolidated balance sheet of Avista Corporation and subsidiaries (the “Corporation”) as of March 31, 2011, and the related condensed consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interests, and cash flows for the three-month periods ended March 31, 2011 and 2010. These interim financial statements are the responsibility of the Corporation’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Avista Corporation and subsidiaries as of December 31, 2010, and the related consolidated statements of income, comprehensive income, equity and redeemable noncontrolling interests, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2011, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of accounting guidance for variable interest entities. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2010 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/    Deloitte & Touche LLP

Seattle, Washington

May 6, 2011

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Business Segments

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 79 percent owned as of March 31, 2011) 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 other businesses, including sheet metal fabrication, venture fund investments and real estate investments, Spokane Energy, as well as certain other operations of Avista Capital. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx.

The following table presents net income (loss) attributable to Avista Corp. for each of our business segments (and the other businesses) for the three months ended March 31 (dollars in thousands):

	2011		2010
Avista Utilities	$	40,117	$	27,776
Advantage IQ		1,707		1,447
Other		94		(413	)
Net income attributable to Avista Corp	$	41,918	$	28,810

Executive Level Summary

Overall

Net income attributable to Avista Corp. was $41.9 million for the three months ended March 31, 2011, an increase from $28.8 million for the three months ended March 31, 2010. This was primarily due to an increase in earnings at Avista Utilities (primarily due to colder weather, lower power supply costs and the implementation of general rate increases) and partially due to an increase in earnings at Advantage IQ and the other businesses.

Avista Utilities

Avista Utilities is our most significant business segment. Our utility 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 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 systems. 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, in Washington effective December 1, 2010 and in Oregon effective March 15, 2011.

Our utility net income was $40.1 million for the three months ended March 31, 2011, an increase from $27.8 million for the three months ended March 31, 2010. Earnings for the first quarter of 2011 were positively impacted by an increase in gross margin (operating revenues less resource costs). The increase in gross margin was primarily due to higher retail loads caused by colder weather and power supply costs below the amount included in base retail rates, as well as general rate increases. The increase in gross margin was partially offset by an increase in other operating expenses, depreciation and amortization, and taxes other than income taxes.

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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 $49.7 million for the first quarter of 2011. We expect utility capital expenditures to be about $250 million for the full year of 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 Corp. of $1.7 million for the three months ended March 31, 2011, an increase from $1.4 million for the three months ended March 31, 2010. The increase was primarily due to moderate growth from expense management and energy management services, as well as the acquisition of The Loyalton Group (Loyalton) effective December 31, 2010. Advantage IQ’s earnings potential continues to be moderated by low short-term interest rates, which limits interest revenue on funds held for customers.

The acquisition of Cadence Network effective July 2, 2008 was funded with the issuance of Advantage IQ common stock. Under the transaction agreement, 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 March 31, 2011, there were redeemable noncontrolling interests of $33.6 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, Avista Capital purchased shares held by one of the previous owners of Cadence Network for $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

Net income attributable to Avista Corp. for these operations was $0.1 million for the three months ended March 31, 2011 compared to a net loss of $0.4 million for the three months ended March 31, 2010. The improvement in results was due in part to increased earnings at METALfx and a net gain on investments of $0.1 million for the first quarter of 2011 compared to a net loss of $0.6 million for the first quarter of 2010.

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.

In February 2011, we entered into a new committed line of credit with various financial institutions 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 that had expiration dates in April 2011. As of March 31, 2011, there were $65.0 million of cash borrowings and $22.1 million in letters of credit outstanding. As of March 31, 2011, we had $312.9 million of available liquidity 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 the first quarter of 2011, we sold 255,000 shares for a total of $5.8 million. As of March 31, 2011, we had 0.8 million shares available to be issued under this agreement.

We expect to issue up to $25 million of common stock in 2011 (including first quarter issuances) 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 $400.0 million committed line of credit agreement to provide adequate resources to fund:

• capital expenditures,

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• 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 a general rate case in Washington in the second quarter of 2011 and continue to evaluate rate case plans in Idaho. The following is a summary of our authorized rates of return in each jurisdiction:

		Authorized			Authorized			Authorized
	Implementation	Overall Rate			Return on			Equity
Jurisdiction and service	Date	of Return			Equity			Level
Washington electric and natural gas	December 2010		7.9	%		10.2	%		46.5	%
Idaho electric and natural gas	October 2010		(1	)		(1	)		(1	)
Oregon natural gas	March 2011		8.0	%		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 8.5 percent, a return on equity of 10.5 percent and authorized equity level of 50.0 percent.

Washington General Rate Cases

In November 2010, the WUTC approved an all-party settlement stipulation in our general rate case filed in March 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.

Idaho General Rate Cases

In September 2010, the IPUC approved a settlement agreement in 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.

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

In March 2011, the OPUC approved an all-party settlement stipulation in our general rate case that was filed in September 2010. The settlement 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 became effective March 15, 2011, with the remaining increase effective June 1, 2011. An additional rate adjustment designed to increase revenues by $0.6 million will occur on June 1, 2012 to recover capital costs associated with certain reinforcement and replacement projects upon a demonstration that such projects were prudently incurred and complete.

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. 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 $15.5 million as of March 31, 2011, a decrease from $22.1 million as of December 31, 2010.

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Oregon Senate Bill 408

The OPUC established rules in September 2007 related to Oregon Senate Bill 408 (OSB 408), which was enacted into law in 2005. These rules direct the utility to establish an automatic adjustment clause to account for the difference between income taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. The automatic adjustment clause may result in either rate increases or rate decreases. In April 2011, the OPUC approved a settlement stipulation to refund $1.2 million (including interest), which was previously accrued, to Oregon customers for the 2009 tax report year. Legislation is currently pending that would repeal OSB 408 and replace it with provisions which are supported by Avista Corp. We cannot predict whether or not this pending legislation will be enacted into law.

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 in 2010. Deferrals under the ERM resumed in 2011. Total net deferred power costs under the ERM were a liability of $2.7 million as of March 31, 2011.

In periods where we are a net seller of wholesale power, market prices lower than the prices included in retail rates can result in increased power supply costs and potential deferrals in the surcharge direction under the ERM. In periods where we are a net purchaser, market prices lower than the amount included in retail rates can decrease power supply costs and result in potential deferrals in the rebate direction 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.

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:

	Deferred for Future
Annual Power Supply	Surcharge or Rebate			Expense or Benefit
Cost Variability	to Customers			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. In 2011, we made our filing indicating that there were not any deferrals under the ERM for 2010. 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.

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. Total net power costs deferred under the PCA mechanism were a regulatory asset of $10.3 million as of March 31, 2011.

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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. 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 in January 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 Condensed 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.

Utility revenues increased $14.1 million due to increased electric revenues of $19.7 million and natural gas revenues of $11.4 million, partially offset by intracompany revenues of $17.0 million. Retail electric revenues increased $25.2 million due to an increase in volumes caused by colder weather and prices from general rate increases. In addition, sales of fuel increased $22.3 million (reflected increased thermal general resource optimization and lower usage of our thermal generating plants). These increases in electric revenues were partially offset by a decrease in wholesale electric revenues of $27.5 million (due to a decrease in wholesale prices and volumes). Retail natural gas revenues increased $28.1 million due to an increase in volumes caused by colder weather and prices from general rate increases, while wholesale natural gas revenues decreased $17.1 million (due to decreased volumes and wholesale prices).

Other non-utility revenues increased $6.1 million to $38.9 million primarily as a result of Advantage IQ’s revenues increasing $5.2 million due to moderate growth in expense management and energy management services, as well as the acquisition of Loyalton effective December 31, 2010. Revenues from our other businesses increased $0.9 million, primarily due to increased sales at METALfx.

Utility resource costs decreased $11.4 million due to intracompany resource costs of $17.0 million, while electric resource costs increased $5.2 million and natural gas resource costs increased $0.4 million. The increase in electric resource costs was primarily due to an increase in other fuel costs (reflecting an increase in thermal generation optimization and lower usage of our thermal plants) and the deferral of power supply costs below the amount included in retail rates, partially offset by a decrease in fuel costs (due to lower thermal generation).

Utility other operating expenses increased $3.9 million primarily due to increased compensation costs, pensions and benefits, and maintenance expenses.

Utility depreciation and amortization increased $1.5 million driven by additions to utility plant.

Utility taxes other than income taxes increased $3.8 million primarily reflecting higher retail revenue related taxes, as well as increased property taxes.

Other non-utility operating expenses increased $5.3 million reflecting an increase of $4.8 million for Advantage IQ primarily due to moderate growth in expense management and energy management services, as well as the acquisition of Loyalton.

Interest expense decreased $0.7 million primarily due to refinancing transactions completed in December 2010 that lowered our effective rate on long-term debt. This was partially offset by higher average balances and interest rates on short-term borrowings.

Other expense-net decreased $1.1 million primarily due to net gains on investments of $0.1 million in the first quarter of 2011 compared to net losses of $0.6 million in the first quarter of 2010. The decrease was also partially due to an increase in equity-related AFUDC of $0.4 million.

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Income taxes increased $5.8 million and our effective tax rate was 35.8 percent for the first quarter of 2011 compared to 37.9 percent for the first quarter of 2010. This increase was due to an increase in income before income taxes. The effective tax rate decreased due to regulatory accounting treatment impacting the timing of recognition for deferred state income taxes.

Avista Utilities

Net income for Avista Utilities was $40.1 million for the three months ended March 31, 2011, an increase from $27.8 million for the three months ended March 31, 2010. Avista Utilities’ income from operations was $79.5 million for the three months ended March 31, 2011 compared to $63.2 million for the three months ended March 31, 2010. The increase in net income and income from operations was primarily due to an increase in gross margin (operating revenues less resource costs), partially offset by an increase in other 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 three months ended March 31 (dollars in thousands):

	Electric				Natural Gas				Intracompany					Total
	2011		2010		2011		2010		2011			2010		2011		2010
Operating revenues	$	271,952	$	252,257	$	183,231	$	171,774	$	(17,036	)	$	—	$	438,147	$	424,031
Resource costs		137,049		131,879		128,108		127,688		(17,036	)		—		248,121		259,567
Gross margin	$	134,903	$	120,378	$	55,123	$	44,086	$	—		$	—	$	190,026	$	164,464

Avista Utilities’ operating revenues increased $14.1 million and resource costs decreased $11.4 million, which resulted in an increase of $25.6 million in gross margin. The gross margin on electric sales increased $14.5 million and the gross margin on natural gas sales increased $11.0 million. The increase in electric gross margin was due to colder weather that increased retail loads, power supply costs below the amount included in base retail rates (due to improved hydroelectric generation and lower purchased power and fuel costs) and general rate increases. During the first quarter of 2011, we recognized a benefit of $4.9 million under the ERM in Washington compared to an expense of $1.2 million for the first quarter of 2010. The increase in our natural gas gross margin was primarily due to colder weather that increased retail loads and partially due to 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. All transactions for 2010 were recorded in the fourth quarter of 2010.

The following table presents our utility electric operating revenues and megawatt-hour (MWh) sales for the three months ended March 31 (dollars and MWhs in thousands):

	Electric Operating				Electric Energy
	Revenues				MWh sales
	2011		2010		2011		2010
Residential	$	103,245	$	86,579		1,175		1,050
Commercial		70,190		64,850		775		747
Industrial		29,449		26,347		514		482
Public street and highway lighting		1,758		1,715		7		6
Total retail		204,642		179,491		2,471		2,285
Wholesale		19,051		46,562		596		919
Sales of fuel		44,372		22,112		—		—
Other		3,887		4,092		—		—
Total	$	271,952	$	252,257		3,067		3,204

Retail electric revenues increased $25.2 million due to an increase in total MWhs sold (increased revenues $15.4 million) primarily due to an increase in use per customer as a result of colder weather, and an increase in revenue per MWh (increased revenues $9.8 million). Compared to 2010, residential electric use per customer increased 11 percent and commercial use per customer increased 3 percent. The increase in revenue per MWh was primarily due to the Washington and Idaho general rate increases.

Wholesale electric revenues decreased $27.5 million due to a decrease in sales prices (decreased revenues $17.2 million) and a decrease in sales volumes (decreased revenues $10.3 million). The decrease in sales volumes was primarily due to decreased wholesale power optimization and higher than expected retail sales caused by colder weather.

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AVISTA CORPORATION

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 $22.3 million due to an increase in thermal generation resource optimization and lower usage of our thermal generation plants in 2011 as compared to 2010. This was due in part to increased hydroelectric generation. In the first quarter of 2011, $6.4 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 and the PCA mechanism.

The following table presents our utility natural gas operating revenues and therms delivered for the three months ended March 31 (dollars and therms in thousands):

	Natural Gas				Natural Gas
	Operating Revenues				Therms Delivered
	2011		2010		2011		2010
Residential	$	87,177	$	68,724		85,458		70,705
Commercial		44,585		35,069		50,332		41,130
Interruptible		829		816		1,458		1,303
Industrial		1,281		1,157		1,659		1,622
Total retail		133,872		105,766		138,907		114,760
Wholesale		45,022		62,118		114,531		122,553
Transportation		1,804		1,565		44,595		39,686
Other		2,533		2,325		233		191
Total	$	183,231	$	171,774		298,266		277,190

Retail natural gas revenues increased $28.1 million due to an increase in volumes (increased revenues $23.3 million) and higher retail rates (increased revenues $4.8 million). We sold more retail natural gas in the first quarter of 2011 as compared to first quarter of 2010 primarily due to colder weather. Compared to 2010, residential natural gas use per customer increased 20 percent and commercial use per customer increased 22 percent. The increase in retail rates reflects purchased gas adjustments, as well as general rate increases.

Wholesale natural gas revenues decreased $17.1 million due to a decrease in prices (decreased revenues $13.9 million) and volumes (decreased revenues $3.2 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. Additionally, we engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. With higher retail loads in 2011 as compared to 2010, we had less opportunity to optimize transportation resources. In the first quarter of 2011, $10.6 million of these sales were made to our electric generation operations and are reflected as intracompany revenues and resource costs. 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 three months ended March 31:

	Electric				Natural Gas
	Customers				Customers
	2011		2010		2011		2010
Residential		317,149		315,130		285,167		282,854
Commercial		39,575		39,469		33,636		33,489
Interruptible		—		—		36		38
Industrial		1,367		1,370		249		252
Public street and highway lighting		454		447		—		—
Total retail customers		358,545		356,416		319,088		316,633

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AVISTA CORPORATION

The following table presents our utility resource costs for the three months ended March 31 (dollars in thousands):

	2011			2010
Electric resource costs:
Power purchased	$	54,561		$	53,641
Power cost amortizations, net		10,759			3,712
Fuel for generation		15,968			44,959
Other fuel costs		47,212			22,762
Other regulatory amortizations, net		3,962			4,879
Other electric resource costs		4,587			1,926
Total electric resource costs	$	137,049		$	131,879
Natural gas resource costs:
Natural gas purchased	$	128,299		$	133,585
Natural gas cost amortizations, net		(6,809	)		(10,054	)
Other regulatory amortizations, net		6,618			4,157
Total natural gas resource costs		128,108			127,688
Intracompany resource costs		(17,036	)		—
Total resource costs	$	248,121		$	259,567

Power purchased increased $0.9 million due to an increase in wholesale prices (increased costs $0.6 million) and an increase in the volume of power purchases (increased costs $0.3 million).

Net amortization of deferred power costs was $10.8 million for the first quarter of 2011 compared to $3.7 million for the first quarter of 2010. During the first quarter of 2011, we recovered (collected as revenue) $5.1 million of previously deferred power costs in Idaho through the PCA surcharge. The Washington ERM surcharge was eliminated in February 2010, since the previous balance of deferred power costs had been recovered. During the first quarter of 2011 actual power supply costs were below the amount included in base retail rates in both Washington and Idaho. This was due to improved hydroelectric generation and lower purchased power and fuel costs. As such, we deferred $3.0 million in Idaho and $2.7 million in Washington for future rebate to customers.

Fuel for generation decreased $29.0 million primarily due to a decrease in thermal generation. This was due in part to an increase in hydroelectric generation.

Other fuel costs increased $24.5 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 $5.3 million due to a decrease in the price of natural gas (decreased costs $13.4 million), partially offset by an increase in the total therms purchased (increased costs $8.2 million). Total therms purchased increased due to an increase in retail loads (resulting from colder weather), partially offset by a decrease in wholesale sales with the balancing of loads and resources as part of the natural gas procurement process. We engage in optimization of available interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During the first quarter of 2011, natural gas resource costs were reduced by $6.8 million reflecting the rebate of a deferred liability for natural gas costs through the purchased gas adjustments.

Advantage IQ

Advantage IQ’s net income attributable to Avista Corp. was $1.7 million for the three months ended March 31, 2011 compared to $1.4 million for the three months ended March 31, 2010. Operating revenues increased $5.2 million and operating expenses increased $4.9 million. The increase in net income attributable to Avista Corp., operating revenues and expenses was primarily due to moderate growth in expense management and energy management services, as well as the acquisition of Loyalton effective December 31, 2010. As of March 31, 2011, Advantage IQ had 539 customers representing 365,000 billed sites in North America. In the first quarter of 2011, Advantage IQ managed bills totaling $4.8 billion, an increase of $0.7 billion, or 18 percent, as compared to the first quarter of 2010. The increase was due to an increase in both the average value of each bill processed and the number of accounts managed.

Other Businesses

Net income attributable to Avista Corp. from these operations was $0.1 million for the three months ended March 31, 2011 compared to a net loss of $0.4 million for three months ended March 31, 2010. Operating revenues decreased $5.3 million and operating expenses decreased $5.7 million. The decrease in operating revenues and operating expenses was primarily due to the assignment of the Lancaster PPA to Avista Corp. in December 2010. The improvement in results for these businesses was due in part to increased earnings at METALfx, which had net income of $0.3 million for the first quarter of 2011.

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. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2010 Form 10-K and have not changed materially from that discussion.

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AVISTA CORPORATION

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During the three months ended March 31, 2011, positive cash flows from operating activities of $103.3 million were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $49.7 million and dividends of $15.8 million. We were also able to reduce short-term borrowings by $45.0 million.

Operating Activities Net cash provided by operating activities was $103.3 million for the three months ended March 31, 2011 compared to $81.1 million for the three months ended March 31, 2010. Net cash provided by working capital components was $23.7 million for the three months ended March 31, 2011, compared to $21.6 million for the three months ended March 31, 2010. The net cash provided during the first quarter of 2011 primarily reflects positive cash flows from:

• accounts receivable (representing a seasonal decrease in receivables outstanding at Avista Utilities and Advantage IQ),

• a decrease in materials and supplies, fuel stock and natural gas stored, and

• A decrease in other current assets (primarily due to a decrease in income taxes receivable).

These positive cash flows were partially offset by net cash outflows related to accounts payable.

The net cash provided during the first quarter of 2010 primarily reflects an increase in cash flows from:

• accounts receivable (representing a seasonal decrease in the receivables outstanding),

• other current assets (primarily representing a decrease in income taxes receivable), and

• materials and supplies, fuel stock and natural gas stored (primarily representing a seasonal drawdown of natural gas stored).

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

Contributions to our defined benefit pension plan were $8.5 million for the first quarter of 2011 compared to $7.0 million for the first quarter of 2010. Cash paid for interest decreased to $6.4 million for the first quarter of 2011, compared to $8.1 million for the first quarter of 2010.

Investing Activities Net cash provided by investing activities was $0.2 million for the three months ended March 31, 2011, an increase compared to net cash used of $47.3 million for the three months ended March 31, 2010. Utility property capital expenditures increased for the first quarter of 2011 as compared to the first quarter of 2010, and funds held from customers at Advantage IQ decreased by $47.6 million (compared to an increase of $2.6 million for the first quarter of 2010). 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 used in financing activities was $111.0 million for the three months ended March 31, 2011 compared to $31.2 million for the three months ended March 31, 2010. During the first quarter of 2011, our short-term borrowings decreased $45.0 million. Cash dividends paid increased to $15.8 million (or 27.5 cents per share) for the first quarter of 2011 from $13.8 million (or 25 cents per share) for the first quarter of 2010. We issued $8.5 million of common stock during the first quarter of 2011, including $5.8 million under a sales agency agreement. Additionally, customer funds obligations at Advantage IQ decreased by $47.6 million (see explanation under “Investing Activities”).

During the first quarter of 2010, our short-term borrowings decreased $17.0 million.

Overall Liquidity

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

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AVISTA CORPORATION

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 $400.0 million committed line of credit.

As of March 31, 2011, we had $312.9 million of available liquidity under our committed line of credit. With our $400.0 million credit facility that expires in 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 March 31, 2011, that we would potentially be required to post additional collateral up to $133 million. The additional collateral amount is higher than the amount disclosed in Note 5 of the Notes to Condensed 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 March 31, 2011, 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.

Dodd-Frank Wall Street Reform and Consumer Protection Act

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted into law in July 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.

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AVISTA CORPORATION

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 including certain proposals to delay various implementation steps defined in the Act. We 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 March 31, 2011 and December 31, 2010 (dollars in thousands):

	March 31, 2011					December 31, 2010
			Percent					Percent
	Amount		of total			Amount		of total
Current portion of long-term debt	$	360		—	%	$	358		—	%
Current portion of nonrecourse long-term debt		12,754		0.5			12,463		0.5
Short-term borrowings		65,000		2.7			110,000		4.5
Long-term debt to affiliated trusts		51,547		2.1			51,547		2.1
Nonrecourse long-term debt		43,164		1.8			46,471		1.9
Long-term debt		1,101,814		45.2			1,101,499		45.0
Total debt		1,274,639		52.3			1,322,338		54.0
Total Avista Corporation stockholders’ equity		1,160,379		47.7			1,125,784		46.0
Total	$	2,435,018		100.0	%	$	2,448,122		100.0	%

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 $34.6 million during the first quarter of 2011 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 $400.0 million committed line of credit will supplement these funds to the extent necessary.

We are planning to issue up to $25 million of common stock in 2011 (including first quarter issuances) 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 the first quarter of 2011 we sold a total of 255,000 shares for a total of $5.8 million. As of March 31, 2011, we had 0.8 million shares available to be issued under this agreement.

In February 2011, we entered into a new committed line of credit with various financial institutions 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 that had expiration dates in April 2011.

Our committed line of credit agreement contains customary covenants and default provisions, including a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 65 percent at any time. As of March 31, 2011, we were in compliance with this covenant with a ratio of 52.4 percent.

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AVISTA CORPORATION

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 three months ended March 31 (dollars in thousands):

	2011			2010
Balance outstanding at end of period	$	65,000		$	70,000
Letters of credit outstanding at end of period	$	22,123		$	27,948
Maximum balance outstanding during the period	$	110,000		$	100,000
Average balance outstanding during the period	$	85,383		$	68,667
Average interest rate during the period		1.19	%		0.57	%
Average interest rate at end of period		1.55	%		0.46	%

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 March 31, 2011, Avista Corp. and its subsidiaries were in compliance with all of the covenants of their financing agreements.

Avista Utilities Capital Expenditures

We expect utility capital expenditures to be $250 million for 2011, and between $230 million and $240 million for each of 2012 and 2013. 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.

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 are evaluating various proposals received under this RFP. 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.”

The development of a proposed 1,000-3,000 MW transmission project that would extend from British Columbia, Canada to Northern California has undergone a transformation from a single project into two separate projects. The project would now be implemented in two sections; one from Canada to northeastern Oregon (the northern section) and one from northeastern Oregon to 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. BC Hydro 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 $0.8 million to the project to date with no additional funding anticipated in 2011.

Advantage IQ Credit Agreement

In April 2011, Advantage IQ entered into a new $40.0 million three-year committed line of credit agreement with a financial institution that replaced its $15.0 million committed credit agreement that had an expiration date of May 2011. The credit agreement is secured by substantially all of Advantage IQ’s assets. There were no borrowings outstanding under Advantage IQ’s previous credit agreement as of March 31, 2011 and December 31, 2010.

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 $9.2 million as of March 31, 2011 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 $33.6 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, Avista Capital purchased shares held by one of the previous owners of Cadence Network for $5.6 million.

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Pension Plan

As of March 31, 2011, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. We contributed $21 million to the pension plan in 2010. We expect to contribute $26 million to the pension plan in 2011 ($8.5 million was contributed in the first quarter of 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 5 of the Notes to Condensed Consolidated Financial Statements.” The following table summarizes our credit ratings as of May 5, 2011:

	Standard & Poor’s (1)		Moody’s (2)
Avista Corporation
Corporate/Issuer rating		BBB		Baa2
Senior secured debt		BBB+		A3
Senior unsecured debt		BBB		Baa2
Rating outlook		Stable		Stable

(1) Standard & Poor’s lowest level of “investment grade” credit rating is BBB-. Ratings were upgraded in March 2011.

(2) Moody’s lowest level of “investment grade” credit rating is Baa3. Ratings were upgraded in March 2011.

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.

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.

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

Our future contractual obligations have not changed materially from the amounts disclosed in the 2010 Form 10-K, with the following exceptions:

As of March 31, 2011, we had $65.0 million of borrowings outstanding under our committed line of credit. There were $110.0 million in borrowings outstanding as of December 31, 2010.

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Redeemable noncontrolling interests decreased to $42.8 million as of March 31, 2011 from $46.7 million as of December 31, 2010 due to the redemption of noncontrolling interests, partially offset by an increase in the value.

Economic Conditions

The general economic data, on both national and local levels, contained in this section are based, in part, on independent government and industry publications, reports by market research firms or other independent sources. While we believe that these publications and other sources are reliable, we have not independently verified such data and can make no representation as to its accuracy.

Economic growth in the region we serve has slowed dramatically in the last couple of years. However, we have experienced customer growth, although this growth is less than we had been experiencing in recent years prior to the economic downturn. Employment improved in most of our service area after enduring significant cutbacks in the construction, forest products, mining and manufacturing sectors. Non-farm employment growth for March 2011 compared to March 2010 was 2.3 percent in Coeur d’Alene, Idaho and 1.1 percent Medford, Oregon. It was only 0.3 percent in the Spokane area but with positives in the retail trade and health sectors, offset by weakness in state and local government jobs. U.S. nonfarm sector jobs grew by 1.0 percent in the same twelve-month period. Unemployment rates declined in March 2011 from the year earlier levels in Spokane and Medford, but rose slightly in Coeur d’Alene. The Spokane rate declined from 11.0 percent to 10.5 percent from March 2010 to March 2011 and Medford from 14.1 percent to 12.7 percent while Coeur d’Alene went from 12.4 percent to 12.6 percent. The U.S. rate declined from 10.2 percent to 9.2 percent in the same period. Although showing modest improvement, the housing market in Coeur d’Alene has a higher foreclosure rate than the national average. The March 2011 national rate was 0.18 percent with 0.34 percent in Kootenai County, Idaho. The Spokane housing market had a foreclosure rate of 0.11 percent and Jackson County, Oregon was 0.16 percent.

Environmental Issues and Other Contingencies

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

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

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.

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

Climate Change and Greenhouse Gas Emission Reduction Initiatives

Concerns about long-term global climate changes could have a significant effect on our business. Our operations could also be affected by changes in laws and regulations intended to mitigate the risk of global climate changes, including restrictions on the operation of our power generation resources and obligations imposed on the sale of natural gas. Changing temperatures and precipitation, including snowpack conditions, affect the availability and timing of the streamflows, which impacts hydroelectric generation. Extreme weather events could increase service interruptions, outages and maintenance costs. Changing temperatures could also increase or decrease customer demand.

Greenhouse gas (GHG) emission standards could result in significant compliance costs. Such standards could also preclude us from developing, operating or contracting with certain types of generating plants.

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AVISTA CORPORATION

We continue to monitor and evaluate the possible adoption of international, national, regional, or state GHG emission legislation and regulations. In particular, climate change legislation was passed in the state of Washington, which includes a bill establishing GHG emissions reduction targets and another requiring that regulated sources report GHG emission from facilities that emit more than 10,000 metric tons of GHGs per year. As the U.S. Congress has not enacted any comprehensive climate change legislation, for the foreseeable future climate change regulations are expected to emerge from the EPA and individual states.

Although we are actively monitoring developments for climate change policies and restrictions on GHG emissions, it is important to note that we have relatively low GHG emissions as compared to other investor-owned utilities in the U.S. With 60 percent of our electric generation resource mix derived from renewable sources (including hydroelectric, biomass and wind contracts) and a majority of our thermal generation fueled with natural gas, plus a commitment to energy efficiency, we are among the lowest carbon-emitting utilities in the nation.

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

• anticipate and evaluate strategic needs and opportunities relating to climate change,

• analyze the company-wide implications of various trends and proposals,

• develop recommendations on positions and action plans, and

• facilitate internal and external communications regarding climate change issues.

Longer-term issues followed by the Climate Council include: state and federal emissions tracking and certification, recommendations for GHG reduction goals and activities, the merits of different reduction programs, the development of legislation, and climate change policies and activities adopted by other organizations.

National Legislation

Climate change legislation has been proposed in the U.S. Congress; however, recent actions in the U.S. Senate and the outcome of the mid-term (November 2010) elections strongly indicate that climate change legislation is unlikely until 2013 or later. We continue to monitor the situation for new developments that could affect our business.

Recent EPA Initiatives Related to Climate Change

After a public comment and review period, in December 2009, the EPA issued an “endangerment finding” regarding GHG emissions from motor vehicles under section 202(a) of Clean Air Act (CAA). The EPA found that the current and projected concentrations of the six key well-mixed greenhouse gases - carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride - in the atmosphere threaten the public health and welfare of current and future generations. The EPA also found that the combined emissions of these well-mixed greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the GHG pollution which threatens public health and welfare. The EPA’s findings are currently being challenged in the U.S. Court of Appeals for the District of Columbia Circuit. On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing GHG emission standards for mobile sources. The GHG emission standards for mobile sources became effective on January 2, 2011. The EPA has concluded that the CAA requires the agency to regulate GHG emissions from stationary sources through its preconstruction and operating permit programs on the date when EPA regulations require any source (mobile or stationary) to meet GHG emission limits. The EPA’s final decision has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In May 2010, the EPA finalized a rule establishing an applicability threshold for regulating GHG emissions from stationary sources through the preconstruction and operating permit programs.

The EPA issued a series of rules on December 23, 2010 to narrow the CAA permitting requirement so that facilities with GHG emissions below the levels set in the tailoring rule do not need permits as well as to give the EPA authority to issue GHG permits in states that need to revise their permitting regulations to cover GHG emissions. On January 2, 2011, rules took effect requiring that permits issued under the CAA for new large stationary sources begin to address GHG emissions, as well as require Best Available Control Technology (BACT) to control these emissions. On March 11, 2011, the EPA proposed a rule that would defer, for a period of three years, the GHG permitting requirements for carbon dioxide for utilities, boilers and other industrial facilities using biomass. The EPA also has announced a schedule for issuing regulations controlling GHG emissions from electric generating units. According to this schedule, the EPA will propose standards for natural gas, oil and coal-fired electric generating units by July 26, 2011, and issue final standards by May 26, 2012. The EPA agreed to this schedule as part of a settlement with several states, local governments and environmental organizations that sued the EPA over its failure to update emissions standards for power plants and refineries as required by Section 111 of the CAA. Section 111 requires the EPA to issue NSPS that set emissions limits for new facilities and address emissions from existing facilities. These rules could significantly impact the costs of modifying existing thermal plants as well as building new thermal generation sources. We cannot determine or estimate the costs of compliance with such measures at this time.

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AVISTA CORPORATION

In September 2009, the EPA finalized a rule that requires facilities emitting over 25,000 metric tons of GHG a year to report their emissions to the EPA beginning in January 2011 for 2010 emissions. The rule became effective on December 29, 2009. On March 18, 2011, the EPA issued a rule extending the deadline for reporting 2010 GHG emissions data to September 30, 2011. Based on rule applicability criteria, Colstrip, Coyote Springs 2, and the Rathdrum CT are required to report GHGs. These facilities currently report carbon dioxide to the EPA under the Acid Rain Program and it is expected that the operators of Colstrip and Coyote Springs 2 will be responsible for any additional GHG reporting. Based on our evaluation of historical emissions from 2004-2008, none of our other electrical generation facilities meet the threshold requirements. The rule also requires that natural gas distribution system throughput be reported. Monitoring methods, per the rule, are currently in place and development of a GHG Monitoring Plan for covered facilities was in place prior to the April 1, 2010 deadline for required monitoring method implementation. The purpose of the plan is to document the process and procedures for collecting and reviewing the data needed to estimate annual GHG emissions. On March 22, 2010, the EPA proposed to amend its reporting rule to include several new source categories, including reporting of GHG fugitive emissions from electric power transmission and distribution systems, fugitive emissions from natural gas distribution systems, and fugitive emissions from natural gas storage facilities. Reporting for these additional sources is required by March 31, 2012 for 2011 emissions. We will report on natural gas distribution system fugitives and the operator of the natural gas storage facility, of which we are a part owner, will report on fugitives from that facility. On May 13, 2010, the EPA issued a final rule on GHG emissions reporting for stationary sources. As stated above, Colstrip, Coyote Springs 2 and the Rathdrum CT are required to report GHG emissions, even under modified rule. We continue to monitor developments.

State Activities

The states of Washington and Oregon have statutory targets to reduce GHG emissions. Washington’s targets are intended to reduce GHG emission to 1990 levels by 2020; to 25 percent below 1990 levels by 2035; and to 50 percent below 1990 levels by 2050. Oregon’s targets would reduce GHG emissions to 10 percent below 1990 levels by 2020 and 75 percent below 1990 levels by 2050. Both states enacted their targets expecting that they would be met through a combination of renewable energy standards, and assorted “complementary policies,” such as land-use policies, energy efficiency codes for buildings, renewable fuel standards and vehicle emission standards. However, neither state has adopted any comprehensive requirements aimed at achieving these targets.

Washington and Oregon continue to participate in the Western Climate Initiative (WCI), along with the states of Arizona, California, New Mexico, Utah and Montana, and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. The WCI has adopted a regional cap-and-trade program with an overall regional goal for reducing GHG emissions to 15 percent below 2005 levels by 2020. The WCI’s program design includes cap-and-trade regulation of the electricity sector in 2012 and of emissions associated with the distribution of natural gas by 2015. Neither Washington, nor Oregon has enacted legislation establishing the WCI’s program requirements.

In 2009, the Governor of Washington issued an Executive Order (09-05) directing the Washington Department of Ecology to estimate GHG emissions by sector and source and to identify potential reduction requirements for them in preparation for the eventual imposition of state and/or federal GHG regulations. The Department of Ecology has identified “facilities” that emit more than 25,000 metric tons of GHG annually and has forecasted that those facilities will need to reduce their emissions by 9.2 percent in order for the state to achieve its GHG emissions reduction target for 2020. Our natural gas distribution system has been specifically identified as a “facility” along with our thermal plants and contracts with thermal plants. Fossil-fueled generation outside of the state has also been generically identified as a “facility” for the purposes of potentially regulating emissions associated with the importation of power to serve our Washington loads. The state of Washington has yet to identify how it might impose and enforce emission reductions. Nevertheless, the State will make significant progress in meeting its greenhouse gas emission targets in light of the enactment of SB 5769, which requires the only coal-fired generation facility operating in the state to completely cease operations in 2025. The state’s Department of Ecology has adopted regulations to ensure that Washington’s State Implementation Plan comports with the requirements of the EPA’s regulation of GHG emissions. We will continue to monitor actions by the department as it may proceed to adopt additional regulations under its Clean Air Act authorities.

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

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Initiative Measure 937 (I-937), the Energy Independence Act, was passed into law through the 2006 General Election in Washington. I-937 requires investor-owned, cooperative, and government-owned electric utilities with over 25,000 customers to acquire qualified renewable energy resources and/or renewable energy credits in incremental amounts until those resources or credits equal 15 percent of the utility’s total retail load in 2020. I-937 also requires these utilities to meet biennial energy conservation targets, the first of which must be met in 2012. Furthermore, by January 1, 2012, electric utilities subject to I-937’s mandates must have acquired enough incremental renewable energy and/or renewable energy credits to meet 3 percent of their load. Failure to comply with renewable energy and energy efficiency standards will result in penalties of at least $50 per MWh being assessed against a utility for each MWh it is deficient in meeting a standard. A utility would be deemed to comply with the renewable energy standard if it invests at least 4 percent of its total annual retail revenue requirement on the incremental costs of renewable energy resources and/or renewable energy credits.

Electric Integrated Resource Plan

Our most recent Electric Integrated Resource Plan (IRP), which we filed with the WUTC and the IPUC in the third quarter 2009, includes the acquisition of additional renewable resources such that, if the Preferred Resources Strategy is implemented, we would be compliant with the requirements of I-937 by the various milestone dates. 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 new generation requirements by 26 percent or 339 MW,

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

• Hydroelectric upgrades at existing facilities will generate additional renewable energy.

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

In February 2011, we issued an 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 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. While this RFP does not include the development of a wind site for which we acquired the development rights in 2008, we continue to study that 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. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes or if a new or modified renewable energy standards are enacted at either the state or federal levels.

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

Chicago Climate Exchange

In October 2007, we became a member of the Chicago Climate Exchange (CCX). Members agreed to reduce their GHG emissions by 6 percent from an established baseline by 2010. In October 2010, the CCX announced that they would not be offering a Phase 3 program. As such, we concluded our participation in the CCX in 2010. Our 2010 CCX compliance obligation was met with the retirement of surplus CCX credits. All of our remaining surplus CCX credits have been voluntarily retired.

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Clean Air Act

We must comply with requirements under the CAA and Clean Air Act Amendments (CAAA) in operating our thermal generating plants. The most significant impacts on us, related to the CAA and the 1990 CAAA, pertain to Colstrip, which is a “Phase II” coal-fired plant for sulfur dioxide (SO2) under the CAAA. However, we do not expect Colstrip to be required to implement any additional SO2 mitigation in the foreseeable future in order to continue operations. Our other thermal projects are subject to various CAAA standards. Every five years each of the other thermal projects requires an updated operating permit (known as a Title V permit), which addresses, among other things, the compliance of the plant with the CAAA. The operating permit for the Rathdrum CT was renewed in 2006 (expires in 2011) and the operating permit for the Kettle Falls GS was renewed in 2007 (expires in 2012). Coyote Springs 2 was issued a renewed Title V permit in 2008 that expires in 2013. Boulder Park and the Northeast CT do not require a Title V permit based on their limited output and instead each has a synthetic minor permit that does not expire.

Mercury Emissions

In 2006, the Montana Department of Environmental Quality (Montana DEQ) adopted final rules for the control of mercury emissions from coal-fired plants. The new rules set strict mercury emission limits by 2010, and establish a recurring ten-year review process to ensure facilities are keeping pace with advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities. The joint owners of Colstrip believe, based upon current results, that the plant will be able to comply with the Montana law without utilizing the temporary alternate emissions limit provision. In addition, on March 21, 2011, the EPA issued a proposed rule that, if finalized, will establish maximum achievable control technology standards to control hazardous air pollutants, including mercury, from new and existing coal- and oil-fired power plants.

National Ambient Air Quality Standards

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

Coal Ash Management/Disposal

Currently, coal combustion byproducts (CCBs) are not regulated by the EPA as a hazardous waste. Under a proposed rule issued in 2010, the EPA is currently reconsidering the classification of CCBs under the Resource Conservation and Recovery Act (RCRA). Should the EPA determine to regulate CCBs as a hazardous waste under the RCRA, such action could have a significant impact on future operations of Colstrip. The EPA provided proposed draft rules in 2010 for public review and comment, with two alternatives. One would require management of CCBs as a hazardous waste under Subtitle C of RCRA; the other would regulate coal ash under Subtitle D, for solid wastes. The EPA has not indicated a clear schedule for final rulemaking.

Fisheries

A number of species of fish in the Northwest, including the Snake River sockeye salmon and fall chinook salmon, the Kootenai River white sturgeon, the upper Columbia River steelhead, the upper Columbia River spring chinook salmon and the bull trout, are listed as threatened or endangered under the Federal Endangered Species Act. Thus far, measures that were adopted and implemented to save the Snake River sockeye salmon and fall chinook salmon have not directly impacted generation levels at any of our hydroelectric facilities. We purchase power under long-term contracts with certain PUDs on the Columbia River that are directly impacted by ongoing mitigation measures for salmon and steelhead. The reduction in generation at these projects is relatively minor, resulting in minimal economic impact on our operations at this time. We cannot predict the economic costs to us resulting from future mitigation measures. We received a 45-year FERC operating license for Cabinet Gorge and Noxon Rapids in March 2001 that incorporates a comprehensive settlement agreement. The restoration of native salmonid fish, particularly bull trout, is a key part of the agreement. The result is a collaborative bull trout recovery program with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana on the lower Clark Fork River, consistent with requirements of the FERC license. See “Hydroelectric Licensing” and “Fish Passage at Cabinet Gorge and Noxon Rapids” in “Note 11 of the Notes to Condensed Consolidated Financial Statements” for further information.

Western Power Market Issues

The FERC continues to conduct proceedings and investigations related to market controls within the western United States that include proposals by certain parties to impose refunds, and some of the FERC’s decisions have been appealed in Federal Courts. Certain parties have asserted claims for significant refunds from us, which could result in liabilities for refunding revenues recognized in prior periods. We have joined other parties in opposing these proposals. We believe that we have adequate reserves established for refunds that may be ordered. The refund proceedings provide that any refunds would be offset against unpaid energy debts due to the same party. As of March 31, 2011, our accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties. See “California Refund Proceeding” and “Pacific Northwest Refund Proceeding” in “Note 11 of the Notes to Condensed Consolidated Financial Statements” for further information on the refund proceedings.

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Other

For other environmental issues and other contingencies see “Note 11 of the Notes to Condensed Consolidated Financial Statements.”

Item 3. Quantitative and Qualitative Disclosures about Market Risk

General

Our qualitative general market risk disclosures have not materially changed during the three months ended March 31, 2011. Please refer to the 2010 Form 10-K.

Commodity Price Risk

Our qualitative commodity price risk disclosures have not materially changed during the three months ended March 31, 2011. Please refer to the 2010 Form 10-K.

The following table presents energy commodity derivative fair values as a net asset or (liability) as of March 31, 2011 that are expected to settle in each respective year (dollars in thousands):

	Purchases												Sales
	Electric Derivatives						Gas Derivatives						Electric Derivatives					Gas Derivatives
Year	Physical			Financial			Physical			Financial			Physical			Financial		Physical			Financial
2011	$	(4,512	)	$	(5,712	)	$	(16,823	)	$	4,681		$	1,674		$	976	$	27		$	(3,624	)
2012		(1,759	)		(6,797	)		(12,742	)		(1,159	)		19			478		(1,637	)		(765	)
2013		1,299			1,829			(4,246	)		1,694			(64	)		1,229		(1,524	)		(2,142	)
2014		1,630			—			297			20			(96	)		—		(1,126	)		—
2015		2,699			—			388			116			(165	)		—		—			—
Thereafter		10,981			—			—			—			(1,189	)		—		—			—

Credit Risk

Our credit risk has not materially changed during the three months ended March 31, 2011. Please refer to the 2010 Form 10-K.

Interest Rate Risk

Our qualitative interest rate risk disclosures have not materially changed during the three months ended March 31, 2011. Please refer to the 2010 Form 10-K.

In the second quarter of 2010, we entered into two interest rate swap agreements with a total notional amount of $50.0 million and a mandatory cash settlement date of July 2012.

Under the terms of the outstanding interest rate swap agreements, the value of the interest rate swaps is determined based upon Avista Corp. paying a fixed rate and receiving a variable rate based on LIBOR for a term of ten years. As of March 31, 2011, we had a long-term derivative asset of $0.4 million and an offsetting regulatory liability on the Condensed Consolidated Balance Sheets in accordance with regulatory accounting practices. Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) will be amortized as a component of interest expense over the life of the forecasted interest payments.

Foreign Currency Risk

Our qualitative foreign currency risk disclosures have not materially changed during the three months ended March 31, 2011. Please refer to the 2010 Form 10-K. As of March 31, 2011, we had a current derivative asset for foreign currency hedges of $0.1 million included in other current assets on the Condensed Consolidated Balance Sheet. As of March 31, 2011, we had entered into 42 Canadian currency forward contracts with a notional amount of $20.5 million ($20.0 million Canadian).

Risk Management

We use a variety of techniques to manage risks for energy resources and wholesale energy market activities. We have an energy resources risk policy and control procedures to manage these risks, both qualitative and quantitative. Please refer to the 2010 Form 10-K for discussion of risk management policies and procedures.

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Further information for derivatives and fair values is disclosed at “Note 5 of the Notes to Condensed Consolidated Financial Statements” and “Note 9 of the Notes to Condensed Consolidated Financial Statements.”

Item 4. Controls and Procedures

The Company has disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) to ensure that information required to be disclosed in the reports it files or submits under the Act is recorded, processed, summarized and reported on a timely basis. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial officers as appropriate to allow timely decisions regarding required disclosure. Under the supervision and with the participation of the Company’s management, including the Company’s principal executive officer and principal financial officer, the Company has evaluated its disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon the Company’s evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures are effective at a reasonable assurance level as of March 31, 2011.

There have been no changes in the Company’s internal control over financial reporting that occurred during the first quarter of 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

See “Note 11 of the Notes to Condensed Consolidated Financial Statements” in “Part I. Financial Information Item 1. Condensed Consolidated Financial Statements.”

Item 1A. Risk Factors

Please refer to the 2010 Form 10-K for disclosure of risk factors that could have a significant impact on our results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2010 Form 10-K. In addition to these risk factors, 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.

Item 6. Exhibits

12	Computation of ratio of earnings to fixed charges*
15	Letter Re: Unaudited Interim Financial Information*
31.1	Certification of Chief Executive Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)*
31.2	Certification of Chief Financial Officer (Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)*
32	Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)**
101	The following financial information from the Quarterly Report on Form 10-Q for the period ended March 31, 2011, formatted in XBRL (Extensible Business Reporting Language) and furnished electronically herewith: (i) the Condensed Consolidated Statements of Income; (ii) Condensed Consolidated Statements of Comprehensive Income; (iii) the Condensed Consolidated Balance Sheets; (iv) the Condensed Consolidated Statements of Cash Flows; (v) the Condensed Consolidated Statements of Equity and Redeemable Noncontrolling Interests; and (vi) the Notes to Condensed Consolidated Financial Statements, tagged as blocks of text.**

* Filed herewith.

** Furnished herewith.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	AVISTA CORPORATION
	(Registrant)
Date: May 6, 2011	/s/ Mark T. Thies
	Mark T. Thies
	Senior Vice President and
	Chief Financial Officer
	(Principal Financial Officer)

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EX-12

Exhibit 12

AVISTA CORPORATION

Computation of Ratio of Earnings to Fixed Charges

Consolidated

(Thousands of Dollars)

	Three months
	ended			Years Ended December 31
	March 31, 2011			2010			2009			2008			2007			2006
Fixed charges, as defined:
Interest charges	$	17,355		$	72,010		$	61,361		$	74,914		$	80,095		$	88,426
Amortization of debt expense and premium - net		1,236			4,414			5,673			4,673			6,345			7,741
Interest portion of rentals		460			2,027			1,874			1,601			1,612			1,802
Total fixed charges	$	19,051		$	78,451		$	68,908		$	81,188		$	88,052		$	97,969
Earnings, as defined:
Pre-tax income from continuing operations	$	66,040		$	146,105		$	134,971		$	120,382		$	63,061		$	114,927
Add (deduct):
Capitalized interest		(438	)		(298	)		(545	)		(4,612	)		(3,864	)		(2,934	)
Total fixed charges above		19,051			78,451			68,908			81,188			88,052			97,969
Total earnings	$	84,653		$	224,258		$	203,334		$	196,958		$	147,249		$	209,962
Ratio of earnings to fixed charges		4.44			2.86			2.95			2.43			1.67			2.14

EX-15

Exhibit 15

May 6, 2011

Avista Corporation

Spokane, Washington

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of Avista Corporation and subsidiaries for the periods ended March 31, 2011 and 2010, as indicated in our report dated May 6, 2011; because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, is incorporated by reference in Registration Statement Nos. 2-81697, 2-94816, 033-54791, 333-03601, 333-22373, 333-58197, 333-33790, 333-47290, and 333-126577 on Form S-8; and in Registration Statement Nos. 033-53655, 333-63243, 333-64652, 333-155657, and 333-163609 on Form S-3.

We are also aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.

/s/ Deloitte & Touche LLP

Seattle, Washington

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Scott L. Morris, certify that:

1. I have reviewed this report on Form 10-Q of Avista Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	/s/ Scott L. Morris
	Scott L. Morris
	Chairman of the Board, President
	and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Mark T. Thies, certify that:

1. I have reviewed this report on Form 10-Q of Avista Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2011	/s/ Mark T. Thies
	Mark T. Thies
	Senior Vice President and
	Chief Financial Officer
	(Principal Financial Officer)

EX-32

Exhibit 32

AVISTA CORPORATION

CERTIFICATION OF CORPORATE OFFICERS

(Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the

Sarbanes-Oxley Act of 2002)

Each of the undersigned, Scott L. Morris, Chairman of the Board, President and Chief Executive Officer of Avista Corporation (the “Company”), and Mark T. Thies, Senior Vice President and Chief Financial Officer of the Company, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934, as amended, and that the information contained therein fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2011

/s/ Scott L. Morris

Scott L. Morris

Chairman of the Board, President

and Chief Executive Officer

/s/ Mark T. Thies

Mark T. Thies

Senior Vice President and

Chief Financial Officer