Edgar Filing: AVISTA CORP

Form 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, 2009

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

For the transition period from to

Commission file number 1-3701

AVISTA CORPORATION

(Exact name of registrant as specified in its charter)


Washington		91-0462470
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1411 East Mission Avenue, Spokane, Washington		99202-2600
(Address of principal executive offices)		(Zip Code)

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

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

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 ¨ 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 ¨	Smaller reporting company ¨
		(Do not check if a 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 27, 2009, 54,643,215 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, 2009 and 2008	3

		Condensed Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2009 and 2008	4

		Condensed Consolidated Balance Sheets - March 31, 2009 and December 31, 2008	5

		Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2009 and 2008	7

		Condensed Consolidated Statements Stockholders’ Equity - Three Months Ended March 31, 2009 and 2008	8

		Notes to Condensed Consolidated Financial Statements	9

		Report of Independent Registered Public Accounting Firm	31

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54

	Item 4.	Controls and Procedures	54

Part II.	Other Information:

	Item 1.	Legal Proceedings	55

	Item 1A.	Risk Factors	55

	Item 5.	Other Information	55

	Item 6.	Exhibits	56

Signature			57

FORWARD-LOOKING STATEMENTS

Our Quarterly Report on Form 10-Q contains forward-looking statements, which should be read with the cautionary statements and important factors included at “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” on pages 32-33. 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. All forward-looking statements are subject to a variety of risks and uncertainties and other factors. Many of these factors are beyond our control and could have a significant effect on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in our statements.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands, except per share amounts

(Unaudited)


	2009			2008
Operating Revenues:
Utility revenues	$	460,864		$	472,272
Non-utility energy marketing and trading revenues		5,997			6,416
Other non-utility revenues		20,609			17,619

Total operating revenues		487,470			496,307

Operating Expenses:
Utility operating expenses:
Resource costs		289,692			318,226
Other operating expenses		57,732			51,719
Depreciation and amortization		22,923			21,442
Taxes other than income taxes		26,895			25,085
Non-utility operating expenses:
Resource costs		5,728			5,920
Other operating expenses		17,293			13,845
Depreciation and amortization		1,362			1,009

Total operating expenses		421,625			437,246

Income from operations		65,845			59,061

Other Income (Expense):
Interest expense		(15,588	)		(18,929	)
Interest expense to affiliated trusts		(1,358	)		(1,696	)
Capitalized interest		548			841
Other income (expense) - net		(560	)		1,176

Total other income (expense)-net		(16,958	)		(18,608	)

Income before income taxes		48,887			40,453
Income taxes		17,468			15,089

Net income		31,419			25,364
Less: Net income attributable to noncontrolling interests		(393	)		(133	)

Net income attributable to Avista Corporation	$	31,026		$	25,231

Weighted-average common shares outstanding (thousands), basic		54,616			53,020
Weighted-average common shares outstanding (thousands), diluted		54,722			53,382
Earnings per common share attributable to Avista Corporation:
Basic	$	0.57		$	0.48

Diluted	$	0.57		$	0.47

Dividends paid per common share	$	0.180		$	0.165

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2009			2008
Net income	$	31,419		$	25,364

Other Comprehensive Income (Loss):
Unrealized losses on interest rate swap agreements - net of taxes of $(2,063)		—			(3,831	)
Reclassification adjustment for realized losses on interest rate swap agreements deferred as a regulatory asset (included in long-term debt) - net of taxes of $5,738		—			10,657
Change in unfunded benefit obligation for pension plan - net of taxes of $54 and $237 respectively		101			440

Total other comprehensive income		101			7,266

Comprehensive income		31,520			32,630
Comprehensive income attributable to noncontrolling interests		(393	)		(133	)

Comprehensive income attributable to Avista Corporation	$	31,127		$	32,497

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)


	March 31, 2009		December 31, 2008
Assets:
Current Assets:
Cash and cash equivalents	$	35,654	$	24,313
Accounts and notes receivable-less allowances of $43,017 and $45,062		215,542		218,846
Utility energy commodity derivative assets		4,599		11,234
Regulatory asset for utility derivatives		51,268		60,229
Funds held for customers		60,957		59,095
Materials and supplies, fuel stock and natural gas stored		24,723		53,526
Deferred income taxes		18,509		18,561
Income taxes receivable		2,456		22,769
Other current assets		16,275		13,654

Total current assets		429,983		482,227

Net Utility Property:
Utility plant in service		3,371,959		3,343,535
Construction work in progress		78,362		77,487

Total		3,450,321		3,421,022
Less: Accumulated depreciation and amortization		946,335		928,831

Total net utility property		2,503,986		2,492,191

Other Property and Investments:
Investment in exchange power-net		25,521		26,133
Investment in affiliated trusts		13,403		13,403
Goodwill		20,509		21,132
Other property and investments-net		76,091		78,208

Total other property and investments		135,524		138,876

Deferred Charges:
Regulatory assets for deferred income taxes		101,705		115,005
Regulatory assets for pensions and other postretirement benefits		169,396		172,278
Other regulatory assets		83,927		85,112
Non-current utility energy commodity derivative assets		35,322		49,313
Power cost deferrals		44,867		57,607
Unamortized debt expense		31,862		33,004
Other deferred charges		7,130		5,134

Total deferred charges		474,209		517,453

Total assets	$	3,543,702	$	3,630,747

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED BALANCE SHEETS - continued

Avista Corporation

Dollars in thousands

(Unaudited)


	March 31, 2009			December 31, 2008
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	136,648		$	176,116
Customer fund obligations		60,957			59,095
Current portion of long-term debt		17,132			17,207
Short-term borrowings		226,100			252,200
Interest accrued		18,942			10,871
Utility energy commodity derivative liabilities		55,867			71,463
Other current liabilities		107,940			101,592

Total current liabilities		623,586			688,544

Long-term debt		809,686			809,258

Long-term debt to affiliated trusts		113,403			113,403

Other Non-Current Liabilities and Deferred Credits:
Regulatory liability for utility plant retirement costs		214,770			213,747
Non-current regulatory liability for utility derivatives		25,285			42,172
Pensions and other postretirement benefits		170,739			184,588
Deferred income taxes		470,913			488,940
Other non-current liabilities and deferred credits		85,000			82,006

Total other non-current liabilities and deferred credits		966,707			1,011,453

Total liabilities		2,513,382			2,622,658

Commitments and Contingencies (See Notes to Condensed Consolidated Financial Statements)
Stockholders’ Equity:
Avista Corporation Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 54,643,215 and 54,487,574 shares outstanding		775,813			774,986
Accumulated other comprehensive loss		(5,991	)		(6,092	)
Retained earnings		249,398			227,989

Total Avista Corporation stockholders’ equity		1,019,220			996,883
Noncontrolling interests		11,100			11,206

Total stockholders’ equity		1,030,320			1,008,089

Total liabilities and stockholders’ equity	$	3,543,702		$	3,630,747

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Three Months Ended March 31

Dollars in thousands

(Unaudited)


	2009			2008
Operating Activities:
Net income	$	31,419		$	25,364
Non-cash items included in net income:
Depreciation and amortization		24,285			22,451
Benefit for deferred income taxes		(4,859	)		(4,113	)
Power and natural gas cost amortizations, net of deferrals		20,776			27,598
Amortization of debt expense		1,411			1,234
Equity-related AFUDC		(676	)		(893	)
Other		(9,618	)		(2,131	)
Changes in working capital components:
Accounts and notes receivable		5,324			(118,986	)
Materials and supplies, fuel stock and natural gas stored		28,803			13,569
Other current assets		15,606			18,152
Accounts payable		(31,330	)		28,033
Deposits from counterparties		—			13,420
Other current liabilities		10,420			20,850

Net cash provided by operating activities		91,561			44,548

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(41,510	)		(47,680	)
Other capital expenditures		(988	)		(1,099	)
Decrease in restricted cash		—			3,948
Increase in funds held for customers		(1,862	)		(305	)
Other		(1,468	)		(2,295	)

Net cash used in investing activities		(45,828	)		(47,431	)

Financing Activities:
Increase (decrease) in short-term borrowings		(26,100	)		29,000
Redemption and maturity of long-term debt		(114	)		(236	)
Long-term debt and short-term borrowing issuance costs		(307	)		(23	)
Cash paid in interest rate swap agreement		—			(16,395	)
Issuance of common stock		79			108
Cash dividends paid		(9,845	)		(8,754	)
Increase in customer fund obligations		1,862			305
Equity transactions of consolidated subsidiaries		33			25

Net cash provided by (used in) financing activities		(34,392	)		4,030

Net increase in cash and cash equivalents		11,341			1,147
Cash and cash equivalents at beginning of period		24,313			11,839

Cash and cash equivalents at end of period	$	35,654		$	12,986

Supplemental Cash Flow Information:
Cash paid (received) during the period:
Interest	$	7,464		$	7,688
Income taxes		($1,504	)	$	117

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Avista Corporation

For the Three Months Ended March 31, 2009 and 2008

Dollars in thousands

(Unaudited)


	Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Total Avista Corporation Stockholders’ Equity			Non- Controlling Interests			Total Stockholders’ Equity
	Shares	Amount		Accumulated Other Comprehensive Loss			Retained Earnings			Total Avista Corporation Stockholders’ Equity			Non- Controlling Interests			Total Stockholders’ Equity
Balance as of January 1, 2009	54,487,574	$	774,986	$	(6,092	)	$	227,989		$	996,883		$	11,206		$	1,008,089
Net income								31,026			31,026			393			31,419
Equity compensation expense			575								575						575
Issuance of common stock	155,641		79								79						79
Other comprehensive income					101						101						101
Cash dividends paid								(9,845	)		(9,845	)					(9,845	)
Liability to subsidiary minority shareholders								228			228						228
Other			173								173			(499	)		(326	)

Balance as of March 31, 2009	54,643,215	$	775,813	$	(5,991	)	$	249,398		$	1,019,220		$	11,100		$	1,030,320


Balance as of January 1, 2008	52,909,013	$	726,933	$	(19,608	)	$	206,641		$	913,966		$	862		$	914,828
Net income								25,231			25,231			133			25,364
Equity compensation expense			666								666						666
Issuance of common stock	139,981		108								108						108
Other comprehensive income					7,266						7,266						7,266
Cash dividends paid								(8,754	)		(8,754	)					(8,754	)
Liability to subsidiary minority shareholders								627			627						627
Other											—			25			25

Balance as of March 31, 2008	53,048,994	$	727,707	$	(12,342	)	$	223,745		$	939,110		$	1,020		$	940,130

The Accompanying Notes are an Integral Part of These Statements.

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, 2009 and 2008 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 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, 2008 (2008 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2008 Form 10-K for definitions of terms such as capacity, energy and therm.

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 western Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeast and southwest Oregon. 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 including Advantage IQ, Inc. (Advantage IQ), a 74 percent owned subsidiary. Advantage IQ is a provider of facility information and cost management services for multi-site customers throughout North America. See Note 13 for business segment information.

The Company’s operations are exposed to risks including, but not limited to:

•

global financial and economic conditions (including the availability of credit) and their effect on the Company’s ability to obtain funding for working capital and long-term capital requirements on acceptable terms,

•

economic conditions in the Company’s service areas, including the effect on the demand for, and customers’ ability to pay for, the Company’s utility services,

•

streamflow and weather conditions that impact hydroelectric generation, utility operations and customer demand,

•

market prices and supply of wholesale energy, which the Company purchases and sells, including power, fuel and natural gas,

•

regulatory disallowance of the recovery of power and natural gas costs, operating costs and capital investments and the allowance of a reasonable rate of return on investment,

•

the effects of changes in legislative and governmental regulations, including restrictions on emissions from generating plants and requirements for the acquisition of new resources,

•

changes in regulatory requirements,

•

availability of generation facilities,

•

rate increases may change customer demand for electricity and natural gas, and

•

competition.

Also, like other utilities, the Company’s facilities and operations are exposed to natural disasters and terrorism risks or other malicious acts. In addition, the energy business exposes the Company to the financial, liquidity, credit and price risks associated with wholesale purchases and sales of energy commodities.

Basis of Reporting

The 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 financial statements include the Company’s proportionate share of utility plant and related operations resulting from its interests in jointly owned plants.

AVISTA CORPORATION

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 $21.4 million for the three months ended March 31, 2009 and $19.2 million for the three months ended March 31, 2008.

Other Income-Net

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


	2009			2008
Interest income	$	488		$	216
Interest on power and natural gas deferrals		748			968
Equity-related Allowance for Funds Used During Construction		676			893
Net loss on investments		(748	)		(94	)
Other expense		(1,730	)		(825	)
Other income		6			18

Total	$	(560	)	$	1,176

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of March 31, 2009 and December 31, 2008 (dollars in thousands):


	March 31, 2009			December 31, 2008
Unfunded benefit obligation for pensions and other postretirement benefit plans	$	(5,991	)	$	(6,092	)

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, 2008 for the Other businesses and as of December 31, 2008 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):


	Advantage IQ			Other		Total
Balance as of December 31, 2008	$	15,886		$	5,246	$	21,132
Adjustments		(623	)		—		(623	)

Balance as of the March 31, 2009	$	15,263		$	5,246	$	20,509

The adjustment to goodwill during the first quarter of 2009 represents final purchase accounting adjustments for Advantage IQ’s acquisition of Cadence Network based upon the completion of the review of the fair market values of relevant assets and liabilities identified as of the acquisition date.

Other Intangibles

Other Intangibles primarily represent the amounts assigned to client relationships related to the Advantage IQ acquisition of Cadence Network (estimated amortization period of 16 years), software development costs (estimated amortization period of 5 to 7 years) and other. Other Intangibles are included in other properties and investments-net on the Condensed Consolidated Balance Sheets. Amortization expense related to Other Intangibles for the three months ended March 31, 2009 and 2008 was $0.5 million and $0.2 million, respectively.

AVISTA CORPORATION

The gross carrying amount and accumulated amortization of Other Intangibles as of March 31, 2009 and December 31, 2008 are as follows (dollars in thousands):


	March 31, 2009			December 31, 2008
Client relationships	$	8,909		$	8,909
Software development costs		14,630			14,067
Other		570			570

Total other intangibles		24,109			23,546
Less accumulated amortization		(6,266	)		(5,804	)

Total other intangibles - net	$	17,843		$	17,742

The following table details the future estimated amortization expense related to Other Intangibles (dollars in thousands):


	2009		2010		2011		2012		2013
Estimated amortization expense	$	1,957	$	2,502	$	2,301	$	2,180	$	1,926

Regulatory Deferred Charges and Credits

The Company prepares its condensed consolidated financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” The Company prepares its condensed financial statements in accordance with SFAS No. 71 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.

SFAS No. 71 requires the Company to reflect the impact of regulatory decisions in its condensed financial statements. SFAS No. 71 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) are reflected as deferred charges or credits on the Condensed Consolidated Balance Sheets. These costs and/or obligations are not reflected in the statement of income until the period during which matching revenues are recognized.

If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 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.

The Company’s primary regulatory assets include:

•

power cost deferrals,

•

investment in exchange power,

•

regulatory asset for deferred income taxes,

•

unamortized debt expense,

•

assets offsetting net utility energy commodity derivative liabilities (see Note 4 for further information),

•

expenditures for demand side management programs,

•

expenditures for conservation programs,

•

payments to the Coeur d’Alene Tribe for past water storage, and

•

unfunded pensions and other postretirement benefits.

Those items without a specific line on the Condensed Consolidated Balance Sheets are included in other regulatory assets.

Regulatory liabilities include:

•

utility plant retirement costs,

•

natural gas deferrals, and

•

liabilities offsetting net utility energy commodity derivative assets (see Note 4 for further information).

AVISTA CORPORATION

Those items without a specific line on the Condensed Consolidated Balance Sheets are included in other current liabilities and other non-current liabilities and deferred credits.

Reclassifications

Cash flow activity related to the $0.3 million increase in funds held for customers was reclassified as an investing activity and the $0.3 million increase in customer fund obligations was reclassified as a financing activity, rather than an operating activity as previously presented in the Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2008. This reclassification had no impact on the net change in cash and cash equivalents or cash flows from operating activities for the three months ended March 31, 2008.

NOTE 2. NEW ACCOUNTING STANDARDS

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, “Fair Value Measurements” related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the Financial Accounting Standards Board (FASB) issued Staff Position (FSP) No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. Effective January 1, 2009, the Company adopted those provisions of SFAS No. 157. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008 and 2009, did not have a material impact on the Company’s financial condition and results of operations. However, the Company expanded disclosures with respect to fair value measurements that became effective on January 1, 2008. There were no additional disclosures related to the provisions that became effective January 1, 2009. See Note 9 for the expanded disclosures.

Effective January 1, 2009 the Company adopted SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. This statement requires the acquiring entity in a business combination to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the transaction at the acquisition date, measured at their fair values as of that date, with limited exceptions. The adoption of SFAS No. 141(R) did not have any impact on the Company’s financial condition and results of operations.

Effective January 1, 2009, the Company adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for a noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies that a noncontrolling interest in a subsidiary is an ownership in the consolidated entity that should be reported as equity in the consolidated financial statements. The adoption of SFAS No. 160 did not have any material impact on the Company’s financial condition and results of operations. However, it did impact the presentation and disclosure of noncontrolling (minority) interests in the Company’s condensed consolidated financial statements. The presentation and disclosure requirements were retrospectively applied to the condensed consolidated financial statements. The Company included $11.1 million of noncontrolling (minority) interests in equity as of March 31, 2009 and $11.2 million as of December 31, 2008. The Company had a reduction to net income attributable to noncontrolling (minority) interests of $0.4 million for the three months ended March 31, 2009 and $0.1 million for the three months ended March 31, 2008. The noncontrolling (minority) interests primarily relates to third party shareholders of Advantage IQ, who own approximately 26 percent as of March 31, 2009.

Effective January 1, 2009 the Company adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This statement required disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement also required disclosure of derivative features that are related to credit risk. The Company expanded disclosures with respect to derivatives and hedging activities. See Note 4 for the expanded disclosures.

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends FASB Statement No. 132(R) “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This statement provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The Company will be required to adopt FSP FAS 132(R)-1 at the end of 2009 and will have expanded disclosures with respect to its pension and other postretirement benefit plan assets.

AVISTA CORPORATION

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies, as well as in annual financial statements. This FSP also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods. The Company will be required to adopt FSP FAS 107-1 and APB 28-1 for the quarter ending June 30, 2009. The Company will be required to disclose the fair value of financial instruments on an interim basis in its quarterly financial statements that will be consistent with the disclosures currently required in its annual financial statements.

NOTE 3. ACCOUNTS RECEIVABLE SALE

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 13, 2009, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment extended the termination date to March 12, 2010. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in other operating expenses of Avista Corp. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of Avista Corp.’s committed lines of credit (see Note 6). At each of March 31, 2009 and December 31, 2008, ARC had the ability to sell up to $85.0 million of receivables under this revolving agreement. There were no accounts receivable sold as of March 31, 2009 and $17.0 million in accounts receivable sold as of December 31, 2008 under this revolving agreement.

NOTE 4. 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 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.

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 using 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.

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 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 purchases for the operation of Avista Utilities’ resources, and

AVISTA CORPORATION

•

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

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

As part of its resource optimization process described above, Avista Utilities manages the impact of fluctuations in electric energy prices by measuring and controlling the volume of energy imbalance between projected loads and resources and through the use of derivative commodity instruments for hedging purposes. Load/resource imbalances within a planning horizon up to 36 months ahead are compared against established volumetric guidelines. Management determines the timing and actions necessary to manage these energy imbalances. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods.

Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources. Forward natural gas contracts are typically for monthly delivery periods. However, daily variations in natural gas demand can be significantly different than monthly demand projections. On the basis of these projections, 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 gas supply requirements un-hedged for purchase in short-term and spot markets. Natural gas resource optimization activities include:

•

wholesale market sales of surplus gas supplies,

•

purchases and sales of natural gas to use under-utilized pipeline capacity, and

•

sales of excess natural gas storage capacity.

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

In conjunction with the provisions of SFAS No. 133, 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 annual 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.

Substantially all forward contracts to purchase or sell power and natural gas are recorded as assets or liabilities at market value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for on the accrual basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than temporary.

The following table presents the underlying energy commodity volumes as of March 31, 2009 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
Year	Physical MWH	Financial MWH	Physical mmBTUs	Financial mmBTUs	Physical MWH	Financial MWH	Physical mmBTUs	Financial mmBTUs
2009	1,086	462	13,616	993	811	62	2,892	—
2010	514	390	9,700	1,210	425	—	360	—
2011	699	—	7,085	—	615	—	—	—
2012	366	—	2,660	—	287	—	—	—
2013	368	—	1,575	—	286	—	—	—
Thereafter	2,061	—	—	—	1,588	—	—	—

AVISTA CORPORATION

Foreign Currency Exchange Contracts

A significant portion of our natural gas supply is obtained from Canadian sources. Most of those transactions are executed in U.S. dollars which avoids foreign currency risk. A growing portion of our short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within sixty days with U.S. dollars. In early 2009, we implemented a process to economically hedge a portion of the foreign currency risk by purchasing Canadian currency when such commodity transactions are initiated. This risk has not had a material effect on our financial condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply costs for ratemaking. As of March 31, 2009, Avista Corp. had a current derivative liability for foreign currency hedges of less than $0.1 million included in other current liabilities on the Condensed Consolidated Balance Sheet. As of March 31, 2009, the Company had entered into 29 Canadian currency forward contracts with a notional amount of $9.9 million ($12.5 million Canadian).

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 the anticipated issuances of debt. 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, 2009 (dollars in thousands):


Entered	Notional		Number of Contracts	Mandatory Cash Settlement Date
December 2008	$	50,000	2	2009
January 2009		50,000	2	2009
March 2009		50,000	2	2010

Total	$	150,000

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, 2009, Avista Corp. had a current derivative asset and an offsetting regulatory liability of $2.8 million and a long-term derivative liability and an offsetting regulatory asset of $0.9 million 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.

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, 2009 (in thousands):


	Balance Sheet Location	Fair Value
Asset Derivatives:
Interest rate contracts	Other current assets	$	2,759
Commodity contracts	Current utility energy commodity derivative assets		5,680
Commodity contracts	Current utility energy commodity derivative liabilities		20,192
Commodity contracts	Non-current utility energy commodity derivative assets		47,294
Commodity contracts	Other non-current liabilities and deferred credits		1,549

Total asset derivative instruments recorded on the balance sheet		$	77,474

Liability Derivatives:
Interest rate contracts	Other non-current liabilities and deferred credits	$	853
Foreign currency contracts	Other current liabilities		8
Commodity contracts	Current utility energy commodity derivative assets		1,081
Commodity contracts	Current utility energy commodity derivative liabilities		76,059
Commodity contracts	Non-current utility energy commodity derivative assets		11,972
Commodity contracts	Other non-current liabilities and deferred credits		11,586

Total liability derivative instruments recorded on the balance sheet		$	101,559

AVISTA CORPORATION

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, 2009 was $69.5 million. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2009, the Company would be required to post $24.9 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,

•

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.

AVISTA CORPORATION

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. From time to time, margin calls are 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 $0.2 million as of March 31, 2009 and December 31, 2008. 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.

Other Operational and Event Risks

The Company is subject to operational and event risks including, among others:

•

blackouts or disruptions to distribution, transmission or transportation systems,

•

forced outages at generating plants,

•

fuel quality and availability,

•

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

•

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

Terrorism and other malicious threats are a risk to the entire utility industry. Potential disruptions to operations or destruction of facilities from terrorism or other malicious acts are not readily determinable. The Company has taken various steps to mitigate terrorism risks and prepare contingency plans in the event that its facilities are targeted.

NOTE 5. 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 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 $28 million in cash to the pension plan in 2008 and $15 million in each of 2007 and 2006. The Company expects to contribute $48 million to the pension plan in 2009 ($16 million was contributed during the first quarter of 2009).

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.

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 liability and expense for this plan are included as other postretirement benefits.

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

AVISTA CORPORATION

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


	Pension Benefits						Other Post- retirement Benefits
	2009			2008			2009			2008
Service cost	$	2,673		$	2,552		$	202		$	149
Interest cost		5,404			5,203			571			469
Expected return on plan assets		(4,238	)		(5,274	)		(341	)		(391	)
Transition obligation recognition		—			—			126			126
Amortization of prior service cost		164			164			(37	)		—
Net loss recognition		2,055			1,100			263			66

Net periodic benefit cost	$	6,058		$	3,745		$	784		$	419

NOTE 6. SHORT-TERM BORROWINGS

The Company has a committed line of credit agreement with various banks in the total amount of $320.0 million with an expiration date of April 5, 2011. Under the credit agreement, the Company can request the issuance of up to $320.0 million in letters of credit. The Company had $225.0 million in borrowings outstanding under this committed line of credit as of March 31, 2009, and $250.0 million as of December 31, 2008. Total letters of credit outstanding were $25.9 million as of March 31, 2009 and $24.3 million as of December 31, 2008. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds 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.

Additionally, the Company has a committed line of credit agreement with various banks in the total amount of $200.0 million with an expiration date of November 24, 2009. As of March 31, 2009 and December 31, 2008, we did not have any borrowings outstanding under this committed line of credit. The committed line of credit is secured by $200.0 million of 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 agreements contain customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of March 31, 2009, the Company was in compliance with this covenant with a ratio of 3.53 to 1. The committed line of credit agreements also have a covenant which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 70 percent at any time. As of March 31, 2009, the Company was in compliance with this covenant with a ratio of 53.1 percent. If the proposed change in organization becomes effective (see Note 12 for potential holding company formation), the committed line of credit agreements will remain at Avista Corp. The committed line of credit agreements also have a covenant which requires the Company to maintain a minimum funded ratio of the pension plan assets to liabilities. The Pension Protection Act of 2006 (that was implemented in 2008) modified the liability calculation utilized to calculate the funded ratio. Avista Corp. amended the covenant related to the pension funded ratio, under its $320.0 million committed line of credit agreement, to conform with the calculations under the Pension Protection Act of 2006.

Advantage IQ

Advantage IQ has a $12.5 million committed credit agreement with a bank that has an expiration date of February 2011. Advantage IQ has the ability to increase the credit facility to $25 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $1.1 million of borrowings outstanding under the credit agreement as of March 31, 2009, and $2.2 million as of December 31, 2008.

AVISTA CORPORATION

NOTE 7. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of March 31, 2009 and December 31, 2008 (dollars in thousands):


Maturity Year	Description	Interest Rate	March 31, 2009			December 31, 2008
2010	Secured Medium-Term Notes	6.67%-8.02%	$	35,000		$	35,000
2012	Secured Medium-Term Notes	7.37%		7,000			7,000
2013	First Mortgage Bonds	6.13%		45,000			45,000
2013	First Mortgage Bonds	7.25%		30,000			30,000
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
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2034	Secured Pollution Control Bonds	(1)		17,000			17,000
2035	First Mortgage Bonds	6.25%		150,000			150,000
2037	First Mortgage Bonds	5.70%		150,000			150,000

	Total secured long-term debt			835,000			835,000
2023	Unsecured Pollution Control Bonds	6.00%		4,100			4,100
	Other long-term debt and capital leases			2,891			3,006
	Interest rate swaps			(13,695	)		(14,129	)
	Unamortized debt discount			(1,478	)		(1,512	)

	Total			826,818			826,465
	Current portion of long-term debt			(17,132	)		(17,207	)

	Total long-term debt		$	809,686		$	809,258

(1)	Variable interest rate (reset daily) ranging from 0.50 percent to 1.20 percent during the first quarter of 2009. As of March 31, 2009 the variable rate was 0.50 percent.

NOTE 8. LONG-TERM DEBT TO AFFILIATED TRUSTS

In 2004, the Company issued Junior Subordinated Debt Securities, with a principal amount of $61.9 million to AVA Capital Trust III, an affiliated business trust formed by the Company. Concurrently, AVA Capital Trust III issued $60.0 million of Preferred Trust Securities to third parties and $1.9 million of Common Trust Securities to the Company. On April 1, 2009, AVA Capital Trust III redeemed all of the Preferred Trust Securities issued to third parties with a principal balance of $60.0 million and all of the Common Trust Securities issued to the Company with a principal balance of $1.9 million. Concurrently, the Company redeemed the total amount outstanding of its Junior Subordinated Debt Securities, at 100 percent of the principal amount ($61.9 million) plus accrued interest held by AVA Capital Trust III. The Company’s net redemption of $60.0 million was funded by borrowings under its $320.0 million committed line of credit agreement.

NOTE 9. FAIR VALUE

As disclosed in Note 2, on January 1, 2008, the Company adopted the provisions of SFAS No. 157 related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis, and on January 1, 2009, the Company adopted the provisions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. SFAS No. 157 establishes 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 defined by SFAS No. 157 are 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.

AVISTA CORPORATION

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. Level 3 instruments include those that may be more structured or otherwise tailored to the Company’s needs.

As required by SFAS No. 157, 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 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, 2009 and December 31, 2008 at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Counterparty Netting			Total
March 31, 2009
Assets:
Energy commodity derivatives	$	—	$	26,040	$	48,675	$	(34,794	)	$	39,921
Deferred compensation assets		6,296		—		—		—			6,296
Interest rate swaps		—		2,759		—		—			2,759

Total	$	6,296	$	28,799	$	48,675	$	(34,794	)	$	48,976

Liabilities:
Energy commodity derivatives	$	—	$	87,831	$	12,867	$	(34,794	)	$	65,904
Interest rate swaps		—		853		—		—			853
Foreign currency derivatives		—		8		—		—			8

Total	$	—	$	88,692	$	12,867	$	(34,794	)	$	66,765

December 31, 2008
Assets:
Energy commodity derivatives	$	—	$	40,104	$	68,047	$	(47,604	)	$	60,547
Deferred compensation assets		6,990		—		—		—			6,990
Interest rate swaps		—		875		—		—			875

Total	$	6,990	$	40,979	$	68,047	$	(47,604	)	$	68,412

Liabilities:
Energy commodity derivatives	$	—	$	110,123	$	16,085	$	(47,604	)	$	78,604

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 our 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 our 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, which are also quoted under NYMEX. 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 4 for further discussion of the Company’s energy commodity derivative assets and liabilities.

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 excludes cash and cash equivalents of $1.8 million as of March 31, 2009 and December 31, 2008.

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


	2009			2008
Beginning balance as of January 1	$	68,047		$	98,943
Total gains or losses (realized/unrealized):
Included in net income		—			—
Included in other comprehensive income		—			—
Included in regulatory assets/liabilities (1)		(18,220	)		37,078
Purchases, issuances, and settlements, net		(1,152	)		(3,782	)
Transfers to other categories		—			—

Ending balance as of March 31	$	48,675		$	132,239

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


	2009			2008
Beginning balance as of January 1	$	16,085		$	36,506
Total gains or losses (realized/unrealized):
Included in net income		—			—
Included in other comprehensive income		—			—
Included in regulatory assets/liabilities (1)		(3,190	)		9,754
Purchases, issuances, and settlements, net		(28	)		—
Transfers to other categories		—			—

Ending balance as of March 31	$	12,867		$	46,260

(1)

In conjunction with the provisions of SFAS No. 133, the WUTC and the IPUC issued accounting orders authorizing Avista Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. As such, the Company does not recognize unrealized gains or losses on utility energy commodity derivative instruments in the Condensed Consolidated Statements of Income. The Company recognizes realized gains or losses in the period of contract settlement, subject to regulatory approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in annual adjustments to retail rates through purchased gas cost adjustments, the ERM, the PCA mechanism, and periodic general rate cases.

NOTE 10. EARNINGS PER COMMON SHARE

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


	2009			2008
Numerator:
Net income attributable to Avista Corporation	$	31,026		$	25,231
Subsidiary earnings adjustment for dilutive securities		(34	)		(76	)

Adjusted net income attributable to Avista Corporation for computation of diluted earnings per common share	$	30,992		$	25,155

Denominator:
Weighted-average number of common shares outstanding-basic		54,616			53,020
Effect of dilutive securities:
Contingent stock awards		25			133
Stock options		81			229

Weighted-average number of common shares outstanding-diluted		54,722			53,382

Earnings per common share attributable to Avista Corporation:
Basic	$	0.57		$	0.48

Diluted	$	0.57		$	0.47

AVISTA CORPORATION

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 355,350 for the three months ended March 31, 2009, and 315,750 for the three months ended March 31, 2008. These stock options were excluded from the calculation because they were antidilutive based on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during the respective period.

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. With respect to these proceedings, the Company intends to vigorously protect and defend its interests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested proceedings are inherently subject to numerous uncertainties. With respect to matters that affect Avista Utilities’ operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.

Federal Energy Regulatory Commission Inquiry

On April 19, 2004, the FERC issued an order approving the contested Agreement in Resolution of Section 206 Proceeding (Agreement in Resolution) reached by Avista Corp. doing business as Avista Utilities, Avista Energy and the FERC’s Trial Staff with respect to an investigation into the activities of Avista Utilities and Avista Energy in western energy markets during 2000 and 2001. In the Agreement in Resolution, the FERC Trial Staff stated that its investigation found: (1) no evidence that any executives or employees of Avista Utilities or Avista Energy knowingly engaged in or facilitated any improper trading strategy; (2) no evidence that Avista Utilities or Avista Energy engaged in any efforts to manipulate the western energy markets during 2000 and 2001; and (3) that Avista Utilities and Avista Energy did not withhold relevant information from the FERC’s inquiry into the western energy markets for 2000 and 2001. In April 2005 and June 2005, the California Parties and the City of Tacoma, respectively, filed petitions for review of the FERC’s decisions approving the Agreement in Resolution with the United States Court of Appeals for the Ninth Circuit (Ninth Circuit). Based on the FERC’s order approving the Agreement in Resolution and the FERC’s denial of rehearing requests, the Company does not expect that this proceeding will have any material adverse effect on its financial condition, results of operations or cash flows.

California Refund Proceeding

In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the California Independent System Operator (CalISO) and the California Power Exchange (CalPX) during the period from October 2, 2000 to June 20, 2001 (Refund Period). The findings of the FERC administrative law judge were largely adopted in March 2003 by the FERC. The refunds ordered are based on the development of a mitigated market clearing price (MMCP) methodology. If the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, the FERC has held that the seller would be allowed to document these costs and limit its refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim pursuant to the FERC’s August 2005 order and demonstrated an overall revenue shortfall for sales into the California spot markets during the Refund Period after the MMCP methodology is applied to its transactions. That filing was accepted in orders issued by the FERC in January 2006 and November 2006. In its February 2007 status report, the CalISO stated that it intends to process Avista Energy’s cost offset filing (see further discussion regarding the California refund rerun below).

In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the CalPX and the CalISO. As a result, the CalPX and the CalISO failed to pay various energy sellers, including Avista Energy. Both PG&E and the CalPX declared bankruptcy in 2001. In March 2002, SCE paid its defaulted obligations to the CalPX. In April 2004, PG&E paid its defaulted obligations into an escrow fund in accordance with its bankruptcy reorganization. Funds held by the CalPX and in the PG&E escrow fund are not subject to release until the FERC issues an order directing such release in the California refund proceeding. As of March 31, 2009, Avista Energy’s accounts receivable outstanding related to defaulting parties in California were fully offset by reserves for uncollected amounts and funds collected from defaulting parties.

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In addition, in June 2003, the FERC issued an order to review bids above $250 per MW made by participants in the short-term energy markets operated by the CalISO and the CalPX from May 1, 2000 to October 2, 2000. In May 2004, the FERC provided notice that Avista Energy was no longer subject to this investigation. In March and April 2005, the California Parties and PG&E, respectively, petitioned for review of the FERC’s decision by the Ninth Circuit. In addition, many of the other orders that the FERC has issued in the California refund proceedings are now on appeal before the Ninth Circuit. Some of those issues were consolidated as a result of a case management conference conducted in September 2004. In October 2004, the Ninth Circuit ordered that briefing proceed in two rounds. The first round is limited to three issues: (1) which parties are subject to the FERC’s refund jurisdiction in light of the exemption for government-owned utilities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; and (3) which categories of transactions are subject to refunds. In September 2005, the Ninth Circuit held that the FERC did not have the authority to order refunds for sales made by municipal utilities in the California Refund Case. In its Order on Remand, issued in October 2007, the FERC ordered the CalISO and the CalPX to complete their refund calculations, including all entities that participated in the CalISO/CalPX markets (including those amounts that would have been paid by municipal utility entities for their sales into the CalISO and the CalPX spot markets during the refund period). The FERC then directed the CalISO to reduce refunds owed to refund recipients by the amounts attributable to municipal sales to the California markets.

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 a FPA section 309 remedy for tariff violations prior to October 2, 2000. The Ninth Circuit also granted California’s petition for review challenging the FERC’s exclusion of the energy exchange transactions as well as the FERC’s exclusion of forward market transactions from the California refund proceedings. Petitions for rehearing were denied on April 6, 2009. It is unclear at this time what impact, if any, the Court’s remand might have on Avista Energy. The second round of issues and their corresponding briefing schedules have not yet been set by the Ninth Circuit.

The CalISO continues to work on its compliance filing for the Refund Period, which will show “who owes what to whom.” On September 3, 2008, the CalISO filed its 42nd status report on the California recalculation process confirming that the preparatory and the FERC refund recalculations are complete (as are calculations related to fuel cost allowance offsets, emission offsets, cost-recovery offsets, and the majority of the interest calculations). The CalISO states that there are eleven (11) open issues that the FERC must rule on before any distribution can be made. Once these issues are ruled on, the CalISO states that it then intends to: (1) perform the necessary adjustment to remove refunds associated with non-jurisdictional entities and allocate that shortfall to net refund recipients; and (2) work with the parties to the various global settlements to make appropriate adjustments to the CalISO’s data in order to properly reflect those adjustments.

Any potential liabilities or refunds owed by or to Avista Energy in the California Refund Proceeding were retained by Avista Corp. and/or its subsidiaries and have not been transferred to Shell Energy and/or its affiliates based upon the sales agreement.

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 to the Company’s management, the Company does not expect that the California refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. This is primarily due to the fact that 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. During the hearing, Avista Corp., doing business as Avista Utilities, and Avista Energy vigorously opposed claims that rates for spot market sales were unjust and unreasonable and that the imposition of refunds would be appropriate. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. These equitable factors included the fact that the participants in the Pacific Northwest market include not only utilities and other entities that are subject to FERC jurisdiction, but also a very substantial number of governmental entities that are not subject to FERC jurisdiction with respect to wholesale sales and thus could not be ordered by the FERC to make refunds based on existing law. Seven petitions for review were filed with the Ninth Circuit challenging the merits of the FERC’s decision not to order refunds and raising procedural issues.

AVISTA CORPORATION

On August 24, 2007, the Ninth Circuit issued its opinion on the consolidated petitions for review of the Pacific Northwest refund proceeding. 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 in the Pacific Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. Requests for rehearing were denied on April 10, 2009.

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 non-jurisdictional entities 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

In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the Attorney General of the State of California (California AG) that alleged violations of the Federal Power Act by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The complaint alleged that the FERC’s adoption and implementation of market-based rate authority was flawed and, as a result, individual sellers 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 July 2002, the California AG requested a rehearing on the FERC order, which request was denied in September 2002. Subsequently, the California AG filed a Petition for Review of the FERC’s decision with the Ninth Circuit. 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. Nonetheless, the California AG has interpreted the decision as providing authority to the FERC to order refunds in the California refund proceeding for an expanded refund period.

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 Commission’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 are 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 first prehearing conference before an administrative law judge in the case is scheduled for May 1, 2009.

Based on information currently known to the Company’s management, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

Colstrip Generating Project Complaints

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 and other relief similar to that asserted in the litigation described above. No trial date has been set. Because the resolution of this complaint remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect this complaint will have a material adverse effect on its financial condition, results of operations or cash flows.

AVISTA CORPORATION

Colstrip Royalty Claim

Western Energy Company (WECO) supplies coal to the owners of Units 3 & 4 of Colstrip under a Coal Supply Agreement and a Transportation Agreement. The Minerals Management Service (MMS) of the United States Department of the Interior has issued orders, going back to 1991, to WECO to pay additional royalties concerning coal delivered to Units 3 & 4 of Colstrip via the conveyor belt. The owners of Units 3 & 4 of Colstrip take delivery of the coal at the beginning of the conveyor belt.

The orders assert that additional royalties are owed to MMS as a result of WECO not paying royalties in connection with revenue received by WECO from the owners of Units 3 & 4 of Colstrip under the Transportation Agreement during the period October 1, 1991 through December 31, 2007.

The state of Montana also filed claims assessing additional coal production taxes on Coal Transportation Agreement revenues collected by WECO from the owners of Units 3 & 4 of Colstrip. Settlement of production tax claims has recently occurred between WECO and the Montana Department of Revenue.

WECO and the owners of Units 3 & 4 of Colstrip have agreed to a cost sharing agreement for the payment of the settlements owed to the Montana Department of Revenue for coal production taxes and for the MMS royalty claims as they are determined through litigation or settlement. Avista Corp. estimates that its share of the royalties, taxes and interest alleged would be $2.1 million including payment for the calendar year 2008.

Based on information currently known to the Company’s management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. The Company expects to recover, through the ratemaking process, any amounts paid and included in fuel costs through the ERM and PCA mechanism.

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). The total cost of the RI/FS is estimated to be $1.2 million and will take approximately 2 1/2 years to complete. 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 de minimus 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. As such, it is not possible to make an estimate of any liability at this time.

Lake Coeur d’Alene

In July 1998, the United States District Court for the District of Idaho issued its finding that the Couer d’ Alene Tribe (the Tribe) owns, among other things, portions of the bed and banks of Lake Coeur d’Alene (Lake) lying within the current boundaries of the Tribe’s reservation lands. The United States District Court decision was affirmed by the United States Court of Appeals for the Ninth Circuit and the United States Supreme Court in June 2001. This ownership decision resulted in, among other things, Avista Corp. being liable to the Tribe for water storage on the Tribe’s land and for Section 10(e) payments.

The Company’s Post Falls Hydroelectric Generating Station (Post Falls) controls the water level in the Lake for portions of the year (including portions of the lakebed owned by the Tribe).

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In December 2008, Avista Corp., the Tribe and the United States Department of Interior (DOI) finalized an agreement regarding a range of issues related to Post Falls and the Lake. The agreement establishes the amount of past and future compensation Avista Corp. will pay for the use of the Tribe’s reservation lands under Section 10(e) of the Federal Power Act (Section 10(e) payments) and issues related to relicensing of the Company’s hydroelectric generating facilities located on the Spokane River (see Spokane River Relicensing below).

Avista Corp. agreed to compensate the Tribe a total of $39 million ($25 million paid in 2008, $10 million to be paid in 2009 and $4 million to be paid in 2010) for trespass and Section 10(e) payments for past storage of water for the period from 1907 through 2007. Avista Corp. agreed to compensate the Tribe for future storage of water through Section 10(e) payments of $0.4 million per year beginning in 2008 and continuing through the first 20 years of a new license and $0.7 million per year through the remaining term of the license.

In addition to Section 10(e) payments, Avista Corp. agreed to make annual payments over the life of a new FERC license to fund a variety of protection, mitigation and enhancement measures on the Coeur d’Alene Reservation required under Section 4(e) of the Federal Power Act. These payments involve creation of a Coeur d’Alene resource protection trust fund (the Trust Fund). Annual payments from the Company to the Trust Fund for protection, mitigation and enhancement measurements would commence with the issuance of a new FERC license and are expected to total approximately $100 million over an assumed 50-year license term.

In September 2008, as part of the settlement of the Company’s general rate case, the IPUC approved deferral of the Idaho jurisdictional allocation of amounts paid to the Tribe, the Trust Fund or related to the licensing of its hydroelectric generating facilities for later recovery through rates in a subsequent general rate filing. Avista Corp. included these items in its general rate case filed in Washington in January 2009. In December 2008, the WUTC approved a settlement of the Company’s general rate case filing which provides similar treatment of the Washington jurisdictional allocation of amounts paid to the Tribe, the Trust Fund or related to the licensing of its hydroelectric generating facilities.

On January 27, 2009, the Public Counsel Section of the Washington Attorney General’s Office (Public Counsel) filed a Petition for Judicial Review of the WUTC’s recent order approving the settlement of the Company’s general rate case. Public Counsel raised a number of issues that were previously argued before the WUTC. These include whether settlement costs associated with resolving the dispute with the Tribe were prudent and whether recovery of such costs would constitute illegal “retroactive ratemaking.” The appeals process may take several months and a decision is not expected until later in 2009. The court will either affirm the decision of the WUTC in its entirety or reverse the decision, in whole or in part, and remand the matter back to the WUTC for further consideration, which could possibly result in de minimus refunds to customers and regulatory disallowance of the Washington portion of the $39 million that the Company has agreed to compensate the Tribe. 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.

Spokane River Relicensing

The Company owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls, which have a total present capability of 144.1 MW) are under one FERC license and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. Since the FERC was unable to issue new license orders prior to the August 1, 2007 (and subsequent August 1, 2008) expiration of the current license, an annual license was issued for all five plants, in effect extending the current license and its conditions until August 1, 2009. The Company has no reason to believe that Spokane River Project operations will be interrupted in any manner relative to the timing of the FERC’s actions.

The Company filed a Notice of Intent to Relicense in July 2002. The formal consultation process involving planning and information gathering with stakeholder groups lasted through July 2005, when the Company filed its new license applications with the FERC. The Company initially requested the FERC to consider a license for Post Falls, which has a present capability of 18 MW, separately from the other four hydroelectric plants due to the complexity of issues related to the Post Falls development. In the license applications, the Company proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River. FERC licenses are granted for terms of 30 to 50 years.

Since the Company’s July 2005 filing of applications to relicense the Spokane River Project, the FERC has continued various stages of processing the applications. In May 2006, the FERC issued a notice requesting other parties to provide terms and conditions regarding the two license applications. In response to that notice, a number of parties including the Tribe, Idaho and Washington state agencies, and the United States DOI filed either

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recommended terms and conditions, pursuant to Sections 10(a) and 10(j) of the Federal Power Act (FPA), or mandatory conditions related to the Post Falls application, pursuant to Section 4(e) of the FPA. In January 2007, the FERC issued a draft Environmental Impact Statement (EIS). After review of comments, the FERC issued a final EIS in July 2007. This was the last administrative step for the FERC before the issuance of license orders; however, the FERC was unable to move forward prior to Federal Clean Water Act 401 Water Quality Certifications (Certifications) being issued by the states of Idaho and Washington.

The states of Idaho and Washington issued Certifications for the Project on June 5, 2008 and June 10, 2008, respectively. The Idaho Certification was based on a Settlement Agreement between Avista Corp., the Idaho Department of Environmental Quality and the Idaho Department of Fish and Game, and is final. The Washington Certification, which was issued by the Washington Department of Ecology (Ecology), however, was appealed by Avista Corp., Inland Empire Paper and the Sierra Club/Center for Environmental Law and Policy. All issues, with the exception of one appealed by the Sierra Club/Center for Environmental Law and Policy (aesthetic spills at the Upper Falls plant) were resolved through a four-party Settlement Agreement. Avista Corp. is actively continuing negotiations on the remaining issue. A hearing is scheduled before the Washington Pollution Control Hearing Board in August 2009 to address the remaining issue under appeal.

On December 16, 2008 Avista Corp., the United States DOI, and the Tribe reached agreement resolving FPA Section 4(e) conditions, as well as the payment of annual charges under Section 10(e) of the FPA regarding Post Falls, which stores water on a portion of the Coeur d’Alene Indian Reservation. The three parties submitted a request to the FERC on January 29, 2009 to incorporate the agreed-upon terms and conditions in a new single 50-year license for all five Spokane River hydroelectric plants.

The United States Department of Fish and Wildlife concurred, via a letter to the FERC on July 31, 2008, that the Spokane River Project is not likely to adversely affect any listed or threatened endangered species.

Avista Corp. can not determine exactly when the FERC will complete action on the applications. Once granted, a new license will describe the final conditions Avista Corp. will be responsible for implementing, and the term for a new license.

The Company’s estimate of the potential cost of the conditions proposed for the Spokane River Project, based on estimates of what it would cost to implement the recommendations and conditions included in the FERC’s FEIS and the numerous settlement agreements, total approximately $305 million over a 50-year period.

In addition, the December 16, 2008 Settlement Agreement between the Company and the Tribe resolved FPA Section 10(e), or water storage payments related to the Post Falls hydroelectric facility. Under the Agreement, Avista Corp. will pay the Tribe $0.4 million annually for the first 20 years of a new FERC license and $0.7 million annually for the remainder of the license term for Section 10(e) charges.

The WUTC approved, for future recovery, costs incurred in relicensing the Spokane River Project, as well as the costs related to settlement with the Tribe. The WUTC approved deferred accounting treatment, with a carrying cost, until these costs are reflected in future retail rates. The IPUC approved similar deferred accounting treatment. Our general rate cases, filed in January 2009, reflect recovery of both the direct and deferred costs. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to the relicensing of the Spokane River Project.

Clark Fork Settlement Agreement

Dissolved atmospheric gas levels exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other signatories to the Agreement and developed the Gas Supersaturation Control Program (GSCP). The Idaho Department of Environmental Quality and the United States Fish and Wildlife Service (USFWS) approved the GSCP in February 2004 and the FERC issued an order approving the GSCP in January 2005.

The GSCP provides for the opening and modification of one and, potentially, both of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. When river flows exceed the capacity of the powerhouse turbines, the excess flows would be diverted to the tunnels rather than released over the spillway. The Company has undertaken physical and computer modeling studies to confirm the feasibility and likely effectiveness

AVISTA CORPORATION

of the tunnel solution. Analysis of the predicted total dissolved gas performance indicates that the tunnels will not meet the performance criteria anticipated in the GSCP. In August 2007, the Gas Supersaturation Subcommittee concluded that the tunnel project does not meet the expectations of the GSCP and is not an acceptable project. As a result, the Company has met and will continue meeting with key stakeholders to review and amend the GSCP which includes developing alternatives to the construction of the tunnels. The Company has expended $5.1 million on the tunnel project. The WUTC and IPUC have accepted the recovery of these costs through rates.

The USFWS has listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes programs intended to restore bull trout populations in the project area. Using the concept of adaptive management and working closely with the 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.

Air Quality

The Company must be in compliance with requirements under the Clean Air Act and Clean Air Act Amendments for its thermal generating plants. The Company continues to monitor legislative developments at both the state and national level for the potential of further restrictions on sulfur dioxide, nitrogen oxide and carbon dioxide, as well as other greenhouse gas and 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 put in place a recurring ten-year review process to ensure facilities are keeping pace with advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities.

Compliance with new and proposed requirements and possible additional legislation or regulations will result in increases to capital expenditures and operating expenses for expanded emission controls at the Company’s thermal generating facilities. The Company, along with the other owners of Colstrip, completed the first phase of testing on two mercury control technologies. The joint owners of Colstrip believe based upon preliminary results that we will be able to comply with the Montana law without utilizing the temporary alternate emission limit provision. Preliminary estimates indicate that the Company’s share of installation capital costs will be $1.5 million and annual operating costs will increase by $2.9 million (beginning in late-2009). The Company will continue to seek recovery, through the ratemaking process, of the costs to comply with various air quality requirements.

Residential Exchange Program

The residential exchange program is intended to provide access to the benefits of low-cost federal hydroelectricity to residential and small-farm customers of the region’s private (investor owned) and public (governmental or customer owned) utilities. The Bonneville Power Administration (BPA) administers the residential exchange program under the Northwest Power Act. Previously, Avista Corp. and other private utilities in the Pacific Northwest executed settlement agreements with the BPA to resolve each party’s rights and obligations under the residential exchange program. These settlements covered payment of benefits for the period October 1, 2001, through September 30, 2011. On May 3, 2007, the Ninth Circuit ruled that the BPA exceeded its authority when it entered into the settlement agreements with private utilities (including Avista Corp.) for the period from 2001 through 2011.

In February 2008, the BPA initiated its WP-07 Supplemental rate case (WP-07S) to, among other things, determine the level of benefits for customers served by private utilities (including Avista Corp.) for its fiscal year 2009. In addition to resolving residential exchange issues for the long-term, the BPA also proposed an interim payout to private utilities for its fiscal year 2008, which included $9.6 million for customers of Avista Corp. Rate adjustments to pass through the interim payment to Avista Corp.’s customers were approved by the WUTC and IPUC in April 2008. In September 2008, the BPA issued its final Record of Decision in WP-07S. Avista Corp. is evaluating the BPA’s final Record of Decision, and may take steps to challenge the BPA’s final Record of Decision. Avista Corp. has executed new Residential Exchange contracts with the BPA for customer benefits in 2009. Rate adjustments to pass through the payments in the amount of $2.4 million for the period November 1, 2008 through October 31, 2009 have been approved by the WUTC and IPUC.

Since the residential exchange settlement payments are passed through to Avista Corp.’s customers as adjustments to electric bills, there is no effect on Avista Corp.’s net income or cash flows.

AVISTA CORPORATION

Noxon Rapids Hydroelectric Facility

In late February 2009, a spill of mineral oil occurred at the Company’s Noxon Rapids Hydroelectric Generating Project (Noxon Rapids) located near Noxon, Montana. Operators of Noxon Rapids discovered ice that had built up on the face of the dam fell off and broke a pressure gauge on the valve of a pipe carrying oil, causing the oil to spill onto the transformer deck. The deck contains storm water drains and just over 1,000 gallons of lightweight mineral oil was released from one of these drains into the stretch of the Clark Fork River between the Noxon Rapids and Cabinet Gorge hydroelectric projects (the Company owns and operates both projects). The Company completed cleanup immediately and further follow up in April 2009 pursuant to an Order issued by the EPA. The Company accrued $1.5 million related to the estimated cleanup costs during 2009. The Company’s estimate of its liability could change in future periods and could include penalties. 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.

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. POTENTIAL HOLDING COMPANY FORMATION

At the Annual Meeting of Shareholders in May 2006, the shareholders of Avista Corp. approved a proposal to proceed with a statutory share exchange, which would change the Company’s organization to a holding company structure. The holding company, currently named AVA Formation Corp. (AVA), would become the parent of Avista Corp. After the contemplated dividend to AVA of the capital stock of Avista Capital (Avista Capital Dividend) now held by Avista Corp., AVA would then also be the parent of Avista Capital. The Avista Capital Dividend would effect the structural separation of Avista Corp.’s non-utility businesses from its regulated utility business.

Avista Corp. received approval from the FERC in April 2006 (conditioned on approval by the state regulatory agencies), the IPUC in June 2006 and the WUTC in February 2007. Avista Corp. also filed for approval from the utility regulators in Oregon and Montana and proceedings are pending in each of these jurisdictions. The statutory share exchange is subject to the receipt of the remaining regulatory approvals and the satisfaction of other conditions. The Company cannot predict when the remaining regulatory approvals will be obtained or if they will be on terms acceptable to the Company.

The IPUC accepted a stipulation entered into between Avista Corp. and the IPUC Staff that sets forth a variety of conditions, which would serve to segregate the Company’s utility operations from the other businesses conducted by the holding company. The stipulation among other things would require Avista Corp. to maintain certain common equity levels as part of its capital structure. The calculation of the utility equity component is essentially the ratio of Avista Corp.’s total common equity to total capitalization excluding, in each case, Avista Corp.’s investment in Avista Capital. The utility equity component was approximately 44.7 percent as of March 31, 2009. In addition, IPUC approval would be required for any dividend from Avista Corp. to the holding company that would reduce utility common equity below 25 percent of total capitalization which, for this purpose, includes long and short-term debt, capitalized lease obligations and preferred and common equity.

The WUTC accepted a similar stipulation entered into between Avista Corp. and the WUTC staff. WUTC approval would be required for any dividend from Avista Corp. to the holding company that would reduce utility common equity below 30 percent of total capitalization.

Pursuant to the Plan of Share Exchange, a statutory share exchange would be effected whereby each outstanding share of Avista Corp. common stock would be exchanged for one share of AVA common stock, no par value, so that holders of Avista Corp. common stock would become holders of AVA common stock and Avista Corp. would become a subsidiary of AVA. The other outstanding securities of Avista Corp. would not be affected by the statutory share exchange, with limited exceptions for stock options and other securities outstanding under equity compensation and employee benefit plans.

AVISTA CORPORATION

NOTE 13. 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 facility information and cost management services for multi-site customers throughout North America. The Other category, which is not a reportable segment, includes the remaining activities of Avista Energy, other investments and operations of various subsidiaries, 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):


	Avista Utilities		Advantage IQ		Other			Total Non- Utility		Intersegment Eliminations (1)			Total
For the three months ended March 31, 2009:
Operating revenues	$	460,864	$	17,340	$	9,266		$	26,606	$	—		$	487,470
Resource costs		289,692		—		5,728			5,728		—			295,420
Other operating expenses		57,732		13,690		3,603			17,293		—			75,025
Depreciation and amortization		22,923		1,026		336			1,362		—			24,285
Income (loss) from operations		63,622		2,624		(401	)		2,223		—			65,845
Interest expense (2)		16,848		116		14			130		(32	)		16,946
Income taxes		17,001		879		(412	)		467		—			17,468
Net income (loss) attributable to Avista Corporation		30,583		1,167		(724	)		443		—			31,026
Capital expenditures		41,510		982		6			988		—			42,498
For the three months ended March 31, 2008:
Operating revenues	$	472,272	$	12,520	$	11,515		$	24,035	$	—		$	496,307
Resource costs		318,226		—		5,920			5,920		—			324,146
Other operating expenses		51,719		8,891		4,954			13,845		—			65,564
Depreciation and amortization		21,442		624		385			1,009		—			22,451
Income from operations		55,800		3,005		256			3,261		—			59,061
Interest expense (2)		20,568		20		51			71		(14	)		20,625
Income taxes		13,987		1,117		(15	)		1,102		—			15,089
Net income attributable to Avista Corporation		23,314		1,766		151			1,917		—			25,231
Capital expenditures		47,680		1,086		13			1,099		—			48,779
Total Assets:
As of March 31, 2009	$	3,342,322	$	134,991	$	66,389		$	201,380	$	—		$	3,543,702
As of December 31, 2008		3,434,844		125,911		69,992			195,903		—			3,630,747

(1)	Intersegment eliminations reported as interest expense represent intercompany interest.

(2)	Including interest expense to affiliated trusts.

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, 2009, and the related condensed consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the three-month periods ended March 31, 2009 and 2008. These condensed consolidated 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, 2008, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended prior to retrospective adjustment for the adoption of Financial Accounting Standards Board Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51, (not presented herein); and in our report dated February 27, 2009, we expressed an unqualified opinion on those consolidated financial statements. We also audited the adjustments described in Note 2 that were applied to retrospectively adjust the December 31, 2008 consolidated balance sheet of Avista Corporation and subsidiaries (not presented herein). In our opinion, such adjustments are appropriate and have been properly applied to the previously issued consolidated balance sheet in deriving the accompanying retrospectively adjusted condensed consolidated balance sheet as of December 31, 2008.

/s/ Deloitte & Touche LLP

Seattle, Washington

April 30, 2009

AVISTA CORPORATION

Item 2.

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

Forward-Looking Statements

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

•

financial performance,

•

capital expenditures,

•

dividends,

•

capital structure,

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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. Most of these factors are beyond our control and many of them 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:

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weather conditions and its effect on energy demand and generation, including the effect of precipitation and temperatures on the availability of hydroelectric resources and the effect of temperatures on customer demand and wholesale energy markets;

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global financial and economic conditions (including the availability of credit) and their effect on our ability to obtain funding for working capital and long-term capital requirements on acceptable terms;

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

•

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

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

•

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

•

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

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the effect of state and federal regulatory decisions affecting our ability to recover costs and/or earn a reasonable return including, but not limited to, the disallowance of costs that we have deferred, and the willingness of regulators to grant necessary rate increases;

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

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

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the outcome of legal proceedings and other contingencies;

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

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

•

the ability to relicense and maintain licenses for our hydroelectric generating facilities at cost-effective levels with reasonable terms and conditions;

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

•

unanticipated delays or changes in construction costs, as well as our ability to obtain required operating permits for present or prospective facilities;

AVISTA CORPORATION

•

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

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blackouts or disruptions of interconnected transmission systems;

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

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

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changes in industrial, commercial and residential growth and demographic patterns in our service territory;

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the loss of significant customers and/or suppliers;

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

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deterioration in the creditworthiness of our customers and counterparties;

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the effect of any potential decline in our credit ratings;

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

•

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

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employee issues, including changes in collective bargaining unit agreements, strikes, work stoppages or the loss of key executives, as well as our ability to recruit and retain employees;

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

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

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changes in tax rates and/or policies; and

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

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, data contained in our records and other data 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 of such factors, nor can we assess the effect of each such factor on our business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

In this Form 10-Q, we discuss our credit ratings. It is important to note that these credit ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other ratings.

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

Potential Holding Company Formation

At the Annual Meeting of Shareholders in May 2006, the shareholders of Avista Corp. approved a proposal to proceed with a statutory share exchange, which would change our organization to a holding company structure. We received approval from the FERC in April 2006 (conditioned on approval by the state regulatory agencies), the IPUC in June 2006 and the WUTC in February 2007. We also filed for approval from the utility regulators in Oregon and Montana and proceedings are pending in each of these jurisdictions. The statutory share exchange is subject to the receipt of the remaining regulatory approvals and the satisfaction of other conditions. We can not predict when the remaining regulatory approvals will be obtained or if they will be on terms acceptable to us. See further information at “Note 12 of the Notes to Condensed Consolidated Financial Statements.”

Business Segments

We have two reportable business segments as follows:

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Avista Utilities –an operating division of Avista Corp. comprising 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.

AVISTA CORPORATION

•

Advantage IQ – an indirect subsidiary of Avista Corp. that provides sustainable utility expense management solutions, partnering with multi-site companies across North America to assess and manage utility costs and usage. Primary product lines include processing, payment and auditing of energy, telecom, waste, water/sewer and lease bills as well as strategic management services.

We have other businesses including sheet metal fabrication, the remaining activities of Avista Energy, venture fund investments and real estate investments. These activities are conducted by various indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx. The Other category is not a reportable segment.

Advantage IQ and the various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital) which is a direct, wholly owned subsidiary of Avista Corp. Our total Avista Corporation stockholders’ equity was $1,019.2 million as of March 31, 2009, of which $78.5 million represented our investment in Avista Capital.

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


	2009			2008
Avista Utilities	$	30,583		$	23,314
Advantage IQ		1,167			1,766
Other		(724	)		151

Net income attributable to Avista Corporation	$	31,026		$	25,231

Executive Level Summary

Overall

Our operating results and cash flows are primarily from:

•

regulated utility operations (Avista Utilities), and

•

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

Our net income was $31.0 million for the three months ended March 31, 2009, an increase from $25.2 million for the three months ended March 31, 2008. This increase was primarily due to increased earnings at Avista Utilities (primarily due to the implementation of general rate increases in Washington and Idaho).

We would like to monetize at least a portion of our investment in Advantage IQ within the next four years. The potential monetization of Advantage IQ depends on future market conditions, growth of the business and other factors. There can be no assurance that we will be able to complete a monetization event. Effective July 2, 2008, Advantage IQ acquired Cadence Network, a Cincinnati-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock, which is subject to redemption. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to redeem their shares of Advantage IQ stock during July 2011 or July 2012 if Advantage IQ is not liquidated through either an initial public offering or sale of the business to a third party. Their redemption rights expire July 31, 2012. The redemption price would be determined based on the fair market value of Advantage IQ at the time of the redemption election as determined by certain independent parties.

In late 2007 and early 2008, Moody’s Investors Service and Standard & Poor’s upgraded our credit ratings, which resulted in an investment grade rating for our senior unsecured debt and corporate rating from each of these rating agencies. The upgrades reflected several steps taken over the past few years to lower our business risk profile and improve financial metrics.

It is important to note that we are at the lower end of the investment grade category. We are working to continuously strengthen our credit ratings by improving earnings and operating cash flows, controlling costs and reducing our debt ratio.

Our operations are affected by global financial and economic conditions. The instability within the financial markets has caused industry-wide concern regarding the ability to access sufficient capital at a reasonable cost. The turmoil has also resulted in significant declines in the market values of assets held by pension plans (which may continue to impact the funded status of pension plans) as well as concerns regarding credit risk.

AVISTA CORPORATION

We are observing declines in employment throughout our service area due to cutbacks in the construction, forest products, mining and manufacturing sectors. Non-farm employment contraction for March 2009 as compared to March 2008 was 3.5 percent in Spokane, 3.9 percent in Medford but it rose 0.4 percent in Coeur d’Alene, compared to the national average decline of 3.6 percent. Unemployment rates are much higher than a year ago in our eastern Washington, northern Idaho and southern Oregon service areas. Unemployment rates for March 2009 were 10.6 percent in Spokane, 7.4 percent in Coeur d’Alene and 14.8 percent in Medford, compared to the national average of 9.0 percent. The housing market in Coeur d’Alene and Medford has deteriorated, and the foreclosure rate at 0.32 percent is above the national average of 0.21 percent whereas the housing market in Spokane remains stable and reflects a foreclosure rate of 0.04 percent.

Avista Utilities

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

•

weather conditions,

•

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

•

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

Our utility net income was $30.6 million for the three months ended March 31, 2009, an increase from $23.3 million for the three months ended March 31, 2008 partially due to an increase in gross margin (operating revenues less resource costs). The increase in gross margin was primarily due to the implementation of the general rate increases in Washington and Idaho effective January 1, 2009 and October 1, 2008, respectively. The increase in net income was also partially due to a decrease in interest expense. This was partially offset by an increase in other operating expenses.

We plan to continue to invest in generation, transmission and distribution systems with a focus on providing reliable service to our customers. Utility capital expenditures were $41.5 million for the three months ended March 31, 2009. We expect utility capital expenditures to be over $210 million for 2009. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

Advantage IQ

Advantage IQ’s net income attributable to Avista Corporation was $1.2 million for the three months ended March 31, 2009, a decrease from $1.8 million for the three months ended March 31, 2008. This was primarily due to lower short-term interest rates (which decreases interest revenue), the decrease in our ownership percentage in the business in connection with the acquisition of Cadence Network effective July 2, 2008 and increased amortization of intangible assets (related to the Cadence acquisition). During 2009, we are anticipating slower internal growth at Advantage IQ than had been expected, as some of its clients are experiencing bankruptcies and store closures in these difficult economic times. Additionally, interest revenue is expected to be lower in 2009 due to the historic low short-term interest rate environment that we are currently experiencing, which is expected to continue throughout 2009.

Other Businesses

Over time as opportunities arise, we plan to dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy. The net loss attributable to Avista Corporation for these operations was $0.7 million for the three months ended March 31, 2009 compared to net income attributable to Avista Corporation of $0.2 million for the three months ended March 31, 2008. The net loss attributable to Avista Corporation in the first quarter of 2009 primarily reflects losses on long-term venture fund investments.

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. Current conditions in the financial markets have resulted in companies having limited access to capital on reasonable terms and have resulted in a significant increase in borrowing rates for corporations. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

AVISTA CORPORATION

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 5, 2011. We had $225.0 million of cash borrowings and $25.9 million in letters of credit outstanding as of March 31, 2009, under our $320.0 million committed line of credit. In November 2008, we entered into a new committed line of credit in the total amount of $200.0 million with an expiration date of November 24, 2009. We entered into this line of credit to ensure we had adequate liquidity, as conditions in the financial markets resulted in limited access to capital on reasonable terms. To date, we have not borrowed any funds under this committed line of credit.

In March 2009, we amended our accounts receivable sales facility with Bank of America, N.A. to extend the termination date to March 2010. Under this facility, we can sell without recourse, on a revolving basis, up to $85.0 million of accounts receivable. Based upon calculations under this agreement, we had the ability to sell up to $85.0 million as of March 31, 2009. There were no accounts receivable sold under this facility as of March 31, 2009.

As of March 31, 2009, we had a combined $354.1 million of available liquidity under our $320.0 million committed line of credit, $200.0 million committed line of credit, and $85.0 million revolving accounts receivable sales facility.

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

We anticipate issuing long-term debt during 2009 to reduce the balances outstanding under our committed line of credit agreements. We do not have any scheduled long-term debt maturities in 2009. The current portion of long-term debt includes $17 million of Pollution Control Bonds because the bonds are subject to purchase at any time at the option of the bond holder due to the interest rate currently being reset daily. After considering the issuances of long-term debt during 2009, we expect net cash flows from operating activities and our committed line of credit agreements (total of $520.0 million) to provide adequate resources to fund:

•

capital expenditures,

•

dividends, and

•

other contractual commitments.

In December 2006, we entered into a sales agency agreement with a sales agent to issue up to 2 million shares of our common stock from time to time. We issued 750,000 shares of common stock under this sales agency agreement in 2008. We will continue to evaluate issuing common stock in future periods; however, we are not currently planning to issue common stock in 2009.

Due to market conditions and the decline in the fair value of pension plan assets, we are planning to contribute $48 million to the pension plan in 2009 ($16 million was contributed during the first quarter of 2009) as compared to the $28 million we contributed in 2008. The final determination of pension plan contributions beyond 2009 is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We have adequate liquidity to meet our pension plan funding obligations for 2009.

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:

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provide for recovery of operating costs and capital investments, and

•

more closely align earned returns with those allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include in-service dates of major capital investments and the timing of changes in major revenue and expense items. Primarily due to the significant amount of capital investments we are making in our utility infrastructure and increasing operating costs, we filed general rate cases in Washington and Idaho in January 2009. We are planning to file in Oregon during the second quarter of 2009.

AVISTA CORPORATION

The following is a summary of our authorized rates of return in each jurisdiction:


Jurisdiction and service	Implementation Date	Authorized Overall Rate of Return		Authorized Return on Equity		Authorized Equity Level
Washington electric and natural gas	January 2009	8.22	%	10.2	%	46	%
Idaho electric and natural gas	October 2008	8.45	%	10.2	%	48	%
Oregon natural gas	April and November 2008	8.21	%	10.0	%	50	%

Washington General Rate Cases

In September 2008, we entered into a settlement stipulation with respect to our general rate case that was filed with the WUTC in March 2008. Other parties to the settlement stipulation were the staff of the WUTC, Northwest Industrial Gas Users, and the Energy Project. The Industrial Customers of Northwest Utilities (ICNU) joined in portions of the settlement and the Public Counsel Section of the Washington Attorney General’s Office (Public Counsel) did not join in the settlement stipulation. This settlement stipulation was approved by the WUTC in December 2008. The new electric and natural gas rates became effective on January 1, 2009. As agreed to in the settlement, base electric rates for our Washington customers increased by an average of 9.1 percent, which is designed to increase annual revenues by $32.5 million. Base natural gas rates for our Washington customers increased by an average of 2.4 percent, which is designed to increase annual revenues by $4.8 million.

The settlement was based on an overall rate of return of 8.22 percent with a common equity ratio of 46.3 percent and a 10.2 percent return on equity. Our original request was based on a proposed overall rate of return of 8.43 percent with a common equity ratio of 46.3 percent and a 10.8 percent return on equity.

On January 27, 2009, Public Counsel filed a Petition in Thurston County Superior Court for Judicial Review of the WUTC’s December 2008 order approving our multiparty settlement. Public Counsel raised a number of issues that were previously argued before the WUTC. These include whether settlement costs associated with resolving the dispute with the Coeur d’Alene Tribe were prudent and whether recovery of such costs would constitute illegal “retroactive ratemaking.” Public Counsel also questioned whether the WUTC’s decision to entertain supplemental testimony by us to update our filing for power supply costs during the course of the proceedings was appropriate. Finally, Public Counsel argued that the settlement improperly included advertising costs, dues and donations, and certain other expenses.

The appeal itself did not prevent the new rates from going into effect. The appeals process may take several months and a decision is not expected until later in 2009. The court will either affirm the decision of the WUTC in its entirety or reverse the decision, in whole or in part, and remand the matter back to the WUTC for further consideration, which could possibly result in de minimus refunds to customers and regulatory disallowance of the Washington portion of the $39 million that we have agreed to compensate the Tribe. We cannot predict the potential impact the outcome of this matter could ultimately have on our results of operations, financial condition or cash flows.

In January 2009, we filed a general rate case with the WUTC requesting to increase base electric rates for our Washington customers. In the general rate case filing, we requested a net electric rate increase of 8.6 percent. The net electric rate increase is based on a requested 16.0 percent increase in billed rates with an offsetting 7.4 percent reduction in the current Energy Recovery Mechanism (ERM) surcharge. We also requested a 2.4 percent increase in natural gas rates. The filing is designed to increase annual base electric service revenues by $69.8 million ($37.5 million net after considering the reduction in the current ERM surcharge) and increase annual natural gas service revenues by $4.9 million. Our request is based on a proposed rate of return on rate base of 8.68 percent, with a common equity ratio of 47.5 percent and an 11.0 percent return on equity. The WUTC generally has up to 11 months to review a general rate case filing.

Idaho General Rate Cases

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

AVISTA CORPORATION

In January 2009, we filed a general rate case with the IPUC requesting to increase base electric rates for our Idaho customers. In the general rate case filing, we requested a net electric rate increase of 7.8 percent. The net electric rate increase is based on a requested 12.8 percent increase in billed rates with an offsetting 5.0 percent reduction in the current Power Cost Adjustment (PCA) surcharge. We also requested a 3.0 percent increase in natural gas rates. The filing is designed to increase annual base electric service revenues by $31.2 million ($18.9 million net after considering the reduction in the current PCA surcharge) and increase annual natural gas service revenues by $2.7 million. Our request is based on a proposed rate of return on rate base of 8.8 percent, with a common equity ratio of 50 percent and an 11.0 percent return on equity. The IPUC generally has up to seven months to review a general rate case filing.

Oregon General Rate Cases

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

Purchased Gas Adjustments

Effective January 6, 2009, natural gas rates decreased 4.7 percent in Idaho. Effective January 16, 2009, natural gas rates decreased 3.0 percent in Washington. Effective November 1, 2008, natural gas rates decreased 4.1 percent in Oregon. Purchased gas adjustments (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 10 percent of the difference between actual and projected gas costs for unhedged supply. In October 2008, the OPUC issued an order based upon an extensive review of the current PGA mechanism. The order reaffirmed the current mechanism and included several minor modifications that we believe will not have a significant impact on our gas purchasing and hedging strategies or net income. Total net deferred natural gas costs were a liability of $26.4 million as of March 31, 2009, an increase from $18.6 million as of December 31, 2008.

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 and applies only to taxes paid and collected on or after January 1, 2006.

In February 2008, we reached a settlement stipulation with respect to the refund liability for the 2006 tax report that was approved by the OPUC in April 2008. The approved settlement provided for a refund to customers of $1.5 million, including interest for the period June 2008 through May 2009.

In October 2008, we filed the tax report for 2007 showing taxes paid to be less than taxes collected by $2.0 million before interest. We claimed that no refund should be made in connection with the 2007 tax report, asserting that such a refund would violate the “fair and reasonable” standard provided for under OPUC rules. In January 2009, we reached a settlement stipulation that would result in no refund related to the 2007 tax report. A joint brief related to the settlement was filed in February 2009. On April 10, 2009, the settlement stipulation was rejected by the OPUC and we were ordered to file tariffs to refund $2.0 million plus approximately $0.4 million of interest. After tariffs are filed, we are allowed to file a request to terminate or modify the refund, arguing that the resulting rates would not be fair or sufficient. On April 14, 2009, the OPUC issued an order adopting a temporary rule amendment changing the time period used for the earnings review to evaluate the fair and reasonable standard from the applicable tax year to the period during which the automatic adjustment clause would be in effect. We intend to file a claim that the refund would result in confiscatory rates, and propose that no refund be implemented. We have recorded a potential refund liability related to the 2008 tax report of $1.4 million. However, any final determination of refunds or surcharges to customers will ultimately be determined based on final calculations for the 2008 tax year.

Natural Gas Decoupling

In January 2007, the WUTC approved the implementation of a natural gas decoupling mechanism. Because our rate structure provides for recovery of the majority of fixed costs on a per-therm (sales volume) basis, energy efficiency and conservation objectives are directly at odds with the recovery of fixed costs, which do not vary with the volume of natural gas sold. Decoupling separates the direct link between natural gas sales volume and the recovery of the fixed cost of providing service to our customers. The decoupling mechanism allows us to recover lost margin resulting from lower usage by Washington customers due to conservation and price elasticity. However, the mechanism does not provide rate adjustments related to abnormal weather. The decoupling

AVISTA CORPORATION

mechanism is a two and one half year “pilot” that began in January 2007. We filed a request with the WUTC on April 30, 2009 to continue the natural gas decoupling mechanism on a permanent basis. The request is subject to review and approval by the WUTC. The rate adjustment in any one year would be limited to no more than 2 percent. Our most recent decoupling rate adjustment became effective November 1, 2008 and is designed to recover $0.7 million from Washington residential and small commercial customers over a twelve month period. This represents an incremental rate increase of 0.3 percent, reflecting 90 percent of the lost margin during the period July 2007 through June 2008.

Power Cost Deferrals and Recovery Mechanisms

The ERM is an accounting method used to track certain differences between actual net power supply costs and the amount included in base retail rates for our Washington customers.

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.

The initial amount of power supply costs in excess of or below the level in retail rates, which we either incur the cost of, or receive the benefit from, 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 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. 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. 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 incur the cost of, or receive the benefit from, the remaining 10 percent of the annual variance beyond $10.0 million without affecting current or future customer rates. The following is a summary of the ERM:


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

Under the ERM, we make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. Additionally, we must make a filing (no sooner than January 1, 2011), to allow all interested parties the opportunity to review the ERM, and make recommendations to the WUTC related to the continuation, modification or elimination of the ERM.

We have a Power Cost Adjustment (PCA) mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. The PCA rate surcharge, as approved by the IPUC, is 0.61 cents per KWh (designed to recover $21.7 million) for the period October 1, 2008 through September 30, 2009.

The following table shows activity in deferred power costs for Washington and Idaho during the three months ended March 31, 2009 (dollars in thousands):


	Washington			Idaho			Total
Deferred power costs as of December 31, 2008	$	36,952		$	20,655		$	57,607
Activity from January 1 – March 31, 2009:
Power costs deferred		—			2,848			2,848
Interest and other net additions		337			97			434
Recovery of deferred power costs through retail rates		(10,122	)		(5,900	)		(16,022	)

Deferred power costs as of March 31, 2009	$	27,167		$	17,700		$	44,867

AVISTA CORPORATION

Public Utility Regulatory Policy Act

In March 2009, the Idaho Public Utility Commission changed the federal Public Utility Regulatory Policy Act (“PURPA”) avoided cost rates from approximately 7 cents per kWh to approximately 9 cents per kWh for deliveries in the state of Idaho. PURPA rates are paid to qualifying resources up to 10 aMW each. We must purchase these resources under federal law. Since the new rates have gone into place, we have received three new requests for PURPA contracts, bringing the total requested contracts to four. These contracts have the potential to increase electric resource costs by $30 to $35 million per year, which would require us to approach our Washington and Idaho regulators to recover these costs.

Results of Operations

The following provides an overview of changes in our Condensed Consolidated Statements of Income for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008. 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 decreased $11.4 million to $460.9 million as a result of decreased natural gas revenues of $25.6 million, partially offset by increased electric revenues of $14.2 million. The decrease in natural gas revenues was primarily the result of decreased wholesale revenues (due to decreased prices, offset by increased volumes) of $22.4 million and retail natural gas revenues (due to decreased volumes) of $3.7 million. The increase in electric revenues was primarily due to increased retail revenues (primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increase implemented on October 1, 2008) of $17.8 million, partially offset by decreases in wholesale revenues of $1.5 million and sales of fuel of $2.6 million.

Non-utility energy marketing and trading revenues decreased $0.4 million to $6.0 million. The revenues primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. We expect that these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.

Other non-utility revenues increased $3.0 million to $20.6 million as a result of an increase in revenues from Advantage IQ of $4.8 million primarily due to customer growth and the acquisition of Cadence Network in the third quarter of 2008, partially offset by a decrease in interest earnings on funds held for customers (due to lower interest rates). The increase in revenues at Advantage IQ was partially offset by decreased revenues from our other businesses, primarily due to decreased sales at AM&D.

Utility resource costs decreased $28.5 million due to decreases in natural gas resource costs of $29.0 million. The decrease in natural gas resource costs primarily reflects a decrease in the price of natural gas purchases and decreased amortization of deferred natural gas costs.

Utility other operating expenses increased $6.0 million primarily due to an increase of $2.8 million in electric generation operating and maintenance expenses, as well as a $2.5 million increase in pension and other post-retirement benefit costs.

Utility depreciation and amortization increased $1.5 million primarily due to additions to utility plant.

Non-utility resource costs decreased $0.2 million. The costs primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. We expect that these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.

The net change in other non-utility operating expenses was an increase of $3.4 million due to an increase of $4.9 million for Advantage IQ due to expanding operations and the acquisition of Cadence Network in the third quarter of 2008. The increase in expenses at Advantage IQ was partially offset by decreased operating expenses from our other businesses, primarily AM&D.

Interest expense decreased $3.3 million due to the effect of long-term debt maturities and redemptions during 2008, which were funded primarily with proceeds from the issuance of long-term debt as well as borrowings under our $320.0 million committed line of credit at lower interest rates.

AVISTA CORPORATION

Interest expense to affiliated trusts decreased $0.3 million due to a decrease in the variable interest rate.

Other income-net decreased $1.7 million due in part to $0.7 million of losses on long-term venture fund investments.

Income taxes increased $2.4 million primarily due to increased income before income taxes. Our effective tax rate was 35.7 percent for the three months ended March 31, 2009 compared to 37.3 percent for the three months ended March 31, 2008.

Avista Utilities

Net income for the utility was $30.6 million for the three months ended March 31, 2009 compared to $23.3 million for the three months ended March 31, 2008. Utility income from operations was $63.6 million for the three months ended March 31, 2009 compared to $55.8 million for the three months ended March 31, 2008. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses, depreciation and amortization and taxes other than income taxes.

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


	Electric				Natural Gas				Total
	2009		2008		2009		2008		2009		2008
Operating revenues	$	240,467	$	226,237	$	220,397	$	246,035	$	460,864	$	472,272
Resource costs		121,965		121,548		167,727		196,678		289,692		318,226

Gross margin	$	118,502	$	104,689	$	52,670	$	49,357	$	171,172	$	154,046

Utility operating revenues decreased $11.4 million and utility resource costs decreased $28.5 million, which resulted in an increase of $17.1 million in gross margin. The gross margin on electric sales increased $13.8 million and the gross margin on natural gas sales increased $3.3 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2009 and Idaho effective October 1, 2008. We had a benefit of $2.7 million in the first quarter of 2009 and absorbed $3.4 million of expense in the first quarter of 2008 under the ERM, which increased electric gross margin by $6.1 million in the first quarter of 2009 as compared to the first quarter of 2008.

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 Revenues				Electric Energy MWh sales
	2009		2008		2009	2008
Residential	$	99,434	$	88,483	1,177	1,155
Commercial		69,067		63,209	805	824
Industrial		25,355		24,525	461	512
Public street and highway lighting		1,660		1,470	7	6

Total retail		195,516		177,687	2,450	2,497
Wholesale		29,201		30,676	597	311
Sales of fuel		11,972		14,578	—	—
Other		3,778		3,296	—	—

Total	$	240,467	$	226,237	3,047	2,808

Retail electric revenues increased $17.8 million due to an increase in revenue per MWh (increased revenues $21.7 million) primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increase implemented on October 1, 2008, offset by a decrease in total MWhs sold (decreased revenues $3.9 million) primarily due to a decrease in use per customer.

Wholesale electric revenues decreased $1.5 million due to a decrease in sales prices (decreased revenues $15.5 million), offset by an increase in sales volumes (increased revenues $14.0 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel decreased $2.6 million due to lower natural gas prices in the first quarter of 2009 as compared to the first quarter of 2008, offset by an increase in thermal generation resource optimization activities.

AVISTA CORPORATION

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 Operating Revenues				Natural Gas Therms Delivered
	2009		2008		2009	2008
Residential	$	114,254	$	116,755	88,937	91,181
Commercial		62,640		63,997	53,180	54,285
Interruptible		1,637		1,465	1,761	1,524
Industrial		2,055		2,116	1,954	2,030

Total retail		180,586		184,333	145,832	149,020
Wholesale		36,505		58,861	78,845	72,043
Transportation		1,550		1,688	39,538	42,331
Other		1,756		1,153	274	269

Total	$	220,397	$	246,035	264,489	263,663

The $3.7 million decrease in retail natural gas revenues was due to a decrease in volumes (decreased revenues $3.9 million), partially offset by slightly higher retail rates (increased revenues $0.2 million). We sold less retail natural gas in the first quarter of 2009, primarily due to warmer weather in the first quarter of 2009 as compared to the first quarter of 2008. The slight increase in retail rates reflects the Washington general rate increase implemented on January 1, 2009 and Idaho general rate increase implemented on October 1, 2008, offset by the purchased gas adjustments implemented in the first quarter of 2009.

The decrease in our wholesale natural revenues of $22.4 million was due to a decrease in prices (decreased revenues $25.5 million), partially offset by an increase in volumes (increased revenues $3.1 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Additionally, we engage in optimization of under-utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

The following table presents our average number of electric and natural gas retail customers for the three months ended March 31:


	Electric Customers		Natural Gas Customers
	2009	2008	2009	2008
Residential	314,462	311,769	281,385	278,304
Commercial	39,296	39,054	33,313	32,926
Interruptible	—	—	42	39
Industrial	1,389	1,384	262	258
Public street and highway lighting	441	428	—	—

Total retail customers	355,588	352,635	315,002	311,527

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


	2009		2008
Electric resource costs:
Power purchased	$	54,347	$	51,498
Power cost amortizations, net of deferrals		13,174		6,241
Fuel for generation		30,198		39,782
Other fuel costs		16,923		15,350
Other regulatory amortizations, net		5,185		5,146
Other electric resource costs		2,138		3,531

Total electric resource costs		121,965		121,548

Natural gas resource costs:
Natural gas purchased		156,121		171,529
Natural gas amortizations, net of deferrals		7,602		21,588
Other regulatory amortizations, net		4,004		3,561

Total natural gas resource costs		167,727		196,678

Total resource costs	$	289,692	$	318,226

AVISTA CORPORATION

Power purchased increased $2.8 million due to an increase in the volume of power purchases (increased costs $12.2 million), primarily due to an increase in sales volumes related to optimization, partially offset by a decrease in wholesale prices (decreased costs $9.4 million).

Net amortization of deferred power costs was $13.2 million for the three months ended March 31, 2009 compared to $6.2 million for the three months ended March 31, 2008. During the first quarter of 2009, we recovered (collected as revenue) $10.1 million of previously deferred power costs in Washington and $5.9 million in Idaho. During the first quarter of 2009, we deferred $2.8 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates. We did not defer any power costs in Washington during the first quarter of 2009, as power supply costs were within the $4.0 million deadband below the amount included in base retail rates under the ERM.

Fuel for generation decreased $9.6 million due to a decrease in fuel prices.

Other fuel costs increased $1.6 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economical to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel. Other fuel costs exceeded revenues we received from selling the natural gas. We account for this shortfall under the ERM in Washington and the PCA in Idaho.

The expense for natural gas purchased decreased $15.4 million due to a decrease in the price of natural gas, partially offset by an increase in the total therms purchased. The increase in total therms purchased was due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process, partially offset by a decrease in retail sales volumes. We engage in optimization of under utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During the first quarter of 2009, we amortized $7.6 million of deferred natural gas costs compared to $21.6 million for the first quarter of 2008.

Advantage IQ

Advantage IQ’s net income attributable to Avista Coporation was $1.2 million for the three months ended March 31, 2009 compared to $1.8 million for the three months ended March 31, 2008. Operating revenues increased $4.8 million and operating expenses increased $5.2 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base and the third quarter 2008 acquisition of Cadence Network, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). As of March 31, 2009, Advantage IQ had 540 customers representing 427,000 billed sites in North America. The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base, as well as the third quarter 2008 acquisition of Cadence Network (including the amortization of intangible assets). In the first quarter of 2009, Advantage IQ managed bills totaling $4.6 billion, an increase of $1.2 billion, or 35 percent, as compared to the first quarter of 2008. The acquisition of Cadence Network (in July 2008) added $1.0 billion in managed bills for the first quarter of 2009.

Other Businesses

Net loss attributable to Avista Corporation from these operations was $0.7 million for the three months ended March 31, 2009 compared to net income attributable to Avista Corporation of $0.2 million for the three months ended March 31, 2008. Operating revenues decreased $2.2 million and operating expenses decreased $1.6 million. Contributing to the net loss attributable to Avista Corporation in the first quarter of 2009 were losses on long-term venture fund investments.

New Accounting Standards

Effective January 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements” related to our financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the FASB issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. Effective January 1, 2009, we adopted those provisions of SFAS No. 157. The adoption of the provisions of SFAS No. 157, that became effective on January 1, 2008 and 2009, did not have a material impact on our financial condition and results of operations. However, we expanded disclosures with respect to fair value measurements that became effective on January 1, 2008. There were no additional disclosures related to the provisions that became effective January 1, 2009. See Note 9 for the expanded disclosures.

Effective January 1, 2009, we adopted SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. The adoption of SFAS No. 141(R) did not have any impact on our financial condition and results of operations.

AVISTA CORPORATION

Effective January 1, 2009, we adopted adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for a noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. The adoption of SFAS No. 160 did not have any material impact on our financial condition and results of operations. However, it did impact the presentation and disclosure of noncontrolling (minority) interests in the condensed consolidated financial statements. The presentation and disclosure requirements have been retrospectively applied to the condensed consolidated financial statements. The noncontrolling (minority) interests primarily relates to third party shareholders of Advantage IQ, who own approximately 26 percent as of March 31, 2009. See Note 2 for changes to the presentation and disclosure of noncontrolling (minority) interests.

Effective January 1, 2009, we adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This statement required disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement also required disclosure of derivative features that are related to credit risk. We expanded our disclosures with respect to derivatives and hedging activities. See Note 4 for the expanded disclosures.

In December 2008, the FASB issued FSP 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This FSP amends FASB statement No. 132(R) “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” This statement provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. We will be required to adopt FSP 132(R)-1 at the end of 2009. We will have expanded disclosures with respect to our pension and other postretirement benefit plan assets.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This FSP also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures in summarized financial information at interim reporting periods. We will be required to adopt FSP FAS 107-1 and APB 28-1 for the quarter ending June 30, 2009. We will be required to disclose the fair value of financial instruments on an interim basis in our quarterly financial statements that will be consistent with the disclosures currently required in our annual financial statements.

Critical Accounting Policies and Estimates

The preparation of our condensed 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 condensed consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our condensed 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 2008 Form 10-K and have not changed materially from that discussion.

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall During the three months ended March 31, 2009, positive cash flows from operating activities of $91.6 million were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $41.5 million, repayment of short-term borrowings of $26.1 million and dividends of $9.8 million.

Operating Activities Net cash provided by operating activities was $91.6 million for the first quarter of 2009 compared to $44.5 million for the three months ended March 31, 2008. Net cash provided by working capital components was $28.8 million for the three months ended March 31, 2009, compared to cash used of $25.0 million for the three months ended March 31, 2008. The net cash provided during the first quarter of 2009 primarily reflects an increase in cash flows from:

•

accounts receivable (representing a decrease in the receivables outstanding offset by a $17.0 million decrease in the amount of receivables that were sold),

•

other current assets (primarily related to federal income taxes), and

•

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

AVISTA CORPORATION

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

The net cash used during the three months ended March 31, 2008 primarily reflected an increase in cash flows from accounts receivable (representing net cash owed from our customers primarily from wholesale transactions including sales of fuel, electricity and natural gas), as well as a decrease in the amount of accounts receivable sold under our revolving accounts receivable sales facility. This cash used was partially offset by positive cash flows from accounts payable (representing net cash owed to our vendors), other current liabilities, other current assets (primarily related to federal income taxes), materials and supplies, fuel stock and natural gas stored (representing the seasonal drawdown of natural gas inventory) and deposits from counterparties (representing cash received as collateral funds from counterparties at Avista Utilities).

Significant non-cash items included $20.8 million of power and natural gas cost amortizations, net of deferrals, for the first quarter of 2009, a decrease from $27.6 million for the first quarter of 2008.

Investing Activities Net cash used in investing activities was $45.8 million for the three months ended March 31, 2009, a decrease compared to $47.4 million for the three months ended March 31, 2008. Utility property capital expenditures decreased in the first quarter of 2009 as compared to the first quarter of 2008, and funds held from customers at Advantage IQ increased.

Financing Activities Net cash used in financing activities was $34.4 million for the first quarter of 2009 compared to $4.0 million provided by financing activities for the first quarter of 2008. During the first quarter of 2009, our short-term borrowings decreased $26.1 million, which primarily reflects a decrease in the amount of debt outstanding under our $320.0 million committed line of credit. Cash dividends paid increased to $9.8 million (or 18.0 cents per share) for the first quarter of 2009 from $8.8 million (or 16.5 cents per share) for the first quarter of 2008. Additionally, customer funds obligations at Advantage IQ increased by $1.9 million.

During the first quarter of 2008, our short-term borrowings increased $29.0 million. In March 2008, we cash settled two interest rate swap agreements and paid a total of $16.4 million.

AVISTA CORPORATION

Overall Liquidity

Our consolidated operating cash flows are primarily derived from the operations of Avista Utilities. The primary source of operating cash flows for our utility operations is revenues (including the recovery of previously deferred power and natural gas costs) from sales of electricity and natural gas. Significant uses of cash flows from our utility operations include the purchase of electricity and natural gas, and payment of other operating expenses, taxes and interest, with any excess being available for other corporate uses such as capital expenditures and dividends.

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

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

We periodically file for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align our earned returns with those allowed by regulators. Effective January 1, 2009, the WUTC authorized an increase in our rates in Washington designed to increase annual electric revenues by $32.5 million and annual natural gas revenues by $4.8 million. Effective October 1, 2008, the IPUC authorized an increase in our rates in Idaho designed to increase annual electric revenues by $23.2 million and annual natural gas revenues by $3.9 million. See further details in the section “Avista Utilities - Regulatory Matters.”

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

•

increases in demand (either due to weather or customer growth),

•

low availability of streamflows for hydroelectric generation,

•

unplanned outages at generating facilities, and

•

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

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

•

$320.0 million committed line of credit,

•

$200.0 million committed line of credit, and

•

$85.0 million revolving accounts receivable sales facility.

As of March 31, 2009, we had a combined $354.1 million of available liquidity under the three facilities described above.

Our utility has regulatory mechanisms in place that provide for the deferral and recovery of the majority of power and natural gas supply costs. However, if prices increase, deferral balances will increase, which will negatively affect our cash flow and liquidity until such costs, with interest, are recovered from customers.

Exposure to Demands for Collateral

Our contracts for the purchase and sale of energy commodities often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement in the event of a downgrade in our credit ratings or adverse changes in market prices. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below investment grade and energy prices decreased by 15 percent in the first year and 20 percent in subsequent years, we estimate, based on our positions outstanding at March 31, 2009, that we would potentially be required to post additional collateral up to $133.1 million. The additional collateral amount is higher than the amount disclosed in Note 4 to the Condensed Consolidated Financial Statements because this analysis includes contracts that are not considered derivatives under SFAS 133 and due to the assumptions about potential energy price changes.

AVISTA CORPORATION

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

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, 2009 and December 31, 2008 (dollars in thousands):


	March 31, 2009				December 31, 2008
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	17,132	0.8	%	$	17,207	0.8	%
Short-term borrowings		226,100	10.4			252,200	11.5
Long-term debt to affiliated trusts (1)		113,403	5.2			113,403	5.2
Long-term debt		809,686	37.0			809,258	37.0

Total debt		1,166,321	53.4			1,192,068	54.5
Total Avista Corporation stockholders’ equity		1,019,220	46.6			996,883	45.5

Total	$	2,185,541	100.0	%	$	2,188,951	100.0	%

(1)

We need to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund capital expenditures, working capital, purchased power and natural gas costs, dividends and other requirements. Our stockholders’ equity increased $22.3 million during the first quarter of 2009 primarily due to net income, partially offset by dividends.

We generally fund capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by our utility operating activities and issuance of long-term debt are expected to be the primary source of funds for operating needs, dividends and capital expenditures for 2009. Borrowings under our $320.0 million committed line of credit, $200.0 million committed line of credit and sales of accounts receivable under our $85.0 million revolving facility will supplement these funds to the extent necessary.

We do not have any scheduled long-term debt maturities in 2009. The current portion of long-term debt includes $17.0 million of Pollution Control Bonds because the bonds are subject to purchase at any time at the option of the bond holder. We are planning to issue long-term debt during 2009 to repay a portion of the amounts that are outstanding on our credit agreement.

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 2011 with the following banks:


	Commitment (in millions)
Union Bank of California, N.A.	$	60.0
The Bank of New York Mellon	$	45.0
Wells Fargo Bank, National Association	$	35.0
US Bank National Association	$	35.0
Keybank National Association	$	35.0
Bank of America, N.A.	$	30.0
Mizuho Corporate Bank, LTD	$	25.0
Comerica West Incorporated	$	20.0
Societe Generale	$	15.0
First Commercial Bank, New York	$	10.0
Bank Hapoalim B.M., New York Branch	$	10.0

AVISTA CORPORATION

Under the agreement, we can request the issuance of up to $320.0 million in letters of credit. As of March 31, 2009, we had $225.0 million in borrowings outstanding under this committed line of credit, a decrease from $250.0 million in borrowings outstanding as of December 31, 2008. As of March 31, 2009, there were $25.9 million in letters of credit outstanding, an increase from $24.3 million as of December 31, 2008. The committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that we default on obligations under the committed line of credit.

Additionally, in November 2008, we entered into a new committed line of credit in the total amount of $200.0 million with an expiration date of November 2009 with the following banks:


	Commitment (in millions)
Union Bank of California, N.A.	$	44.25
Wells Fargo Bank, National Association	$	44.25
JPMorgan Chase Bank, N.A.	$	26.50
Keybank National Association	$	22.00
Suntrust Bank	$	22.00
US Bank National Association	$	17.50
The Bank of New York Mellon	$	13.50
UBS Loan Finance LLC	$	10.00

As of March 31, 2009, we did not have any borrowings outstanding under this committed line of credit. The committed line of credit is secured by $200.0 million of non-transferable First Mortgage Bonds issued to the agent bank. Such First Mortgage Bonds would only become due and payable in the event, and then only to the extent, that we default on obligations under the committed line of credit.

Our committed line of credit agreements contain customary covenants and default provisions, including a covenant requiring the ratio of “earnings before interest, taxes, depreciation and amortization” to “interest expense” of Avista Utilities for the preceding twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of March 31, 2009, we were in compliance with this covenant with a ratio of 3.53 to 1. The committed line of credit agreements also have a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 70 percent at any time. As of March 31, 2009, we were in compliance with this covenant with a ratio of 53.1 percent. If the proposed change in organization to a holding company structure becomes effective, the committed line of credit agreements will remain at Avista Corp. (Avista Utilities). See “Note 12 of the Notes to Condensed Consolidated Financial Statements” for further information on the proposed change in organization to a holding company structure. The committed line of credit agreements also have a covenant which requires the Company to maintain a minimum funded ratio of the pension plan assets to liabilities. The Pension Protection Act of 2006 (that was implemented in 2008) modified the liability calculation utilized to calculate the funded ratio. Avista Corp. amended the covenant related to the pension funded ratio, under its $320.0 million committed line of credit agreement, to conform with the calculations under the Pension Protection Act of 2006.

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

We are restricted under our Restated Articles of Incorporation as to the additional preferred stock we can issue.

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

•

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

•

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

•

deposit of cash

AVISTA CORPORATION

provided, however, that we may not issue any additional First Mortgage Bonds (with certain exceptions in the case of bonds issued on the basis of retired bonds) unless our “net earnings” (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all indebtedness of prior rank.

Advantage IQ Credit Agreement

Off-Balance Sheet Arrangements

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

The Receivables Purchase Agreement was originally entered into on May 29, 2002 and provides us with cost-effective funds for:

•

working capital requirements,

•

capital expenditures, and

•

other general corporate needs.

Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of our receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of our committed line of credit agreements. As of March 31, 2009, we had the ability to sell up to $85.0 million of receivables and there were no accounts receivable sold under this revolving agreement.

Credit Ratings

The following table summarizes our credit ratings as of April 30, 2009:


	Standard & Poor’s (1)	Moody’s (2)	Fitch, Inc. (3)
Avista Corporation
Corporate/Issuer rating	BBB-	Baa3	BB+
Senior secured debt (4)	BBB+	Baa2	BBB
Senior unsecured debt	BBB-	Baa3	BBB-
Preferred stock	BB	Ba2	BB+
Avista Capital II (5)
Preferred Trust Securities	BB	Ba1	BB+
AVA Capital Trust III (5)
Preferred Trust Securities	BB	Ba1	BB+
Rating outlook	Stable	Stable	Positive

(1)	Ratings were upgraded in February 2008.

(2)	Ratings were upgraded in December 2007.

(3)	Ratings were upgraded in August 2007 and affirmed in February 2008.

(4)

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

AVISTA CORPORATION

(5)	Only assets are subordinated debentures of Avista Corporation (redeemed April 1, 2009).

Each security rating agency has its own methodology for assigning ratings. Security ratings are not recommendations to buy, sell or hold securities. The ratings are subject to change or withdrawal at any time by the respective credit rating agencies. Each credit rating should be evaluated independently of any other ratings.

Pension Plan

As of March 31, 2009, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. We contributed $28 million to the pension plan in 2008 and $15 million in both 2006 and 2007. Our total pension plan contributions were $112 million from 2002 through 2008. Due to market conditions and the decline in the fair value of pension plan assets, we plan to contribute $48 million to the pension plan in 2009 ($16 million was contributed during the first quarter of 2009). The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We have adequate liquidity to meet our pension plan funding obligations for 2009.

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 contained in our Restated Articles of Incorporation, as amended.

In March 2009, Avista Corp. paid a quarterly dividend of $0.18 per share on the Company’s common stock.

As further discussed at “Note 12 of the Notes to the Condensed Consolidated Financial Statements,” the IPUC accepted a stipulation that we entered with the IPUC Staff that sets forth a variety of conditions if and when we implement a holding company structure. One of the conditions would require IPUC approval of any dividend to the holding company that would reduce utility common equity below 25 percent. We entered into a similar agreement in Washington. This agreement would require WUTC approval of any dividend to the holding company that would reduce utility common equity below 30 percent. The utility equity component was approximately 44.7 percent as of March 31, 2009.

Avista Utilities Capital Expenditures

We expect utility capital expenditures to be over $210 million for each of 2009, 2010 and 2011. In addition to ongoing needs for our distribution system, significant projects include upgrades to generating facilities. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

We are committed to investment in generation, transmission and distribution systems with a focus on increasing capacity and improving reliability. We continue to upgrade hydroelectric plants to increase their availability and capture additional output.

In February 2009, the U.S. House of Representatives and Senate approved the conference report for the American Recovery and Reinvestment Act (the ARRA) of 2009. The ARRA includes almost $80 billion of stimulus funding in areas that have some relation to electric and natural gas utilities, such as Avista Corp. We are currently reviewing the ARRA to determine if there are potential funding opportunities. We are determining which projects match the goals of the stimulus and benefit our stakeholders. No financial commitments have been made as of May 1, 2009. If we decide to apply for stimulus funds, an application will be submitted once the Department of Energy announces the process with regards to obtaining stimulus funds.

AVISTA CORPORATION

In the second quarter of 2008, we completed the acquisition of a wind generation site. We expect to construct a 50 MW generation facility at an estimated cost of over $125 million with the majority of the costs expected to be incurred in 2013 and thereafter. We are evaluating the ARRA related to potential stimulus funding and the investment tax credit rules. We may accelerate the deployment of capital related to this wind generation site depending on the outcome of this analysis. Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements as discussed at “Environmental Issues and Other Contingencies.”

We are participating in planning activities for the development of a proposed 3,000 MW transmission project that would extend from British Columbia, Canada to Northern California. Other participants include Pacific Gas and Electric Company, PacifiCorp, and British Columbia Transmission Corporation. We have executed an agreement (stage one agreement) with the other participants in order to perform preliminary studies and assessments for the project, including electrical system studies and resource mapping of possible transmission line corridors. Under the stage one agreement, we have committed to contribute $0.6 million, or 12.25 percent of the total stage one costs of the project.

Contractual Obligations

Our future contractual obligations have not changed materially from the amounts disclosed in the 2008 Form 10-K with the following exceptions:

As of March 31, 2009, we had $225.0 million of borrowings outstanding under our $320 million committed line of credit. There were $250.0 million in borrowings outstanding as of December 31, 2008.

Business Risk

Primarily through our utility operations, we are exposed to risks including, but not limited to:

•

economic conditions in our service areas, including the effect on the demand for, and customers’ ability to pay for, our utility services,

•

streamflow and weather conditions that impact hydroelectric generation, utility operations and customer demand,

•

market prices and supply of wholesale energy, which we purchase and sell, including power, fuel and natural gas,

•

regulatory disallowance of the recovery of power and natural gas costs, operating costs and capital investments and the allowance of a reasonable rate of return on investment,

•

the effects of changes in legislative and governmental regulations, including restrictions on emissions from generating plants and requirements for the acquisition of new resources,

•

changes in regulatory requirements,

•

availability of generation facilities,

•

customer response to rate increases, and

•

competition.

Also, like other utilities, our facilities and operations are exposed to natural disasters and terrorism risks or other malicious acts. In addition, the energy business exposes us to the financial, liquidity, credit and price risks associated with wholesale purchases and sales of energy commodities. See further reference to risks and uncertainties under “Forward-Looking Statements.”

Our business risk has not materially changed during the three months ended March 31, 2009. Please refer to the 2008 Form 10-K for further description and analysis of business risk including, but not limited to, commodity price, credit, other operating, interest rate and foreign currency risks.

AVISTA CORPORATION

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 2008 Form 10-K for discussion of risk management policies and procedures.

Economic and Utility Load Growth

Along with others in our utility service area, we encourage regional economic development, including expanding existing businesses and attracting new businesses to the Inland Northwest and Southwest Oregon region. Agriculture, mining and lumber were the primary industries for many years; today health care, education, finance, electronic and other manufacturing, tourism and the service sectors have grown in importance in our utility service area.

Based on our forecast for electric customer growth to average 0.7 to 1.6 percent and natural gas customer growth to average 1.1 to 2.8 percent within our service area, we anticipate retail electric and natural gas load growth will average between 0.2 and 1.6 percent annually for the four year period 2009-2012. This forecast of load growth takes into account recession impacts and represents a decline as compared to our forecast in the 2008 Form 10-K. While the number of electric customers is growing, the average annual usage by each residential electric customer has stabilized. Natural gas sales growth has slowed as retail prices have risen and Company sponsored conservation programs have intensified. Population increases and business growth in our three-state service territory remains above the national average. Natural gas loads for space heating vary significantly with annual fluctuations in weather within our service territories.

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

•

assumptions relating to weather and economic and competitive conditions,

•

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

•

internal business plans, and

•

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

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

Environmental Issues and Other Contingencies

We are subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which we have an ownership interest are designed and operated in compliance with applicable environmental laws.

We monitor legislative and regulatory developments at all levels of government with respect to 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 costs of generating plants,

•

increase the lead time for the construction of new generating plants,

•

require modification of our existing generating plants,

•

require existing generating plants to be curtailed or shut down,

•

increase the risk of delay on construction projects,

•

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

•

restrict the types of generating plants that can be built.

Compliance with environmental laws and regulations could result in increases to capital expenditures and operating expenses. However, we intend to seek recovery of incurred costs through the ratemaking process.

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

AVISTA CORPORATION

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

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

The state of Washington’s continued participation in the Western Climate Initiative (WCI) was affirmed in 2009. The Governors of Arizona, California, New Mexico, Oregon, Washington, Utah and Montana, along with the Premiers of British Columbia, Manitoba, Ontario and Quebec, created the WCI to develop a regional cap-and-trade program with an overall regional goal for reducing greenhouse gas emissions to 15 percent below 2005 levels by 2020. In September 2008, the WCI partners released recommendations for the design of such a program, which would apply cap-and-trade regulation to the electricity sector in 2012 and to emissions associated with the distribution of natural gas by 2015. The WCI is presently following a work plan to refine its recommendations. The Governor introduced legislation during the 2009 Legislative Session seeking authority to implement cap-and-trade regulations. That authorization was not given. In 2008, Washington codified goals to reduce greenhouse gas emissions to 1990 levels by 2020; to 25 percent below 1990 levels by 2035; and to 50 percent below 1990 levels by 2050.

Legislation was introduced in January 2009 before the Washington State Legislature to confer authority to the Washington State Department of Ecology (DOE) to implement and enforce a cap-and-trade regulatory regime, “consistent with the regional cap-and-trade program”, designed by the WCI. This legislation was substantially amended to merely affirm Washington’s participation in the WCI and essentially defer consideration of legislation enabling the State of Washington to implement a regional cap-and-trade system until 2011. That legislation is still pending.

A greenhouse gas emissions performance standard (SB 6001) passed into law in the state of Washington during 2007. This law places significant restrictions on greenhouse gas emissions from any new generation plants built in the state of Washington. Furthermore, the bill intends to prevent utilities from entering into long-term contracts (five years or more) to purchase energy produced by plants in other states that do not meet the same restrictions. Currently, the only type of non-renewable base load thermal generating plants that meet these restrictions are natural gas-fired combined-cycle combustion turbines.

Initiative Measure 937 (I-937), the Energy Independence Act, was passed into law through the General Election in Washington in November 2006. I-937 requires investor-owned, cooperative, and government-owned electric utilities with over 25,000 customers to acquire new 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 beginning in 2012. 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 resources and/or renewable credits. Legislation is pending to increase the renewable energy standard by 1.25 percent in 2016 and 2020, to allow utilities to count biomass generation entering commercial operation before March 31, 1999, against the renewable energy standard, and to permit utilities to acquire non-hydro renewable energy and renewable energy credits from anywhere within the jurisdiction of the Western Electricity Coordinating Council.

Our most recent Electric Integrated Resource Plan (IRP), which we filed with the WUTC and the IPUC in August 2007, includes the acquisition of additional renewable resources such that, if the IRP is implemented, we would be compliant with the requirement by the various milestone dates. The IRP outlines a preferred resource strategy that calls for 350 MW of natural gas generation, 300 MW of wind generation, 87 MW of conservation, 38 MW of hydroelectric generation plant upgrades and 35 MW of other renewable generation by 2017. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

We are required to file an IRP every two years. We will file an IRP in August 2009 and the preferred resource strategy may change based upon market, legislative and regulatory changes.

AVISTA CORPORATION

In October 2007, we became a member of the Chicago Climate Exchange (CCX), North America’s only voluntary, verifiable and legally binding emissions reduction and trading marketplace for all six greenhouse gases. Members agree to reduce their greenhouse gas emissions by 6 percent from an established baseline by 2010. The CCX allows participants who exceed their reduction targets to bank or sell the excess CCX Carbon Financial Instruments. The audit establishing our 2007 baseline emissions was completed in July 2008. We received credit for 1,470 CCX Carbon Financial Instruments in October 2008. The 2008 emissions audit data was submitted in April 2009.

Recent EPA Initiatives Related to Climate Change

In March 2009, the EPA issued a proposed rule for mandatory greenhouse gas (GHG) reporting. The public comment period is open until June 9, 2009. EPA’s rule would require mandatory reporting of GHGs from large emission sources in the United States, as required by the FY2008 Consolidated Appropriations Act. This is a reporting rule to collect comprehensive emissions data to inform future policy decisions.

In general, the proposed threshold for reporting is 25,000 metric tons or more of carbon dioxide (CO2) equivalent per year. Our CO2 emissions, as currently measured from thermal generation sources, exceed this level. Therefore, we will be required to report GHG emissions to EPA, should this rule be adopted in final form. Based on the proposed rule, we would meet initial reporting requirements through submission of data already collected under EPA’s Acid Rain Program. We cannot currently estimate the cost of compliance with this GHG reporting requirement, but we are tracking the rule development and will be better able to estimate the cost of compliance when the rule is finalized.

In April 2009, the EPA issued proposed findings that six greenhouse gases (carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride) present a health and safety issue such that they should be regulated under the Clean Air Act. These proposed findings are based on a 2007 U.S. Supreme Court case, Massachusetts v. EPA, 549 U.S. 497. The Court’s decision requires applying such a finding to motor vehicles.

Once finalized, the EPA will be obligated to regulate the gases under section 202(a) of the Clean Air Act, which requires that the Administrator set standards for emissions of pollutants from new motor vehicles and new motor vehicle engines. However, according to EPA, the findings could lay the groundwork for regulating these gases under other provisions of the Clean Air Act.

Publication of these proposed findings in the Federal Register will trigger a public comment period. We cannot currently estimate any direct impact of these proposed findings to our operations. However, we believe these proposed findings could be indicative of the policy direction to regulate GHG at the federal level through some kind of mechanism, including through the Clean Air Act. We continue to track and evaluate these developments.

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

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations: – Business Risk and – Risk Management,” “Note 4 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, 2009.

AVISTA CORPORATION

There have been no changes in the Company’s internal control over financial reporting that occurred during the first quarter of 2009 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 2008 Form 10-K for disclosure of risk factors that could have a significant impact on our operations, 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 2008 Form 10-K.

In addition to these risk factors, please also see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.

Item 5.

Other Information

Effective January 1, 2009, we adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amended Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for a noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. The adoption of SFAS No. 160 did not have any material impact on our financial condition and results of operations. However, it did impact the presentation and disclosure of noncontrolling (minority) interests in our consolidated financial statements. As a result of the retrospective presentation and disclosure requirements of SFAS No. 160, we will be required to reflect the change in presentation and disclosure for all periods presented in future filings. The noncontrolling (minority) interests primarily relates to third party shareholders of Advantage IQ, who own approximately 26 percent as of March 31, 2009.

We determined that the accounting change was not material to the previously issued financial statements and thus we are not amending our previously filed 2008 Form 10-K. The following table summarizes the effects of the adoption of SFAS No. 160 on our financial statements as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007 and 2006 (in thousands, except per share amounts):


	2008				2007				2006
	As Previously Reported		As Revised		As Previously Reported		As Revised		As Previously Reported	As Revised
Consolidated Statements of Income:
Other income - net	$	9,309	$	10,446	$	10,806	$	11,058	8,600	8,600
Net income		73,620		74,757		38,475		38,727	72,941	72,941
Net income attributable to Avista Corporation (1)		—		73,620		—		38,475	—	72,941
Net income attributable to noncontrolling interests (1)		—		1,137		—		252	—	—
Total earnings per common share, basic		1.37		—		0.73		—	1.48	—
Total earnings per common share, diluted		1.36		—		0.72		—	1.46	—
Earnings per common share attributable to Avista Corporation:
Basic (1)		—		1.37		—		0.73	—	1.48
Diluted (1)		—		1.36		—		0.72	—	1.46

AVISTA CORPORATION


	2008						2007						2006
	As Previously Reported			As Revised			As Previously Reported			As Revised			As Previously Reported			As Revised
Consolidated Statements of Comprehensive Income:
Net income	$	73,620		$	74,757		$	38,475		$	38,727			72,941			72,941
Comprehensive income		87,136			88,273			36,683			36,935			82,103			82,103
Comprehensive income attributable to noncontrolling interests (1)		—			1,137			—			252			—			—
Comprehensive income attributable to Avista Corporation (1)		—			87,136			—			36,683			—			82,103
Consolidated Balance Sheets:
Total liabilities	$	2,633,864		$	2,622,658		$	2,275,831		$	2,274,969
Noncontrolling interest (1)		—			11,206			—			862
Total Avista Corporation Stockholders’ Equity (1)		—			996,883			—			913,966
Total stockholders’ equity		996,883			1,008,089			913,966			914,828
Consolidated Statements of Cash Flows:
Operating Activities:
Net income	$	73,620		$	74,757		$	38,475		$	38,727		$	72,941		$	72,941
Other		(868	)		(2,005	)		(7,265	)		(7,517	)		(16,018	)		(16,018	)
Consolidated Statements of Stockholders’ Equity:
Net income	$	73,620		$	74,757		$	38,475		$	38,727		$	72,941		$	72,941
Noncontrolling interest (1)		—			11,206			—			862			—			733
Total stockholders’ equity		996,883			1,008,089			913,966			914,828			914,525			915,258

(1)	Represents a new financial statement line item included as a result of the retrospective application of SFAS No. 160.

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*

31.2		Certification of Chief Financial Officer*

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)**

*	Filed herewith.

**	Furnished herewith.

AVISTA CORPORATION

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 1, 2009				/s/ Mark T. Thies
				Mark T. Thies
				Senior Vice President and
				Chief Financial Officer
				(Principal Financial Officer)