Edgar Filing: AVISTA CORP

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-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 September 30, 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):

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 October 23, 2009, 54,779,281 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 September 30, 2009 and 2008	3

		Condensed Consolidated Statements of Income - Nine Months Ended September 30, 2009 and 2008	4

		Condensed Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2009 and 2008	5

		Condensed Consolidated Balance Sheets - September 30, 2009 and December 31, 2008	6

		Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2009 and 2008	8

		Condensed Consolidated Statements Stockholders’ Equity - Nine Months Ended September 30, 2009 and 2008	9

		Notes to Condensed Consolidated Financial Statements	10

		Report of Independent Registered Public Accounting Firm	32

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61

	Item 4.	Controls and Procedures	61

Part II. Other Information:

	Item 1.	Legal Proceedings	62

	Item 1A.	Risk Factors	62

	Item 6.	Exhibits	62

Signature			63

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 33-34. 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 September 30

Dollars in thousands, except per share amounts

(Unaudited)


	2009			2008
Operating Revenues:
Utility revenues	$	284,249		$	353,824
Non-utility energy marketing and trading revenues		6,491			6,824
Other non-utility revenues		23,952			22,037

Total operating revenues		314,692			382,685

Operating Expenses:
Utility operating expenses:
Resource costs		167,462			245,127
Other operating expenses		55,332			49,114
Depreciation and amortization		23,630			22,023
Taxes other than income taxes		16,284			15,323
Non-utility operating expenses:
Resource costs		6,239			6,206
Other operating expenses		20,465			18,081
Depreciation and amortization		1,526			1,479

Total operating expenses		290,938			357,353

Income from operations		23,754			25,332


Other Income (Expense):
Interest expense		(15,435	)		(17,452	)
Interest expense to affiliated trusts		(189	)		(1,445	)
Capitalized interest		298			970
Other income - net		153			7,573

Total other income (expense) - net		(15,173	)		(10,354	)

Income before income taxes		8,581			14,978

Income tax expense (benefit)		(53	)		7,150

Net income		8,634			7,828
Less: Net income attributable to noncontrolling interests		(495	)		(469	)

Net income attributable to Avista Corporation	$	8,139		$	7,359

Weighted-average common shares outstanding (thousands), basic		54,706			53,773
Weighted-average common shares outstanding (thousands), diluted		55,094			54,205
Earnings per common share attributable to Avista Corporation:
Basic	$	0.15		$	0.14

Diluted	$	0.15		$	0.13

Dividends paid per common share	$	0.21		$	0.18

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands, except per share amounts

(Unaudited)


	2009			2008
Operating Revenues:
Utility revenues	$	1,024,978		$	1,152,741
Non-utility energy marketing and trading revenues		18,081			19,068
Other non-utility revenues		66,214			57,493

Total operating revenues		1,109,273			1,229,302

Operating Expenses:
Utility operating expenses:
Resource costs		582,805			746,428
Other operating expenses		170,554			153,353
Depreciation and amortization		69,733			65,379
Taxes other than income taxes		60,661			55,631
Non-utility operating expenses:
Resource costs		17,307			17,661
Other operating expenses		56,273			46,426
Depreciation and amortization		4,259			3,541

Total operating expenses		961,592			1,088,419

Income from operations		147,681			140,883


Other Income (Expense):
Interest expense		(47,183	)		(57,131	)
Interest expense to affiliated trusts		(1,800	)		(4,661	)
Capitalized interest		1,296			2,720
Other income (expense) - net		(617	)		10,477

Total other income (expense) - net		(48,304	)		(48,595	)

Income before income taxes		99,377			92,288

Income tax expense		33,034			35,544

Net income		66,343			56,744
Less: Net income attributable to noncontrolling interests		(1,325	)		(609	)

Net income attributable to Avista Corporation	$	65,018		$	56,135

Weighted-average common shares outstanding (thousands), basic		54,659			53,366
Weighted-average common shares outstanding (thousands), diluted		54,881			53,765

Earnings per common share attributable to Avista Corporation:
Basic	$	1.19		$	1.05

Diluted	$	1.18		$	1.04

Dividends paid per common share	$	0.60		$	0.51

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands

(Unaudited)


	2009			2008
Net income	$	8,634		$	7,828

Other Comprehensive Income:
Change in unfunded benefit obligation for pension plan - net of taxes of $54 and $64 respectively		101			119

Total other comprehensive income		101			119

Comprehensive income		8,735			7,947
Comprehensive income attributable to noncontrolling interests		(495	)		(469	)

Comprehensive income attributable to Avista Corporation	$	8,240		$	7,478


For the Nine Months Ended September 30 Dollars in thousands (Unaudited)

	2009			2008
Net income	$	66,343		$	56,744

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 $162 and $365 respectively		302			678

Total other comprehensive income		302			7,504

Comprehensive income		66,645			64,248
Comprehensive income attributable to noncontrolling interests		(1,325	)		(609	)

Comprehensive income attributable to Avista Corporation	$	65,320		$	63,639

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands

(Unaudited)


	September 30, 2009		December 31, 2008
Assets:
Current Assets:
Cash and cash equivalents	$	35,025	$	24,313
Restricted cash		12,000		—
Accounts and notes receivable - less allowances of $42,002 and $45,062		149,492		218,846
Utility energy commodity derivative assets		8,724		11,234
Regulatory asset for utility derivatives		28,441		60,229
Funds held for customers		51,881		59,095
Materials and supplies, fuel stock and natural gas stored.		42,019		53,526
Deferred income taxes		17,526		18,561
Income taxes receivable		—		22,769
Other current assets		13,313		13,654

Total current assets		358,421		482,227

Net Utility Property:
Utility plant in service		3,487,589		3,343,535
Construction work in progress		60,577		77,487

Total		3,548,166		3,421,022
Less: Accumulated depreciation and amortization		985,484		928,831

Total net utility property		2,562,682		2,492,191

Other Property and Investments:
Investment in exchange power - net		24,296		26,133
Investment in affiliated trusts		11,547		13,403
Goodwill		24,820		21,132
Other property and investments - net		81,030		78,208

Total other property and investments		141,693		138,876

Deferred Charges:
Regulatory assets for deferred income taxes		98,060		115,005
Regulatory assets for pensions and other postretirement benefits		163,634		172,278
Other regulatory assets		82,163		85,112
Non-current utility energy commodity derivative assets		76,600		49,313
Power cost deferrals		37,531		57,607
Unamortized debt expense		30,827		33,004
Other deferred charges		6,369		5,134

Total deferred charges		495,184		517,453

Total assets	$	3,557,980	$	3,630,747

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED BALANCE SHEETS - continued

Avista Corporation

Dollars in thousands

(Unaudited)


	September 30, 2009			December 31, 2008
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	133,135		$	176,116
Customer fund obligations		51,881			59,095
Current portion of long-term debt		27,206			17,207
Short-term borrowings		33,400			252,200
Interest accrued		17,223			10,871
Utility energy commodity derivative liabilities		37,165			71,463
Other current liabilities.		147,269			101,592

Total current liabilities		447,279			688,544

Long-term debt		1,060,951			809,258

Long-term debt to affiliated trusts		51,547			113,403

Other Non-Current Liabilities and Deferred Credits:
Regulatory liability for utility plant retirement costs		216,762			213,747
Non-current regulatory liability for utility derivatives		74,627			42,172
Pensions and other postretirement benefits		144,876			184,588
Deferred income taxes		443,440			488,940
Other non-current liabilities and deferred credits		71,293			82,006

Total other non-current liabilities and deferred credits		950,998			1,011,453

Total liabilities		2,510,775			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; 54,740,806 and 54,487,574 shares outstanding		776,977			774,986
Accumulated other comprehensive loss		(5,790	)		(6,092	)
Retained earnings		264,975			227,989

Total Avista Corporation stockholders’ equity		1,036,162			996,883
Noncontrolling interests		11,043			11,206

Total stockholders’ equity		1,047,205			1,008,089

Total liabilities and stockholders’ equity	$	3,557,980		$	3,630,747

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands

(Unaudited)


	2009			2008
Operating Activities:
Net income	$	66,343		$	56,744
Non-cash items included in net income:
Depreciation and amortization		73,992			68,920
Provision (benefit) for deferred income taxes		(27,798	)		5,748
Power and natural gas cost amortizations, net of deferrals		44,886			31,421
Amortization of debt expense		4,305			3,547
Equity-related AFUDC		(1,600	)		(2,892	)
Other		24,023			16,135
Contributions to defined benefit pension plan		(48,000	)		(28,000	)
Changes in working capital components:
Accounts and notes receivable		76,689			9,336
Materials and supplies, fuel stock and natural gas stored		11,507			(35,557	)
Other current assets		15,238			7,723
Accounts payable		(39,548	)		(8,735	)
Other current liabilities		34,073			7,521

Net cash provided by operating activities		234,110			131,911


Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(141,378	)		(150,071	)
Other capital expenditures		(2,653	)		(2,627	)
Decrease (increase) in restricted cash		(12,000	)		4,068
Decrease (increase) in funds held for customers		8,354			(2,544	)
Repayments received on notes receivable		—			3,010
Purchase of subsidiary minority interest		(4,775	)		(8,574	)
Cash paid by subsidiary for acquisition, net of cash received		(8,572	)		(1,428	)
Other		(1,151	)		4,862

Net cash used in investing activities		(162,175	)		(153,304	)


Financing Activities:
Increase (decrease) in short-term borrowings		(218,800	)		86,500
Proceeds from issuance of long-term debt		249,425			249,165
Redemption and maturity of long-term debt		(194	)		(295,023	)
Redemption of long-term debt to affiliated trusts		(61,856	)		—
Long-term debt and short-term borrowing issuance costs		(2,240	)		(2,346	)
Cash received (paid) in interest rate swap agreement		10,776			(16,395	)
Issuance of common stock		1,592			27,397
Cash dividends paid		(32,836	)		(27,258	)
Increase (decrease) in customer fund obligations		(8,354	)		2,544
Equity transactions of consolidated subsidiaries		1,264			—

Net cash provided by (used in) financing activities		(61,223	)		24,584


Net increase in cash and cash equivalents		10,712			3,191

Cash and cash equivalents at beginning of period		24,313			11,839

Cash and cash equivalents at end of period	$	35,025		$	15,030


Supplemental Cash Flow Information:
Cash paid during the period:
Interest	$	38,326		$	48,642
Income taxes		21,165			28,102
Non-cash financing and investing activities:
Liability to subsidiary minority shareholders		(1,962	)		26,243
Issuance of stock by subsidiary for acquisition		—			37,100

The Accompanying Notes are an Integral Part of These Statements.

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Avista Corporation

For the Nine Months Ended September 30, 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									65,018			65,018			1,325			66,343
Equity compensation expense			1,721									1,721						1,721
Issuance of common stock	253,232		1,592									1,592						1,592
Other comprehensive income						302						302						302
Cash dividends paid									(32,836	)		(32,836	)					(32,836	)
Equity transactions of consolidated subsidiaries			(1,322	)								(1,322	)		(1,141	)		(2,463	)
Liability to subsidiary minority shareholders									4,804			4,804						4,804
Other												—			(347	)		(347	)

Balance as of September 30, 2009	54,740,806	$	776,977		$	(5,790	)	$	264,975		$	1,036,162		$	11,043		$	1,047,205


Balance as of January 1, 2008	52,909,013	$	726,933		$	(19,608	)	$	206,641		$	913,966		$	862		$	914,828

Net income									56,135			56,135			609			56,744
Equity compensation expense			1,880									1,880						1,880
Issuance of common stock	1,513,086		27,397									27,397						27,397
Other comprehensive income						7,504						7,504						7,504
Cash dividends paid									(27,258	)		(27,258	)					(27,258	)
Equity transactions of consolidated subsidiaries			16,988									16,988			9,208			26,196
Liability to subsidiary minority shareholders									(17,960	)		(17,960	)					(17,960	)

Balance as of September 30, 2008	54,422,099	$	773,198		$	(12,104	)	$	217,558		$	978,652		$	10,679		$	989,331

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 September 30, 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 (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Condensed Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These condensed consolidated financial statements do not contain the detail or footnote disclosure concerning accounting policies and other matters which would be included in full fiscal year consolidated financial statements; therefore, they should be read in conjunction with the Company’s audited consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 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. The acronyms and terms are an integral part of these condensed consolidated financial statements.

Accounting Standards Codification

In June 2009, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 168, “The Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162.” This statement replaces all previously issued accounting standards and establishes the FASB Accounting Standards Codification (ASC). The ASC is the single source of authoritative nongovernmental U.S. GAAP and is effective for all interim and annual periods ending after September 15, 2009. All existing accounting standards documents were superseded. All other accounting literature not included in the ASC is considered nonauthoritative. The adoption of the ASC did not have any impact on the Company’s financial condition, results of operations and cash flows, as the ASC did not change existing U.S. GAAP. The adoption of the ASC will only result in changes to the Company’s financial statement disclosure references. In order to facilitate the transition to the ASC, the Company has elected to show references to U.S. GAAP within this report on Form 10-Q prior to the ASC along with a parenthetical ASC reference.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy, as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in Montana and northern Oregon. Avista Utilities also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeast and southwest Oregon. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies in the non-utility businesses including Advantage IQ, Inc. (Advantage IQ), a 74 percent owned subsidiary as of September 30, 2009. 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.

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.

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 $9.9 million and $9.3 million for the three months ended September 30, 2009 and 2008, respectively. These taxes were $44.3 million and $40.9 million for the nine months ended September 30, 2009 and 2008, respectively.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Other Income (expense) - Net

Other income (expense)-net consisted of the following items for the three and nine months ended September 30 (dollars in thousands):


	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
Interest income	$	257		$	1,003		$	1,159		$	2,837
Interest on regulatory deferrals		782			820			2,249			2,960
Interest on income tax settlement		—			5,749			—			5,749
Equity-related Allowance for Funds Used During Construction		368			1,034			1,600			2,892
Income (loss) on investments, net		106			—			(904	)		(94	)
Other expense		(1,368	)		(1,755	)		(4,754	)		(4,853	)
Other income		8			722			33			986

Total other income (expense) - net	$	153		$	7,573		$	(617	)	$	10,477

Income taxes

The Company accounts for income taxes under SFAS No. 109, “Accounting for Income Taxes” (ASC 740). A deferred tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s consolidated income tax returns. The deferred tax expense for the period is equal to the net change in the deferred tax asset and liability accounts from the beginning to the end of the period. The effect on deferred taxes of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax liabilities and regulatory assets are established for tax benefits flowed through to customers as prescribed by the respective regulatory commissions.

The Company and its eligible subsidiaries file consolidated federal income tax returns. An adjustment to reconcile the Company’s 2008 federal income tax return to the amount included in the financial statements for 2008 resulted in a $3.2 million decrease to income tax expense for the three and nine months ended September 30, 2009. This adjustment was larger than normal due to several factors. A number of audit adjustments from a recently finalized Internal Revenue Service (IRS) examination of the 2006 and 2007 federal tax returns, along with certain adjustments related to the 2008 federal income tax return, contributed to the impact, but the largest component was a difference between the pension expense recorded in the 2008 financial statements and the 2008 tax deductible cash contribution to the pension trust fund. A large decline in pension fund assets, driven by the negative 2008 financial market conditions, resulted in a $36 million difference between pension expense recorded in the 2008 financial statements and the tax deduction in the 2008 federal income tax return. The portion of this difference allocated to capital expenditures has historically increased or decreased income tax expense through the annual adjustment to reconcile the federal tax return to the amount included in the financial statements.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the unfunded benefit obligation for pensions and other postretirement benefit plans as of September 30, 2009 and December 31, 2008.

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
Goodwill acquired during the year		4,311			—		4,311
Adjustments		(623	)		—		(623	)

Balance as of the September 30, 2009	$	19,574		$	5,246	$	24,820

The goodwill acquired in 2009 was related to Advantage IQ’s acquisition of substantially all of the assets and liabilities of Ecos Consulting, Inc. (Ecos), a Portland, Oregon-based energy efficiency solutions provider.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Pro forma financial statements reflecting this acquisition are not presented, as the acquisition is not material to the Company’s consolidated financial statements. The adjustment to goodwill (recorded in 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 in 2008 (estimated amortization period of 16 years) and Ecos in 2009 (estimated amortization period of 3 years), software development costs (estimated amortization period of 5 to 7 years) and other. Other Intangibles are included in other property and investments - net on the Condensed Consolidated Balance Sheets. Amortization expense related to Other Intangibles for the three months ended September 30, 2009 and 2008 was $0.5 million and $0.6 million, respectively. Amortization expense related to Other Intangibles for the nine months ended September 30, 2009 and 2008 was $1.5 million and $0.8 million, respectively. The gross carrying amount and accumulated amortization of Other Intangibles as of September 30, 2009 and December 31, 2008 are as follows (dollars in thousands):


	September 30, 2009			December 31, 2008
Client relationships	$	10,259		$	8,909
Software development costs		16,026			14,067
Other		1,371			570

Total other intangibles		27,656			23,546
Less accumulated amortization		(7,245	)		(5,804	)

Total other intangibles - net	$	20,411		$	17,742

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


	2009		2010		2011		2012		2013
Estimated amortization expense	$	933	$	3,622	$	3,279	$	2,921	$	2,348

Regulatory Deferred Charges and Credits

The Company prepares its condensed consolidated financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (ASC 980). The Company prepares its condensed financial statements in accordance with ASC 980 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.

ASC 980 requires the Company to reflect the impact of regulatory decisions in its condensed financial statements. ASC 980 requires that certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be recovered in the future) 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 ASC 980 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,

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

•

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,

•

expenditures for licensing hydroelectric generating facilities, 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).

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.

NOTE 2. NEW ACCOUNTING STANDARDS

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, “Fair Value Measurements” (ASC 820-10) related to its 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 (FSP) No. 157-2, which deferred the effective date for certain portions of ASC 820-10 related to nonrecurring measurements of nonfinancial assets and liabilities. Effective January 1, 2009, the Company adopted those provisions of ASC 820-10. The adoption of the provisions of ASC 820-10 that became effective on January 1, 2008 and 2009, did not have a material impact on the Company’s financial condition, results of operations and cash flows. 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” (ASC 805-10) that replaces previous accounting guidance for business combinations 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 this statement did not have any impact on the Company’s financial condition, results of operations and cash flows.

Effective January 1, 2009, the Company adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (ASC 810-10). This statement amended previous accounting guidance 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 this statement 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 $11.0 million of noncontrolling (minority) interests in equity as of September 30, 2009 and $11.2 million as of December 31, 2008. For each of the three months ended September 30, 2009 and 2008 net income attributable to noncontrolling (minority) interests was $0.5 million. For the nine months ended September 30, 2009 and 2008, net income attributable to noncontrolling (minority) interests was $1.3 million and $0.6 million, respectively. The noncontrolling (minority) interests primarily relate to third party shareholders of Advantage IQ, who own approximately 26 percent as of September 30, 2009.

Effective January 1, 2009, the Company adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (ASC 815-10) that requires disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement requires 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.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (ASC 715-20) that amends FASB Statement No. 132(R) “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (ASC 715-20). 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 this FSP at the end of 2009 and will have expanded disclosures with respect to its pension and other postretirement benefit plan assets.

Effective June 30, 2009, the Company adopted FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (ASC 825-10-65-1) that amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” (ASC 825-10-50) 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,” (ASC 270-10-45-2) to require those disclosures in summarized financial information at interim reporting periods. The Company expanded disclosures with respect to the fair value of financial instruments. See Note 9 for the expanded disclosures.

Effective June 30, 2009, the Company adopted FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (ASC 820-65-10-4) that provides guidance for determining fair values of financial instruments for which there is no active market or when quoted prices may represent distressed transactions. The guidance includes a reaffirmation of the need to use judgment in certain circumstances and requires expanded disclosures surrounding equity and debt securities. The adoption of this FSP did not have an impact on the Company’s financial condition, results of operations and cash flows. See Note 9 for expanded disclosures.

Effective June 30, 2009, the Company adopted SFAS No. 165, “Subsequent Events” (ASC 855-10). This statement established principles and requirements for subsequent events related to: 1) the period after the balance sheet date during which management of a reporting entity shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; 2) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements; and 3) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. The Company evaluated subsequent events up to the filing of this Form 10-Q on October 30, 2009 (the date the financial statements were issued).

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets an amendment of FASB Statement No. 140” (ASC 860). This statement amends certain provisions of SFAS No. 140 (ASC 860) to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows, and a transferor’s continuing involvement in transferred financial assets. The Company will be required to adopt this statement effective January 1, 2010. The Company is evaluating the impact this statement will have on its financial condition, results of operations and cash flows.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (ASC 810). This statement carries forward the scope of FASB Interpretation No. 46(R) (ASC 810), with the addition of entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated in FASB Statement No. 166, “Accounting for Transfers of Financial Assets an amendment of FASB Statement No. 140” (ASC 860). The Company will be required to adopt this statement effective January 1, 2010. The Company is evaluating the impact this statement will have on its financial condition, results of operations and cash flows.

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. Avista Corp., ARC and a third-party financial institution are parties to a Receivables Purchase Agreement, and on March 13, 2009 that agreement was amended to, among other things, extend the termination date to March 12, 2010. Under the Receivables Purchase Agreement, ARC can sell without recourse, and such financial institution will purchase, 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

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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). Based on calculations of eligible receivables, ARC had the ability to sell up to $42.0 million of receivables under this revolving agreement at September 30, 2009 and $85.0 million at December 31, 2008. There were not any accounts receivable sold under this revolving agreement as of September 30, 2009 and $17.0 million as of December 31, 2008.

The Receivables Purchase Agreement requires a receivables report to be prepared monthly, including information related to customer account delinquency ratios. The June 30, 2009 report indicated that one measurement of the delinquency ratios was in excess of the threshold specified in the Receivables Purchase Agreement, triggering an optional liquidation event. An optional liquidation event gives the receivables purchaser the right, at its option, to terminate its obligations to purchase additional receivables from ARC. Avista Corp, ARC and the third-party financial institution executed an amendment to the Receivables Purchase Agreement which waived the occurrence of the liquidation event arising from the customer account delinquency ratio increase reflected in the June 30, 2009 report and made certain other amendments to the Receivables Purchase Agreement, including an increase in the delinquency ratio threshold for the periods to be covered by the July 31, 2009 and August 31, 2009 monthly receivables reports and the modification of certain reporting obligations. As of September 30, 2009, Avista Corp. was in compliance with all covenants including the delinquency ratio threshold as defined in the Receivables Purchase 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.

As part of its resource procurement and management operations in the electric business, Avista Utilities engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve Avista Utilities’ load obligations and 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

•

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

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

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

As part of its resource procurement and management operations in the natural gas business, Avista Utilities makes continuing projections of its natural gas loads and assesses available natural gas resources. 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 unhedged 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 (ASC 815), 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.

The Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (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 ASC 815 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 derivative volumes as of September 30, 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	717	166	11,899	535	551	101	502	—
2010	846	482	18,740	1,210	1,164	—	3,550	—
2011	840	108	8,541	—	725	—	—	—
2012	421	—	3,760	—	342	—	—	—
2013	368	—	1,575	—	286	—	—	—
Thereafter	2,061	—	—	—	1,588	—	—	—

Foreign Currency Exchange Contracts

A significant portion of Avista Utilities’ 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 Avista Utilities’ short-term natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled within sixty days with U.S. dollars. In early 2009, Avista Utilities 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 the Company’s

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 September 30, 2009, the Company had a current derivative asset for foreign currency hedges of $0.1 million included in other current assets on the Condensed Consolidated Balance Sheet. As of September 30, 2009, the Company had entered into 26 Canadian currency forward contracts with a notional amount of $12.0 million ($12.9 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.

In September 2009, the Company cash settled interest rate swap contracts (notional amount of $200.0 million) and received a total of $10.8 million. The interest rate swap contracts were settled concurrently with the issuance of $250.0 million of First Mortgage Bonds (see Note 7). These settlements of the interest rate swaps were deferred as a regulatory liability (included as part of long-term debt) and will be amortized as a component of interest expense over the life of the associated debt issued in accordance with regulatory accounting practices. The Company did not have any interest rate swap contracts outstanding as of September 30, 2009.

Derivative Instruments Summary

The following table presents the fair values and locations of derivative instruments recorded on the Condensed Consolidated Balance Sheet as of September 30, 2009 (in thousands):


		Fair Value
Derivative	Balance Sheet Location	Asset		Liability			Net Asset (Liability)
Foreign currency contracts	Other current assets	$	86		—		$	86
Commodity contracts	Current utility energy commodity derivative assets		11,228		(2,504	)		8,724
Commodity contracts	Non-current utility energy commodity derivative assets		87,922		(11,322	)		76,600
Commodity contracts	Current utility energy commodity derivative liabilities		8,559		(45,724	)		(37,165	)
Commodity contracts	Other non-current liabilities and deferred credits		1,378		(3,351	)		(1,973	)

	Total derivative instruments recorded on the balance sheet	$	109,173	$	(62,901	)	$	46,272

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 September 30, 2009 was $23.6 million. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2009, the Company would be required to post $6.0 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

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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.

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 $3.2 million as of September 30, 2009 and $0.2 million as of 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.

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 $48 million in cash to the pension plan in 2009, $28 million in 2008 and $15 million in each of 2007 and 2006.

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.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 employee’s years of service and the ending salary. The liability and expense of this plan are included as other postretirement benefits.

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

The Company uses a December 31 measurement date for its pension and postretirement plans. The following table sets forth the components of net periodic benefit costs for the three and nine months ended September 30 (dollars in thousands):


	Pension Benefits						Other Post- retirement Benefits
	2009			2008			2009			2008
Three months ended September 30:
Service cost	$	2,624		$	2,552		$	202		$	149
Interest cost		5,443			5,203			593			469
Expected return on plan assets		(4,403	)		(5,274	)		(325	)		(391	)
Transition obligation recognition		—			—			126			126
Amortization of prior service cost		164			164			(37	)		—
Net loss recognition		3,021			800			459			(43	)

Net periodic benefit cost	$	6,849		$	3,445		$	1,018		$	310

Nine months ended September 30:
Service cost	$	7,970		$	7,657		$	606		$	446
Interest cost		16,251			15,609			1,737			1,407
Expected return on plan assets		(12,879	)		(15,822	)		(1,007	)		(1,172	)
Transition obligation recognition		—			—			378			379
Amortization of prior service cost		492			491			(111	)		—
Net loss recognition		7,165			2,559			1,083			201

Net periodic benefit cost	$	18,999		$	10,494		$	2,686		$	1,261

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 borrow or request the issuance of letters of credit in any combination up to $320.0 million. The Company had $25.0 million in borrowings outstanding under this committed line of credit as of September 30, 2009 and $250.0 million as of December 31, 2008. Total letters of credit outstanding were $23.9 million as of September 30, 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 September 30, 2009 and December 31, 2008, the Company 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.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 September 30, 2009, the Company was in compliance with this covenant with a ratio of 4.02 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 September 30, 2009, the Company was in compliance with this covenant with a ratio of 52.8 percent. 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 to the calculations under the Pension Protection Act of 2006. The pension funded ratio covenant was included in the $200.0 million committed line of credit agreement.

Advantage IQ

Advantage IQ has a committed credit agreement with an expiration date of February 2011. On July 1, 2009, the committed amount was increased from $12.5 million to $15.0 million under the terms of the credit agreement. Advantage IQ may elect to increase the credit facility to $25 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $8.4 million of borrowings outstanding under the credit agreement as of September 30, 2009, and $2.2 million as of December 31, 2008.

NOTE 7. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of September 30, 2009 and December 31, 2008 (dollars in thousands):


Maturity Year	Description	Interest Rate	September 30, 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
2022	First Mortgage Bonds (1)	5.13%		250,000			—
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2034	Secured Pollution Control Bonds	(2)		17,000			17,000
2035	First Mortgage Bonds	6.25%		150,000			150,000
2037	First Mortgage Bonds	5.70%		150,000			150,000

	Total secured long-term debt			1,085,000			835,000
2023	Unsecured Pollution Control Bonds	6.00%		4,100			4,100
	Other long-term debt and capital leases			3,089			3,006
	Interest rate swaps			(2,051	)		(14,129	)
	Unamortized debt discount			(1,981	)		(1,512	)

	Total			1,088,157			826,465
	Current portion of long-term debt			(27,206	)		(17,207	)

	Total long-term debt		$	1,060,951		$	809,258

(1)	On September 22, 2009, the Company issued $250.0 million of 5.125 percent First Mortgage Bonds due in 2022.

(2)	Variable interest rate (reset daily) ranged from 0.20 percent to 1.20 percent during the first nine months of 2009. As of September 30, 2009 the variable rate was 0.35 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

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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

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

The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at estimated fair value on the Condensed Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008 (dollars in thousands):


	September 30, 2009				December 31, 2008
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Long-term debt	$	1,089,100	$	1,140,074	$	839,100	$	875,451
Long-term debt to affiliated trusts		51,547		43,515		113,403		102,027

These estimates of fair value were primarily based on available market information.

Energy commodity derivative assets and liabilities, deferred compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are reported at estimated fair value on the Condensed Consolidated Balance Sheets. As disclosed in Note 2, on January 1, 2008, the Company adopted the provisions of ASC 820-10 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 ASC 820-10 related to nonrecurring measurements of nonfinancial assets and liabilities. ASC 820-10 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 ASC 820-10 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.

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.

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

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 September 30, 2009 and December 31, 2008 at fair value on a recurring basis (dollars in thousands):


	Level 1		Level 2		Level 3		Counterparty Netting (1)			Total
September 30, 2009
Assets:
Energy commodity derivatives	$	—	$	23,214	$	88,837	$	(26,727	)	$	85,324
Deferred compensation assets:
Fixed income securities (2)		1,919		—		—		—			1,919
Equity securities (2)		5,816		—		—		—			5,816
Foreign currency derivatives		—		86		—		—			86

Total	$	7,735	$	23,300	$	88,837	$	(26,727	)	$	93,145

Liabilities:
Energy commodity derivatives	$	—	$	55,313	$	10,552	$	(26,727	)	$	39,138


December 31, 2008
Assets:
Energy commodity derivatives	$	—	$	40,104	$	68,047	$	(47,604	)	$	60,547
Deferred compensation assets:
Fixed income securities (2)		1,889		—		—		—			1,889
Equity securities (2)		5,101		—		—		—			5,101
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

(1)	FIN 39, “Offsetting of Amounts Related to Certain Contracts – an interpretation of APB No. 10 and FASB Statement No. 105” (ASC 210-20) permits the netting of derivative assets and derivative liabilities when a legally enforceable master netting agreement exists.

(2)	These assets are trading securities.

Avista Utilities enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of Avista Utilities’ management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Condensed Consolidated Balance Sheets is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange (NYMEX) pricing for similar instruments, adjusted for basin differences, 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.

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 September 30, 2009 and December 31, 2008.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

The following table presents activity for energy commodity derivative assets measured at fair value using significant unobservable inputs for the three and nine months ended September 30 (dollars in thousands):


	Three months ended September 30,					Nine months ended September 30,
	2009		2008			2009			2008
Balance as of beginning of the period	$	60,569	$	150,971		$	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)		28,268		(21,454	)		21,942			35,556
Purchases, issuances, and settlements, net		—		—			(1,152	)		(4,982	)
Transfers to other categories		—		—			—			—

Ending balance as of September 30	$	88,837	$	129,517		$	88,837		$	129,517

The following table presents activity for energy commodity derivative liabilities measured at fair value using significant unobservable inputs for the three and nine months ended September 30 (dollars in thousands):


	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
Balance as of beginning of the period	$	14,040		$	20,310		$	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)		(3,487	)		645			(5,003	)		(13,848	)
Purchases, issuances, and settlements, net		(1	)		(2	)		(530	)		(1,705	)
Transfers to other categories		—			—			—			—

Ending balance as of September 30	$	10,552		$	20,953		$	10,552		$	20,953

(1)

The WUTC and the IPUC issued accounting orders authorizing Avista Utilities to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility derivative commodity instruments in the Condensed Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in annual adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases.

NOTE 10. EARNINGS PER COMMON SHARE

The following table presents the computation of basic and diluted earnings per common share for the three and nine months ended September 30 (in thousands, except per share amounts):


	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
Numerator:
Net income attributable to Avista Corporation	$	8,139		$	7,359		$	65,018		$	56,135
Subsidiary earnings adjustment for dilutive securities		(31	)		(61	)		(84	)		(212	)

Adjusted net income attributable to Avista Corporation for computation of diluted earnings per common share	$	8,108		$	7,298		$	64,934		$	55,923

Denominator:
Weighted-average number of common shares outstanding-basic		54,706			53,773			54,659			53,366
Effect of dilutive securities:
Contingent stock awards		288			267			140			197
Stock options		100			165			82			202

Weighted-average number of common shares outstanding-diluted		55,094			54,205			54,881			53,765

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)


	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
Earnings per common share attributable to Avista Corporation:
Total earnings per common share, basic	$	0.15	$	0.14	$	1.19	$	1.05

Total earnings per common share, diluted	$	0.15	$	0.13	$	1.18	$	1.04

Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 229,650 for the three and nine months ended September 30, 2009, and 291,550 for the three and nine months ended September 30, 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

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

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

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

California Refund Proceeding

In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for purchases made in the spot markets operated by the CalISO and the CalPX during the period from October 2, 2000 to June 20, 2001 (Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices (MMCP) for each hour. The FERC ruled that if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may document these costs and limit their refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim pursuant to

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

the FERC’s August 2005 order. That filing was accepted in orders issued by the FERC in January 2006 and November 2006. In June 2009, the FERC reversed, in part, its previous decision and ordered a compliance filing requiring an adjustment to the return on investment component of Avista Energy’s cost filing. That compliance filing was made in July 2009.

The CalISO continues to work on its compliance filing for the Refund Period, which will show “who owes what to whom.” In May 2009, the CalISO filed its 43rd 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). Once the FERC rules on several open issues, the CalISO states that it 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. After completing these calculations, the CalISO states that it intends to make a compliance filing with the FERC that presents the final financial position of each party that participated in its markets during the Refund Period.

The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CalPX. As a result, Avista Energy has not been paid for all of its energy sales during the Refund Period. Those funds are now in escrow accounts and will not be released until the FERC issues an order directing such release in the California refund proceeding. As of September 30, 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.

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

In September 2005, the Ninth Circuit held that the FERC did not have the authority to order refunds for sales made by municipal utilities in the California refund proceeding. In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 refund proceeding, but remanded to the FERC its decision not to consider an FPA section 309 remedy for tariff violations prior to that date. Petitions for rehearing were denied in April 2009. In July 2009, Avista Energy and Avista Utilities filed a motion at the FERC, asking that the companies be dismissed from any further proceedings arising under section 309 pursuant to the remand. The filing pointed out that section 309 relief is based on tariff violations of the seller, and as to Avista Energy and Avista Utilities, these allegations had already been fully adjudicated in the proceeding that gave rise to the Agreement in Resolution, discussed above. There, the FERC absolved both companies of all allegations of market manipulation or wrongdoing that would justify or permit FPA sections 206 or 309 remedies during 2000 and 2001. The Company’s July 2009 motion and various other motions filed in this proceeding remain pending before the FERC.

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

Pacific Northwest Refund Proceeding

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

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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

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 (the “Lockyer Complaint”)

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

In March 2008, the FERC issued an order establishing a trial-type hearing to address “whether any individual public utility seller’s violation of the 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 California AG, CPUC, PG&E, and SCE filed their testimony in July 2009. Avista Energy’s answering testimony was filed in September 2009. On the same day, the FERC staff filed its answering testimony taking the position that, using the test the FERC directed to be applied in this proceeding, Avista Energy does not have market power. Cross answering testimony and rebuttal testimony are due in November 2009. A hearing is expected to commence in February 2010.

Based on information currently known to the Company’s management and the fact that neither Avista Utilities nor Avista Energy ever reached a 20 percent generation market share during 2000 or 2001, 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

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

damages, attorney’s fees, an order by the court to remove certain ponds, and the forfeiture of profits earned from the generation of Colstrip. The trial is set to begin in May 2011. 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.

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 $1.4 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.

Lake Coeur d’Alene

In July 1998, the United States District Court for the District of Idaho issued its finding that the Coeur d’ Alene Tribe (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 the use of the Tribe’s reservation lands under Section 10(e) of the Federal Power Act (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).

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 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 the 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 the 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 Reservation Trust Restoration Fund (the Trust Fund). Annual payments from the Company to the Trust Fund for protection, mitigation and enhancement measurements commenced with the issuance of the new FERC license in June 2009 and total $100 million over the 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. In June 2009, Avista Corp. entered into an all-party settlement stipulation with respect to its general rate case that was filed with the IPUC in January 2009. This settlement stipulation, which included the recovery of amounts paid to the Tribe, the Trust Fund or related to the licensing of Avista Corp.’s hydroelectric generating facilities, was approved by the IPUC in July 2009.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

In December 2008, as part of the settlement of the Company’s general rate case, the WUTC approved deferral of the Washington 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.

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 December 2008 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.” A decision is not expected until later in 2009 or early 2010. The court will either affirm the decision of the WUTC in its entirety or reverse the decision, in whole or in part, and possibly remand the matter back to the WUTC for further consideration, which could possibly result in small refunds to customers (for certain amounts collected in rates since January 1, 2009) and regulatory disallowance of the Washington portion, approximately $25.2 million (the amount to be collected through future rates), 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. Five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls, which have a total present capability of 144.1 MW) are under one FERC license and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The FERC issued a new single 50-year license for the Spokane River Project on June 18, 2009.

The license incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the DOI and the Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality Certifications and in the amended Washington 401 Water Quality Certification. Various issues that were appealed under the Washington 401 Water Quality Certification were subsequently resolved through settlement.

As part of the Settlement Agreement with the Washington Department of Ecology (DOE), the Company is currently engaged with the DOE and the EPA Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. Once the Company’s level of responsibility related to low dissolved oxygen in Lake Spokane is established, the Company will identify potential mitigation measures and associated cost estimates. It is not possible to provide cost estimates at this time because the TMDL process is not complete. It is also possible the TMDL will be appealed by one or more parties following the EPA’s approval later this year.

The Company has begun implementing the environmental and operational conditions required in the license for the Spokane River Project. The estimated cost to implement the license conditions for the five hydroelectric plants is $334 million over the next 50 years. This will increase the Spokane River Project’s cost of power by about 40 percent, while decreasing annual generation by only a half of one percent. Costs to implement mitigation measures related to the TMDL are not included in these cost estimates.

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 Public Counsel Section of the Washington Attorney General’s Office filed a Petition for Judicial Review of the WUTC’s December 2008 order approving the settlement of the Company’s Washington general rate case, which included the costs related to settlement with the Tribe. Refer to the Lake Coeur d’Alene disclosure included above for further details. The WUTC approved deferred accounting treatment, with a carrying cost, until these costs are reflected in future retail rates. The Company’s Washington general rate case, filed in January 2009, reflects recovery of both the direct and deferred costs. The IPUC has approved the recovery of relicensing costs through the general rate case settlement that was implemented on August 1, 2009. 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.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Clark Fork Settlement Agreement

Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. 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 provided for the opening and modification of existing diversion tunnels built when Cabinet Gorge was originally constructed. The Company performed physical and computer modeling studies to confirm the feasibility and likely effectiveness of the tunnel solution. Analysis of the predicted total dissolved gas performance indicated that the tunnels would 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 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 current results, that the plant will be able to comply with the Montana law without utilizing the temporary alternate emission limit provision. Current estimates indicate that the Company’s share of installation capital costs will be $1.4 million and annual operating costs will increase by $1.5 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.

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 at 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 work in April 2009 pursuant to an Agreed Order issued by the EPA. The Company completed the terms of the Agreed Order issued by the EPA in April 2009. The Company expensed $1.5 million related to the cleanup during 2009. The Company was assessed a penalty by the EPA, which was not material to its results of operations, financial condition or cash flows.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

Aluminum Recycling Site

In October 2009, the Company (through its subsidiary Pentzer Corporation) received notice from the DOE proposing to find Pentzer liable for a release of hazardous substances under the Model Toxics Control Act (MTCA), under Washington state law. The subject property adjoins land owned by the Union Pacific Railroad (UPR). UPR leased their property to operators of a facility designated by DOE as “Aluminum Recycling – Trentwood.” Operators of that property maintained piles of aluminum “black dross,” which can be designated as a state-only dangerous waste in Washington State. Operators placed a portion of the aluminum dross pile on the site owned by Pentzer Corporation. The Company does not believe it is a contributor to any environmental contamination associated with the dross pile, and is preparing a response to the DOE’s proposed findings. There is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred.

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 have changed the Company’s organization to a holding company structure.

Subsequently, Avista Corp. received approval from the FERC, conditioned on approval by the state regulatory agencies. The Company also received approval from the WUTC and the IPUC, having reached agreement with staffs of those commissions and other parties, as to the terms of various proposed financial and other conditions and commitments on the part of the Company and the proposed new holding company. The Company was unable, however, to reach agreement on acceptable terms and conditions with interested parties in proceedings before the Public Utility Commission of Oregon (OPUC).

At its August 2009 meeting, Avista Corp.’s Board of Directors concluded that the conditions and commitments proposed by the OPUC staff would present risks and uncertainties related to the future issuance of equity capital such that it would not be in the best interests of the Company’s shareholders, or the Company’s customers, to accept such conditions. Therefore, the Board of Directors abandoned the plan of share exchange and related transactions.

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.

AVISTA CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)—(Continued)

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 September 30, 2009:
Operating revenues	$	284,249		$	19,727	$	10,716		$	30,443	$	—		$	314,692
Resource costs		167,462			—		6,239			6,239		—			173,701
Other operating expenses		55,332			15,455		5,010			20,465		—			75,797
Depreciation and amortization		23,630			1,197		329			1,526		—			25,156
Income (loss) from operations		21,541			3,075		(862	)		2,213		—			23,754
Interest expense (2)		15,623			46		13			59		(58	)		15,624
Income tax expense (benefit)		(857	)		1,097		(293	)		804		—			(53	)
Net income (loss) attributable to
Avista Corporation		7,239			1,413		(513	)		900		—			8,139
Capital expenditures		53,478			996		17			1,013		—			54,491
For the three months ended September 30, 2008:
Operating revenues	$	353,824		$	16,822	$	12,039		$	28,861	$	—		$	382,685
Resource costs		245,127			—		6,206			6,206		—			251,333
Other operating expenses		49,114			12,878		5,203			18,081		—			67,195
Depreciation and amortization		22,023			1,072		407			1,479		—			23,502
Income from operations		22,237			2,872		223			3,095		—			25,332
Interest expense (2)		18,847			27		45			72		(22	)		18,897
Income tax expense		5,542			1,007		601			1,608		—			7,150
Net income (loss) attributable to
Avista Corporation		6,451			1,340		(432	)		908		—			7,359
Capital expenditures		59,199			498		80			578		—			59,777
For the nine months ended September 30, 2009:
Operating revenues	$	1,024,978		$	55,113	$	29,182		$	84,295	$	—		$	1,109,273
Resource costs		582,805			—		17,307			17,307		—			600,112
Other operating expenses		170,554			43,387		12,886			56,273		—			226,827
Depreciation and amortization		69,733			3,264		995			4,259		—			73,992
Income (loss) from operations		141,225			8,462		(2,006	)		6,456		—			147,681
Interest expense (2)		48,845			182		86			268		(130	)		48,983
Income tax expense (benefit)		31,093			2,973		(1,032	)		1,941		—			33,034
Net income (loss) attributable to
Avista Corporation		63,203			3,855		(2,040	)		1,815		—			65,018
Capital expenditures		141,378			2,628		25			2,653		—			144,031
For the nine months ended September 30, 2008:
Operating revenues	$	1,152,741		$	41,743	$	34,818		$	76,561	$	—		$	1,229,302
Resource costs		746,428			—		17,661			17,661		—			764,089
Other operating expenses		153,353			30,968		15,458			46,426		—			199,779
Depreciation and amortization		65,379			2,335		1,206			3,541		—			68,920
Income from operations		131,950			8,440		493			8,933		—			140,883
Interest expense (2)		61,619			82		143			225		(52	)		61,792
Income tax expense		31,922			3,070		552			3,622		—			35,544
Net income (loss) attributable to
Avista Corporation		51,791			4,685		(341	)		4,344		—			56,135
Capital expenditures		150,071			2,452		175			2,627		—			152,698
Total Assets:
As of September 30, 2009	$	3,348,282		$	144,152	$	65,546		$	209,698	$	—		$	3,557,980
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 September 30, 2009, and the related condensed consolidated statements of income and of comprehensive income for the three-month and nine-month periods ended September 30, 2009 and 2008, and of stockholders’ equity and cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Corporation’s management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Avista Corporation and subsidiaries as of December 31, 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 (Accounting Standards Codification 810-10, Consolidation) (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

October 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:

•

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;

•

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;

•

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;

•

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 and investments, and delay in the recovery of ownership and operating costs;

•

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;

•

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;

•

the outcome of legal proceedings and other contingencies;

•

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

•

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

•

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

•

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;

•

blackouts or disruptions of interconnected transmission systems;

•

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

•

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

•

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

•

the loss of significant customers and/or suppliers;

•

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

•

deterioration in the creditworthiness of our customers and counterparties;

•

the effect of any potential decline in our credit ratings;

•

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;

•

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;

•

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

•

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

•

changes in tax rates and/or policies; and

•

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

Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, 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. A security rating is not a recommendation to buy, sell or hold securities. Each security rating is subject to revision or withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be considered independently of all other ratings.

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

Business Segments

We have two reportable business segments as follows:

•

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.

•

Advantage IQ – an indirect subsidiary of Avista Corp. (approximately 74 percent owned as of September 30, 2009) that provides sustainable utility expense management solutions, partnering with multi-site companies across North America to assess and manage utility costs and usage. Advantage IQ’s primary product lines include processing, payment and auditing of energy, telecom, waste, water/sewer and lease bills as well as strategic management services.

We have other businesses, including sheet metal fabrication, venture fund investments and real estate investments, as well as certain natural gas storage facilities and a power purchase agreement held by Avista Energy. These activities do not represent a reportable business segment and are conducted by various indirect subsidiaries of Avista Corp., including Advanced Manufacturing and Development (AM&D), doing business as METALfx.

AVISTA CORPORATION

Advantage IQ, Avista Energy, and various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital) which is a direct, wholly owned subsidiary of Avista Corp. Our total Avista Corporation stockholders’ equity was $1,036.2 million as of September 30, 2009, of which $83.1 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 and nine months ended September 30 (dollars in thousands):


	Three months ended September 30,						Nine months ended September 30,
	2009			2008			2009			2008
Avista Utilities	$	7,239		$	6,451		$	63,203		$	51,791
Advantage IQ		1,413			1,340			3,855			4,685
Other		(513	)		(432	)		(2,040	)		(341	)

Net income attributable to Avista Corporation	$	8,139		$	7,359		$	65,018		$	56,135

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 $8.1 million for the three months ended September 30, 2009, an increase from $7.4 million for the three months ended September 30, 2008. This increase was primarily due to increased earnings at Avista Utilities (primarily due to the implementation of general rate increases in Washington and Idaho) as well as a decrease in interest expense and income tax expense (due to adjustments related to Internal Revenue Service (IRS) audits and adjustments for the 2008 filed federal tax return). This change was partially offset by an increase in other operating expenses and interest income from an income tax settlement in the third quarter of 2008. Our net income was $65.0 million for the nine months ended September 30, 2009, an increase from $56.1 million for the nine months ended September 30, 2008. Consistent with the quarterly increase, this was primarily due to increased earnings at Avista Utilities as well as a decrease in interest expense and income tax expense.

In late 2007, early 2008, and early 2009, respectively, Moody’s Investors Service, Standard & Poor’s and Fitch Ratings, Inc. upgraded our credit ratings, which resulted in an investment grade rating for our senior unsecured debt and corporate rating from each of these rating agencies. The upgrades reflected several steps taken over the past few years to lower our business risk profile and improve financial metrics. Moody’s Investors Service and Standard & Poor’s changed our rating outlook to “Positive” from “Stable” in August 2009. For further discussion of our credit ratings, see pages 56-57. It is important to note that we are at the lower end of the investment grade category. We are working to continuously strengthen our credit ratings by improving earnings and operating cash flows, controlling costs and reducing our debt ratio.

Employment has declined throughout our service area due to cutbacks in the construction, forest products, mining and manufacturing sectors. Non-farm employment contraction for September 2009 as compared to September 2008 was 5.1 percent in Spokane, Washington, 4.7 percent in Medford, Oregon and 6.2 percent in Coeur d’Alene, Idaho, compared to the national average decline of 4.2 percent. Unemployment rates are much higher than a year ago in our service areas. Unemployment rates for September 2009 were 8.4 percent in Spokane, Washington, 10.4 percent in Coeur d’Alene, Idaho and 11.5 percent in Medford, Oregon, compared to the national average of 9.5 percent. The housing market in Coeur d’Alene, Idaho and Medford, Oregon has continued to deteriorate; the September 2009 monthly foreclosure rate was 0.48 percent in Kootenai County (the county that includes Coeur d’Alene, Idaho), and 0.28 percent in Jackson County (the county that includes Medford, Oregon) compared to the national foreclosure rate of 0.27 percent; the housing market in Spokane County remains stable with 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:

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weather conditions,

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

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the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand,

AVISTA CORPORATION

•

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, and

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

Our utility net income was $7.2 million for the three months ended September 30, 2009, an increase from $6.5 million for the three months ended September 30, 2008. Our utility net income was $63.2 million for the nine months ended September 30, 2009, an increase from $51.8 million for the nine months ended September 30, 2008. The increase in our quarterly and year-to-date net income was due in part 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. We recognized an expense of $2.0 million under the ERM for the third quarter of 2009 compared to a benefit of $0.1 million in the third quarter of 2008. We recognized an expense of $6.1 million under the ERM for the nine months ended September 30, 2009 compared to an expense of $7.3 million for the nine months ended September 30, 2008. The increase in net income was also due to a decrease in interest expense and income tax expense. In the third quarter of 2009, we recognized adjustments related to IRS audits and adjustments for the 2008 filed federal tax return. In total, these adjustments had a favorable impact to recorded income tax expense of $3.2 million. These positive impacts on net income were partially offset by an increase in other operating expenses, depreciation and amortization and taxes other than income taxes. In addition, in the third quarter of 2008 we recorded $5.7 million (pre-tax) of interest income, partially offset by $1.4 million (pre-tax) of interest expense, related to income tax settlements.

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 $141.4 million for the nine months ended September 30, 2009. We expect utility capital expenditures to be approximately $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 $1.4 million for the three months ended September 30, 2009, an increase from $1.3 million for the three months ended September 30, 2008. Advantage IQ’s net income attributable to Avista Corporation was $3.9 million for the nine months ended September 30, 2009, a decrease from $4.7 million for the nine months ended September 30, 2008. The decrease for the nine months ended September 30, 2009 as compared to 2008 was primarily due to lower short-term interest rates (which decreases interest revenue), the decrease in our ownership percentage in the business in connection with the acquisition of Cadence Network effective July 2, 2008 and increased amortization of intangible assets (related to the Cadence acquisition – refer to the Cadence discussion below). During 2009, we are experiencing slower internal growth at Advantage IQ than was originally expected, as some of its clients are experiencing bankruptcies and store closures in these difficult economic times. Additionally, interest revenue is lower in 2009 due to the historic low short-term interest rate environment that we are experiencing, which is expected to continue in the fourth quarter of 2009.

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

Effective July 2, 2008, Advantage IQ acquired Cadence Network, a Cincinnati, Ohio-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock, which is subject to redemption. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to 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.

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

AVISTA CORPORATION

Other Businesses

The net loss attributable to Avista Corporation for these operations was $0.5 million for the three months ended September 30, 2009 compared to $0.4 million for the three months ended September 30, 2008. The net loss attributable to Avista Corporation for these operations was $2.0 million for the nine months ended September 30, 2009 compared to $0.3 million for the nine months ended September 30, 2008. Contributing to the net loss attributable to Avista Corporation for the nine months ended September 30, 2009 were losses on long-term venture fund investments of $0.9 million and the accrual of a $0.3 million environmental liability for the final cleanup of a waste water treatment plant site that was decommissioned in 1993. AM&D had a net loss of $0.1 million for the nine months ended September 30, 2009 compared to net income of $0.5 million for the nine months ended September 30, 2008. Results from AM&D improved in the third quarter of 2009 as compared to the first and second quarters of 2009 with net income of $0.1 million.

Liquidity and Capital Resources

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

We have a committed line of credit in the total amount of $320.0 million with an expiration date of April 5, 2011. Under this committed line of credit, we had $25.0 million of cash borrowings and $23.9 million in letters of credit outstanding as of September 30, 2009. 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 are in the process of renewing this credit facility at a reduced level (not expected to exceed $100.0 million). 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 of our eligible accounts receivable under this agreement, we had the ability to sell up to $42.0 million as of September 30, 2009. There were not any accounts receivable sold under this facility as of September 30, 2009.

As of September 30, 2009, we had a combined $513.1 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.

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

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 expect net cash flows from operating activities and our committed line of credit agreements to provide adequate resources to fund:

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capital expenditures,

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dividends, and

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other contractual commitments.

AVISTA CORPORATION

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 for the remainder of 2009, other than for compensatory plans and the direct stock purchase and dividend reinvestment plan.

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. We are planning to issue long-term debt and common stock in 2010 in order to maintain our capital structure at an appropriate level for our business.

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

Avista 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

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more closely align earned returns with those allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, but are not limited to, in-service dates of major capital investments and the timing of changes in major revenue and expense items. We are planning to file new general rate cases in all three states in the first half of 2010 to more closely align earned returns with those authorized by regulators.

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	August 2009	8.55	%	10.5	%	50	%
Oregon natural gas	November 2009	8.19	%	10.1	%	50	%

Washington General Rate Cases

In September 2008, we entered into a settlement stipulation in our general rate case that was filed with the WUTC in March 2008. 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.

AVISTA CORPORATION

On January 27, 2009, Public Counsel filed a Petition for Judicial Review (in Thurston County Superior Court) of the WUTC’s December 2008 order approving our multiparty settlement. Public Counsel raised a number of issues that were previously argued before the WUTC. These 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. A decision is not expected until later in 2009 or early 2010. The court will either affirm the decision of the WUTC in its entirety or reverse the decision, in whole or in part, and possibly remand the matter back to the WUTC for further consideration, which could possibly result in small refunds to customers (for certain amounts collected in rates since January 1, 2009) and regulatory disallowance of the Washington portion, approximately $25.2 million (the amount to be collected through future rates), 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 September 2009, we reached a partial settlement stipulation in our electric and natural gas general rate cases that were filed with the WUTC in January 2009. Other parties to the partial settlement stipulation include the WUTC Staff, the Public Counsel Section of the Washington Office of Attorney General, the Industrial Customers of Northwest Utilities, the Northwest Industrial Gas Users, and The Energy Project. The NW Energy Coalition does not oppose the agreement. The partial settlement stipulation is not binding on the WUTC and is subject to approval by the WUTC.

Under the partial settlement stipulation, we reached agreement with the other settling parties on issues in the areas of cost of capital, power supply, rate spread and rate design, and funding under the Low-Income Ratepayer Assistance Program. Issues in the cases that remain unresolved include, among others, the prudence and timing of the addition of the power purchase agreement for the Lancaster Plant (in 2010), capital additions to rate base, labor costs, tree trimming costs, information systems costs, and the proposed continuation of the natural gas decoupling mechanism. Those issues that were not resolved through the partial settlement stipulation are being addressed in further regulatory proceedings before the WUTC.

Our revised rate increase requests, following execution of the partial settlement stipulation, are designed to increase annual electric revenues by approximately $37 million and annual natural gas revenues by approximately $3 million. Our original request in January 2009 was designed to increase annual base electric service revenues by $69.8 million and increase annual natural gas service revenues by $4.9 million. A decision on our proposed rate requests is expected in December 2009.

The cost of natural gas to generate electricity is a major component of the costs included in the rate request we filed in January 2009. Since our filing, prices for natural gas have decreased substantially, and this reduction in natural gas costs is reflected in the partial settlement stipulation.

The partial settlement stipulation is based on an overall rate of return of 8.25 percent with a common equity ratio of 46.5 percent and a 10.2 percent return on equity. Our original request was based on a proposed overall rate of return of 8.68 percent with a common equity ratio of 47.5 percent and an 11.0 percent return on equity.

Idaho General Rate Cases

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

In June 2009, we entered into an all-party settlement stipulation in our electric and natural gas general rate cases that were filed with the IPUC in January 2009. This settlement stipulation was approved by the IPUC in July 2009. The new electric and natural gas rates became effective on August 1, 2009. As agreed to in the settlement, base electric rates for our Idaho customers increased by an average of 5.7 percent, which is designed to increase annual revenues by $12.5 million. Offsetting the base electric rate increase was an overall 4.2 percent decrease in the current Power Cost Adjustment (PCA) surcharge, which is designed to decrease annual PCA revenues by $9.3 million, resulting in

AVISTA CORPORATION

a net increase in annual revenues of $3.2 million. Base natural gas rates for our Idaho customers increased by an average of 2.1 percent, which is designed to increase annual revenues by $1.9 million. Offsetting the natural gas rate increase for residential customers was an equivalent purchased gas adjustment (PGA) decrease of 2.1 percent. Large general services received a PGA decrease of 2.4 percent and interruptible services received a PGA decrease of 2.8 percent. The overall PGA decrease resulted in a $2.0 million decrease in annual PGA revenues, resulting in a net decrease in annual revenues of $0.1 million. The PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin or net income.

Our January 2009 request was for an electric rate increase of 12.8 percent, which was designed to increase annual revenues by $31.2 million. Offsetting the electric rates increase was a decrease in the PCA surcharge of 5.0 percent, which was designed to decrease annual revenues by $12.3 million. We also requested to increase natural gas rates by an average of 3.0 percent, which was designed to increase annual revenues by $2.7 million.

The settlement was based on a rate of return of 8.55 percent with a common equity ratio of 50.0 percent and a 10.5 percent return on equity. Our January 2009 request was based on a rate of return of 8.8 percent with a common equity ratio of 50.0 percent and an 11.0 percent return on equity.

Oregon General Rate Cases

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

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

The settlement is based on a rate of return of 8.19 percent with a common equity ratio of 50.0 percent and a 10.1 percent return on equity. Our June 2009 request was based on a proposed rate of return on rate base of 8.96 percent, with a common equity ratio of 51.5 percent and an 11.0 percent return on equity.

Purchased Gas Adjustments

Effective June 1, 2009, natural gas rates decreased 6.7 percent and effective August 1, 2009 rates decreased 2.1 percent in Idaho. Effective June 1, 2009, natural gas rates decreased 8.1 percent in Washington. Effective November 1, 2009, natural gas rates will decrease 22 percent in Oregon, 26 percent in Washington and 23 percent in Idaho. PGAs are designed to pass through changes in natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, we absorb (gain or loss) 10 percent of the difference between actual and projected gas costs for unhedged supply. Total net deferred natural gas costs were a liability of $43.1 million as of September 30, 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.

In February 2008, we reached a settlement stipulation for the refund liability in 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 2009, the OPUC approved a settlement stipulation in our general rate case that also resolves the refund liability for the 2007 tax report The approved settlement provides for a refund of $2.4 million, including interest, over a two-month period, November and December of 2009. This refund is approximately equal to the new revenue from the general rate increase for this period.

AVISTA CORPORATION

In October 2009, we filed the tax report for 2008 showing taxes paid to be less than taxes collected by $0.9 million before interest. The tax report will be reviewed by the OPUC, a procedural schedule will be established, and a determination of the final level of refund will be made. We are recording a potential refund liability for the 2009 tax report of $0.8 million.

Natural Gas Decoupling

In January 2007, the WUTC approved the implementation of a natural gas decoupling mechanism. 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 a portion of 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 rate adjustment in any one year is limited to no more than 2 percent. On August 31, 2009, we filed for the final rate adjustment under the pilot mechanism. This rate adjustment is designed to recover $0.7 million from Washington residential and small commercial customers over a twelve-month period, effective November 1, 2009. This amount reflects 90 percent of the lost margin during the period July 2008 through June 2009.

The decoupling mechanism was a two and one half year pilot that began in January 2007. We filed a request with the WUTC on April 30, 2009 to: 1) continue the natural gas decoupling mechanism on a permanent basis and 2) temporarily extend the mechanism beyond the end of the pilot period (June 30, 2009) until the WUTC decides whether or not to extend it on a permanent basis. On June 30, 2009, the WUTC issued an order granting the temporary extension. As part of the general rate case filing made earlier this year, the WUTC will evaluate the results of the mechanism and decide on its continuance by the end of 2009. Issues with respect to the natural gas decoupling mechanism were not resolved in the September 2009 partial settlement stipulation in our general rate case filing.

Power Cost Deferrals and Recovery Mechanisms

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

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

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

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the level of hydroelectric generation,

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

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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	%

AVISTA CORPORATION

Under the ERM, we make an annual filing on or before April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. In July 2009, the WUTC issued an order, which approved the recovery of power cost deferrals under the ERM for 2008. 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.

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

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

The following table shows activity in deferred power costs for Washington and Idaho during the nine months ended September 30, 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 – September 30, 2009:
Power costs deferred		2,131			15,508			17,639
Interest and other net additions		775			278			1,053
Recovery of deferred power costs through retail rates		(24,181	)		(14,587	)		(38,768	)

Deferred power costs as of September 30, 2009	$	15,677		$	21,854		$	37,531

Public Utility Regulatory Policy Act

In March 2009, the IPUC 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 four new requests for PURPA contracts, bringing the total requested contracts to five. 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 and nine months ended September 30, 2009 as compared to the three and nine months ended September 30, 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.

Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Utility revenues decreased $69.6 million to $284.2 million due to decreased natural gas revenues of $50.0 million and decreased electric revenues of $19.6 million. The decrease in natural gas revenues was primarily the result of decreased wholesale revenues of $47.5 million (due to decreased prices, offset by increased volumes) and retail natural gas revenues of $3.3 million (due to decreased volumes and prices). The decrease in electric revenues was primarily due to a decrease in wholesale revenues of $26.6 million and sales of fuel of $12.2 million, partially offset by increased retail revenues of $19.7 million (primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increases implemented on August 1, 2009 and October 1, 2008).

AVISTA CORPORATION

Non-utility energy marketing and trading revenues decreased $0.3 million to $6.5 million. These revenues primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. We expect that these rights and obligations will be transferred to our regulated utility in 2010, subject to future approval by the WUTC (the IPUC has approved the transfer and recovery of the costs).

Other non-utility revenues increased $1.9 million to $24.0 million as a result of an increase in revenues from Advantage IQ of $2.9 million primarily due to customer growth and the acquisition of Ecos in third quarter of 2009, partially offset by a decrease in interest earnings on funds held for customers (due to lower interest rates). The increase in revenues at Advantage IQ was partially offset by decreased revenues from our other businesses of $1.0 million, primarily due to decreased sales at AM&D.

Utility resource costs decreased $77.7 million due to decreases in natural gas resource costs of $50.4 million and electric resource costs of $27.2 million. The decrease in natural gas resource costs primarily reflects a decrease in the price of natural gas purchases, partially offset by an increase in the volume of natural gas purchased. The decrease in electric resource costs was due to decreased fuel costs and resource optimization activities.

Utility other operating expenses increased $6.2 million due to an increase of $3.1 million in electric generation operating and maintenance expenses, as well as a $3.2 million increase in pension and other post-retirement benefit costs.

Utility depreciation and amortization increased $1.6 million primarily due to additions to utility plant.

The net change in other non-utility operating expenses was an increase of $2.4 million due to an increase of $2.6 million for Advantage IQ due to expanding operations and the acquisition of Ecos in the third quarter of 2009. The increase in expenses at Advantage IQ was partially offset by decreased operating expenses from our other businesses, primarily AM&D.

Interest expense decreased $2.0 million due to $1.4 million in interest expense recorded for an income tax settlement during the third quarter of 2008 and 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.

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

Other income-net decreased $7.4 million due in part to a decrease in interest income (primarily due to $5.7 million of interest income recorded on the IRS settlement agreement in the third quarter of 2008).

Income taxes decreased $7.2 million due to decreased income before income taxes and adjustments related to IRS audits and adjustments for the 2008 filed federal tax return. In total, these adjustments had a favorable impact to recorded tax expense of $3.2 million (Avista Utilities). See “Income Taxes” in Note 1 of the Notes to Consolidated Financial Statements for further information.

Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Utility revenues decreased $127.8 million to $1,025.0 million due to decreased natural gas revenues of $127.2 million and decreased electric revenues of $0.6 million. The decrease in natural gas revenues was primarily the result of decreased wholesale revenues of $112.2 million (due to decreased prices, offset by increased volumes) and retail natural gas revenues of $17.0 million (primarily due to decreased volumes). The decrease in electric revenues was primarily due to decreases in wholesale revenues of $44.2 million and sales of fuel of $11.0 million, partially offset by increased retail revenues of $54.8 million (primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increases implemented on August 1, 2009 and October 1, 2008).

Non-utility energy marketing and trading revenues decreased $1.0 million to $18.1 million. These revenues primarily represent payments for the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of this agreement were assigned to Shell Energy through the end of 2009. We expect that these rights and obligations will be transferred to our regulated utility in 2010, subject to future approval by the WUTC (the IPUC has approved the transfer and recovery of the costs).

AVISTA CORPORATION

Other non-utility revenues increased $8.7 million to $66.2 million as a result of an increase in revenues from Advantage IQ of $13.4 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 of $4.7 million, primarily due to decreased sales at AM&D.

Utility resource costs decreased $163.6 million due to decreases in natural gas resource costs of $130.6 million and electric resource costs of $33.1 million. The decrease in natural gas resource costs primarily reflects a decrease in the price of natural gas purchases. The decrease in electric resource costs was primarily due to a decrease in fuel costs.

Utility other operating expenses increased $17.2 million primarily due to an increase of $6.6 million in electric generation operating and maintenance expenses, an increase of $2.6 million in natural gas distribution and service costs, as well as an $8.2 million increase in pension and other postretirement benefit costs.

Utility depreciation and amortization increased $4.4 million primarily due to additions to utility plant.

Utility taxes other than income taxes increased $5.0 million due to increased revenue related taxes (due to increases in electric retail revenues) and increased property taxes.

Non-utility resource costs decreased $0.4 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 in 2010, subject to future approval by the WUTC (the IPUC has approved the transfer and recovery of the costs).

The net change in other non-utility operating expenses was an increase of $9.8 million due to an increase of $12.4 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 $9.9 million due to the effect of long-term debt maturities and redemptions during 2008, which were funded primarily with proceeds from the issuance of long-term debt as well as borrowings under our $320.0 million committed line of credit at lower interest rates. The decrease was also partially due to interest expense of $1.4 million related to an income tax settlement recorded in the third quarter of 2008.

Interest expense to affiliated trusts decreased $2.9 million due to the redemption of $61.9 million of long-term debt due to affiliated trusts in April 2009 and a decrease in the variable interest rate.

Other income-net decreased $11.1 million due to a decrease in interest income (primarily due to $5.7 million of interest income recorded on the IRS settlement agreement in the third quarter of 2008). The decrease was also due to losses on long-term venture fund investments and a decrease in equity-related AFUDC.

Income taxes decreased $2.5 million primarily due to adjustments related to IRS audits and adjustments for the 2008 filed federal tax return. In total, these adjustments had a favorable impact to recorded tax expense of $3.2 million (Avista Utilities). See “Income Taxes” in Note 1 of the Notes to Consolidated Financial Statements for further information. This was partially offset by increased income before income taxes. Our effective tax rate was 33.2 percent for the nine months ended September 30, 2009 compared to 38.5 percent for the nine months ended September 30, 2008.

Avista Utilities

Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Net income for the utility was $7.2 million for the three months ended September 30, 2009 compared to $6.5 million for the three months ended September 30, 2008. Utility income from operations was $21.5 million for the three months ended September 30, 2009 compared to $22.2 million for the three months ended September 30, 2008. This decrease in income from operations was primarily due to an increase in other utility operating expenses, depreciation and amortization and taxes other than income taxes. This was partially offset by increased gross margin (operating revenues less resource costs).

AVISTA CORPORATION

The following table presents our operating revenues, resource costs and resulting gross margin for the three months ended September 30 (dollars in thousands):


	Electric				Natural Gas				Total
	2009		2008		2009		2008		2009		2008
Operating revenues	$	198,440	$	217,995	$	85,809	$	135,829	$	284,249	$	353,824
Resource costs		96,156		123,386		71,306		121,741		167,462		245,127

Gross margin	$	102,284	$	94,609	$	14,503	$	14,088	$	116,787	$	108,697

Utility operating revenues decreased $69.6 million and utility resource costs decreased $77.7 million, which resulted in an increase of $8.1 million in gross margin. The gross margin on electric sales increased $7.7 million and the gross margin on natural gas sales increased $0.4 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 August 1, 2009 and October 1, 2008. We absorbed $2.0 million of expense in the third quarter of 2009 compared to a benefit of $0.1 million in the third quarter of 2008 under the ERM, which decreased electric gross margin by $2.1 million in the third quarter of 2009 as compared to the third quarter of 2008.

The following table presents our utility electric operating revenues and megawatt-hour (MWh) sales for the three months ended September 30 (dollars and MWhs in thousands):


	Electric Operating Revenues				Electric Energy MWh Sales
	2009		2008		2009	2008
Residential	$	64,725	$	54,701	781	764
Commercial		70,449		63,307	821	828
Industrial		28,531		26,159	511	536
Public street and highway lighting		1,645		1,482	6	6

Total retail		165,350		145,649	2,119	2,134
Wholesale		15,512		42,063	398	495
Sales of fuel		13,316		25,510	—	—
Other		4,262		4,773	—	—

Total	$	198,440	$	217,995	2,517	2,629

Retail electric revenues increased $19.7 million due to an increase in revenue per MWh (increased revenues $20.9 million) primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increases implemented on August 1, 2009 and October 1, 2008, offset by a decrease in total MWhs sold (decreased revenues $1.2 million) primarily due to a decrease in use per customer.

Wholesale electric revenues decreased $26.6 million due to a decrease in sales prices (decreased revenues $22.8 million) and a decrease in sales volumes (decreased revenues $3.8 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 $12.2 million due to a decrease in thermal generation resource optimization activities and a decrease in sales prices.

The following table presents our utility natural gas operating revenues and therms delivered for the three months ended September 30 (dollars and therms in thousands):


	Natural Gas Operating Revenues				Natural Gas Therms Delivered
	2009		2008		2009	2008
Residential	$	19,597	$	20,766	12,763	13,467
Commercial		12,407		13,849	10,335	11,148
Interruptible		828		1,240	898	1,321
Industrial		975		1,221	935	1,160

Total retail		33,807		37,076	24,931	27,096
Wholesale		48,456		95,965	160,644	117,473
Transportation		1,319		1,358	31,974	34,094
Other		2,227		1,430	12	17

Total	$	85,809	$	135,829	217,561	178,680

AVISTA CORPORATION

The $3.3 million decrease in retail natural gas revenues was due to a decrease in volumes (decreased revenues $3.0 million), and slightly lower retail rates (decreased revenues $0.3 million). We sold less retail natural gas in the third quarter of 2009, primarily due to warmer weather in the third quarter of 2009 as compared to the third quarter of 2008. The slight decrease in retail rates reflects the purchased gas adjustments implemented in 2009 offset by the Washington general rate increase implemented on January 1, 2009 and Idaho general rate increases implemented on August 1, 2009 and October 1, 2008.

The decrease in our wholesale natural gas revenues of $47.5 million was due to a decrease in prices (decreased revenues $60.5 million), partially offset by an increase in volumes (increased revenues $13.0 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. Additionally, we engage in optimization of under-utilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. 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 September 30:


	Electric Customers		Natural Gas Customers
	2009	2008	2009	2008
Residential	313,059	310,474	279,515	276,485
Commercial	39,180	39,069	33,051	32,793
Interruptible	—	—	43	42
Industrial	1,397	1,393	258	259
Public street and highway lighting	446	437	—	—

Total retail customers	354,082	351,373	312,867	309,579

The following table presents our utility resource costs for the three months ended September 30 (dollars in thousands):


	2009		2008
Electric resource costs:
Power purchased	$	52,006	$	48,287
Power cost amortizations, net of deferrals		991		8,239
Fuel for generation		27,456		37,104
Other fuel costs		7,665		22,254
Other regulatory amortizations, net		4,826		1,223
Other electric resource costs		3,212		6,279

Total electric resource costs		96,156		123,386

Natural gas resource costs:
Natural gas purchased		66,282		121,859
Natural gas amortizations (deferrals), net		3,914		(670	)
Other regulatory amortizations, net		1,110		552

Total natural gas resource costs		71,306		121,741

Total resource costs	$	167,462	$	245,127

Power purchased increased $3.7 million due to an increase in the volume of purchases (increased costs $9.1 million), primarily due to purchasing power to cover for the outage at Colstrip and resource optimization, partially offset by a decrease in wholesale prices (decreased costs $5.4 million).

Net amortization of deferred power costs was $1.0 million for the three months ended September 30, 2009 compared to $8.2 million for the three months ended September 30, 2008. During the third quarter of 2009, we recovered (collected as revenue) $7.1 million of previously deferred power costs in Washington and $3.8 million in Idaho. During the third quarter of 2009, we deferred $2.0 million of power costs in Washington and $7.9 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation decreased $9.6 million primarily due to a decrease in fuel prices, as well as a decrease in thermal generation (primarily due to the outage at Colstrip).

AVISTA CORPORATION

Other fuel costs decreased $14.6 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. Revenues from sales of fuel exceeded the costs we paid for purchasing the natural gas. We account for this difference under the ERM in Washington and the PCA in Idaho.

The expense for natural gas purchased decreased $55.6 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 underutilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During the third quarter of 2009, we amortized $3.9 million of deferred natural gas costs compared to deferring $0.7 million for the third quarter of 2008.

Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Net income for the utility was $63.2 million for the nine months ended September 30, 2009 compared to $51.8 million for the nine months ended September 30, 2008. Utility income from operations was $141.2 million for the nine months ended September 30, 2009 compared to $132.0 million for the nine months ended September 30, 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 nine months ended September 30 (dollars in thousands):


	Electric				Natural Gas				Total
	2009		2008		2009		2008		2009		2008
Operating revenues	$	624,297	$	624,904	$	400,681	$	527,837	$	1,024,978	$	1,152,741
Resource costs		272,577		305,628		310,228		440,800		582,805		746,428

Gross margin	$	351,720	$	319,276	$	90,453	$	87,037	$	442,173	$	406,313

Utility operating revenues decreased $127.8 million and utility resource costs decreased $163.6 million, which resulted in an increase of $35.9 million in gross margin. The gross margin on electric sales increased $32.4 million and the gross margin on natural gas sales increased $3.4 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 August 1, 2009 and October 1, 2008. We absorbed $6.1 million of expense in the first nine months of 2009 compared to $7.3 million in the first nine months of 2008 under the ERM, which increased electric gross margin by $1.2 million in the first nine months of 2009 as compared to the first nine months of 2008.

The following table presents our utility electric operating revenues and megawatt-hour (MWh) sales for the nine months ended September 30 (dollars and MWhs in thousands):


	Electric Operating Revenues				Electric Energy MWh Sales
	2009		2008		2009	2008
Residential	$	227,745	$	198,717	2,719	2,696
Commercial		203,239		182,705	2,361	2,378
Industrial		80,380		75,664	1,452	1,565
Public street and highway lighting		4,935		4,434	20	19

Total retail		516,299		461,520	6,552	6,658
Wholesale		66,756		110,958	1,857	1,506
Sales of fuel		29,479		40,498	—	—
Other		11,763		11,928	—	—

Total	$	624,297	$	624,904	8,409	8,164

Retail electric revenues increased $54.8 million due to an increase in revenue per MWh (increased revenues $63.2 million) primarily due to the Washington general rate increase implemented on January 1, 2009 and the Idaho general rate increases implemented on August 1, 2009 and October 1, 2008, offset by a decrease in total MWhs sold (decreased revenues $8.4 million) primarily due to a decrease in use per customer.

AVISTA CORPORATION

Wholesale electric revenues decreased $44.2 million due to a decrease in sales prices (decreased revenues $56.8 million), offset by an increase in sales volumes (increased revenues $12.6 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 $11.0 million due to a decrease in thermal generation resource optimization activities and lower natural gas prices in the first nine months of 2009 as compared to the first nine months of 2008.

The following table presents our utility natural gas operating revenues and therms delivered for the nine months ended September 30 (dollars and therms in thousands):


	Natural Gas Operating Revenues				Natural Gas Therms Delivered
	2009		2008		2009	2008
Residential	$	174,985	$	184,809	131,252	139,203
Commercial		96,970		103,654	82,050	86,729
Interruptible		3,808		3,738	4,107	3,936
Industrial		3,997		4,511	3,899	4,312

Total retail		279,760		296,712	221,308	234,180
Wholesale		110,051		222,259	321,397	253,636
Transportation		4,568		4,945	105,474	110,542
Other		6,302		3,921	392	409

Total	$	400,681	$	527,837	648,571	598,767

The $17.0 million decrease in retail natural gas revenues was due to a decrease in volumes (decreased revenues $16.3 million), and slightly lower retail rates (decreased revenues $0.7 million). We sold less retail natural gas in the first nine months of 2009, primarily due to warmer weather in the first nine months of 2009 as compared to the first nine months of 2008. The slight decrease in retail rates reflects the purchased gas adjustments implemented in 2009 offset by the Washington general rate increase implemented on January 1, 2009 and Idaho general rate increases implemented on August 1, 2009 and October 1, 2008.

The decrease in our wholesale natural gas revenues of $112.2 million was due to a decrease in prices (decreased revenues $135.4 million), partially offset by an increase in volumes (increased revenues $23.2 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 nine months ended September 30:


	Electric Customers		Natural Gas Customers
	2009	2008	2009	2008
Residential	313,508	310,889	280,348	277,423
Commercial	39,251	39,056	33,194	32,876
Interruptible	—	—	43	39
Industrial	1,395	1,388	259	257
Public street and highway lighting	444	432	—	—

Total retail customers	354,598	351,765	313,844	310,595

The following table presents our utility resource costs for the nine months ended September 30 (dollars in thousands):


	2009		2008
Electric resource costs:
Power purchased	$	136,638	$	139,443
Power cost amortizations, net of deferrals		21,129		15,540
Fuel for generation		63,143		92,630
Other fuel costs		28,744		37,605
Other regulatory amortizations, net		14,789		7,697
Other electric resource costs		8,134		12,713

Total electric resource costs		272,577		305,628

Natural gas resource costs:
Natural gas purchased		279,322		419,215
Natural gas amortizations, net of deferrals		23,756		15,977
Other regulatory amortizations, net		7,150		5,608

Total natural gas resource costs		310,228		440,800

Total resource costs	$	582,805	$	746,428

AVISTA CORPORATION

Power purchased decreased $2.8 million due to a decrease in wholesale prices (decreased costs $28.6 million) offset by an increase in the volume of power purchases (increased costs $25.8 million), primarily due to purchasing power to cover for the outage at Colstrip and an increase in sales volumes related to optimization.

Net amortization of deferred power costs was $21.1 million for the nine months ended September 30, 2009 compared to $15.5 million for the nine months ended September 30, 2008. During the first nine months of 2009, we recovered (collected as revenue) $24.2 million of previously deferred power costs in Washington and $14.6 million in Idaho. During the first nine months of 2009, we deferred $2.1 million of power costs in Washington and $15.5 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation decreased $29.5 million primarily due to a decrease in fuel prices, as well as a decrease in thermal generation (primarily due to the outage at Colstrip).

Other fuel costs decreased $8.9 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.

The expense for natural gas purchased decreased $139.9 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 underutilized interstate pipeline transportation and storage capacity through wholesale purchases and sales of natural gas. During the nine months ended September 30, 2009, we amortized $23.8 million of deferred natural gas costs compared to $16.0 million for the nine months ended September 30, 2008.

Advantage IQ

Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Advantage IQ’s net income attributable to Avista Corporation was $1.4 million for the three months ended September 30, 2009 compared to $1.3 million for the three months ended September 30, 2008. Operating revenues increased $2.9 million and operating expenses increased $2.7 million. The increase in operating revenues was primarily due to an increase in service revenues and the third quarter 2009 acquisition of Ecos, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). As of September 30, 2009, Advantage IQ had 527 customers representing 413,000 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 2009 acquisition of Ecos. In the third quarter of 2009, Advantage IQ managed bills totaling $4.6 billion, a decrease of $0.7 billion, or 13 percent, as compared to the third quarter of 2008.

Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Advantage IQ’s net income attributable to Avista Corporation was $3.9 million for the nine months ended September 30, 2009 compared to $4.7 million for the nine months ended September 30, 2008. Operating revenues increased $13.4 million and operating expenses increased $13.3 million. The increase in operating revenues was primarily due to 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). 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 nine months of 2009, Advantage IQ managed bills totaling $13.5 billion, an increase of $1.2 billion, or 10 percent, as compared to the first nine months of 2008. The acquisition of Cadence Network (in July 2008) added $1.8 billion in managed bills for the first nine months of 2009.

AVISTA CORPORATION

Other Businesses

Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Net loss attributable to Avista Corporation from these operations was $0.5 million for the three months ended September 30, 2009 compared to $0.4 million for the three months ended September 30, 2008. Operating revenues decreased $1.3 million and operating expenses decreased $0.2 million.

Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Net loss attributable to Avista Corporation from these operations was $2.0 million for the nine months ended September 30, 2009 compared to $0.3 million for the nine months ended September 30, 2008. Operating revenues decreased $5.6 million and operating expenses decreased $3.1 million. Contributing to the net loss attributable to Avista Corporation in the first nine months of 2009 were losses on long-term venture fund investments. AM&D had a net loss of $0.1 million for the nine months ended September 30, 2009 compared to net income of $0.5 million for the nine months ended September 30, 2008.

New Accounting Standards

Effective January 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements” (ASC 820-10) 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 ASC 820-10 related to nonrecurring measurements of nonfinancial assets and liabilities. Effective January 1, 2009, we adopted those provisions of ASC 820-10. The adoption of the provisions of ASC 820-10, that became effective on January 1, 2008 and 2009, did not have a material impact on our financial condition, results of operations, and cash flows. However, we expanded disclosures for 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” (ASC 805-10) that replaces previous accounting guidance for business combinations and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. The adoption of this statement did not have any impact on our financial condition, results of operations and cash flows.

Effective January 1, 2009, we adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements”
(ASC 810-10). This statement amends previous accounting guidance to establish accounting and reporting standards for a noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. The adoption of this statement 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 relate to third party shareholders of Advantage IQ, who own approximately 26 percent as of September 30, 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”
(ASC 815-10) that requires disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement requires disclosure of derivative features that are related to credit risk. We expanded our disclosures for 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”
(ASC 715-20) that amends FASB statement No. 132(R) “Employers’ Disclosures about Pensions and Other Postretirement Benefits”
(ASC 715-20). 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 this FSP at the end of 2009. We will have expanded disclosures for our pension and other postretirement benefit plan assets.

Effective June 30, 2009, we adopted the provisions of FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (ASC 825-10-65-1) that amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” (ASC 825-10-50) 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,” (ASC 270-10-45-2) to require those disclosures in summarized financial information at interim reporting periods. We expanded disclosures for the fair value of financial instruments. See Note 9 for the expanded disclosures.

AVISTA CORPORATION

Effective June 30, 2009, we adopted FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (ASC 820-65-10-4). This FSP provides guidance for determining fair values of financial instruments for which there is no active market or when quoted prices may represent distressed transactions. The guidance includes a reaffirmation of the need to use judgment in certain circumstances and requires expanded disclosures surrounding equity and debt securities. The adoption of this FSP did not have an impact on our financial condition, results of operations and cash flows. See Note 9 for expanded disclosures.

Effective June 30, 2009, we adopted SFAS No. 165, “Subsequent Events” (ASC 855-10). This statement established principles and requirements for subsequent events related to: 1) the period after the balance sheet date during which management of a reporting entity shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; 2) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements; 3) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. We evaluated subsequent events up to the filing of this Form 10-Q on October 30, 2009 (the date the financial statements were issued).

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets an amendment of FASB Statement No. 140” (ASC 860). This statement amends certain provisions of SFAS No. 140 (ASC 860) to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows: and a transferor’s continuing involvement in transferred financial assets. We will be required to adopt this statement effective January 1, 2010. We are evaluating the impact this statement will have on our financial condition, results of operations and cash flows.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (ASC 810). This Statement carries forward the scope of FASB Interpretation No. 46(R) (ASC 810), with the addition of entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated in FASB Statement No. 166, “Accounting for Transfers of Financial Assets an amendment of FASB Statement No. 140” (ASC 860). We will be required to adopt this statement effective January 1, 2010. We are evaluating the impact this statement will have on our financial condition, results of operations and cash flows.

Critical Accounting Policies and Estimates

The preparation of our condensed consolidated financial statements in conformity with U.S. GAAP 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 nine months ended September 30, 2009, positive cash flows from operating activities of $234.1 million and proceeds from the issuance of debt of $249.4 million were used to fund the majority of our cash requirements. These cash requirements included utility capital expenditures of $141.4 million, a decrease (net repayment) in short-term borrowings of $218.8 million, redemption of long-term debt to affiliated trusts of $61.9 million and dividends of $32.8 million.

Operating Activities Net cash provided by operating activities was $234.1 million for the nine months ended September 30, 2009 compared to $131.9 million for the nine months ended September 30, 2008. Net cash provided by working capital components was $98.0 million for the nine months ended September 30, 2009, compared to cash used of $19.7 million for the nine months ended September 30, 2008. The net cash provided during the nine months ending September 30, 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 liabilities,

AVISTA CORPORATION

•

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).

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

The net cash used during the nine months ended September 30, 2008 primarily reflected an increase in natural gas stored of $33.1 million and a decrease in accounts payable (representing net cash paid to our vendors). This cash used was partially offset by positive cash flows from other current assets (primarily related to federal income taxes).

Contributions to our defined benefit pension plan were $48.0 million for the first nine months of 2009 compared to $28.0 million for the first nine months of 2008.

Significant non-cash items included $44.9 million of power and natural gas cost amortizations, net of deferrals, for the nine months ending September 30, 2009, an increase from $31.4 million for the nine months ending September 30, 2008. We also had a benefit for deferred income taxes of $27.8 million for the nine months ended September 30, 2009 compared to an expense of $5.7 million for the nine months ended September 30, 2008. Income tax payments were $21.2 million in 2009 compared to $28.1 million for 2008.

Investing Activities Net cash used in investing activities was $162.2 million for the nine months ended September 30, 2009, an increase compared to $153.3 million for the nine months ended September 30, 2008. Utility property capital expenditures decreased for the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008, and funds held from customers at Advantage IQ decreased $8.4 million. The $12.0 million decrease in restricted cash relates to the Coeur d’Alene Tribe trust funds for the relicensing of the Spokane River Project.

Financing Activities Net cash used in financing activities was $61.2 million for the nine months ended September 30, 2009 compared to net cash provided of $24.6 million for the nine months ended September 30, 2008. In September 2009, we issued $250.0 million (net proceeds of $249.4 million) of long-term debt. In conjunction with the issuance of long-term debt, we cash settled interest rate swap agreements and received a total of $10.8 million. In April 2009, we redeemed $61.9 million of long-term debt to affiliated trusts. During the nine months ended September 30, 2009, our short-term borrowings decreased $218.8 million due to a decrease of $225.0 million in the amount of debt outstanding under our $320.0 million committed line of credit, partially offset by a $6.2 million increase in the amount borrowed under Advantage IQ’s credit agreement. Cash dividends paid increased to $32.8 million (or 60 cents per share) for the nine months ended September 30, 2009 from $27.3 million (or 51 cents per share) for the nine months ended September 30, 2008. Additionally, customer funds obligations at Advantage IQ decreased by $8.4 million.

In April 2008, we issued $250.0 million (net proceeds of $249.2 million) of long-term debt. During the nine months ended September 30, 2008, $295.0 million of long-term debt matured, the majority being the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. Our short-term borrowings increased $86.5 million during the first nine months of 2008, due to an increase of $85.0 million in borrowings outstanding under Avista Corp.’s committed line of credit and $1.5 million borrowed under Advantage IQ’s credit agreement. In March 2008, we cash settled two interest rate swap agreements and paid a total of $16.4 million. Proceeds from the issuance of common stock of $27.4 million during the nine months ended September 30, 2008 includes $16.6 million from the issuance of 750,000 shares of common stock under a sales agency agreement.

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.

AVISTA CORPORATION

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

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

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low availability of streamflows for hydroelectric generation,

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unplanned outages at generating facilities, and

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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:

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

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$200.0 million committed line of credit (which expires in November 2009) (we are in the process of renewing this credit facility at a reduced level, not expected to exceed $100.0 million), and

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

As of September 30, 2009, we had a combined $513.1 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 September 30, 2009, that we would potentially be required to post additional collateral up to $72 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 ASC 815 and due to the assumptions about potential energy price changes.

Under the terms of interest rate swap agreements that we enter into from time to time, we may be required to post cash collateral depending on fluctuations in the fair value of the instrument. This has not historically been significant to our liquidity. As of September 30, 2009, we did not have any interest rate swap agreements outstanding.

Our utility held cash deposits from other parties in the amount of $3.2 million as of September 30, 2009 and $0.2 million as of December 31, 2008. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral.

AVISTA CORPORATION

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 September 30, 2009 and December 31, 2008 (dollars in thousands):


	September 30, 2009				December 31, 2008
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	27,206	1.2	%	$	17,207	0.8	%
Short-term borrowings (1)		33,400	1.5			252,200	11.5
Long-term debt to affiliated trusts (2)		51,547	2.4			113,403	5.2
Long-term debt (1)		1,060,951	48.0			809,258	37.0

Total debt		1,173,104	53.1			1,192,068	54.5
Total Avista Corporation stockholders’ equity		1,036,162	46.9			996,883	45.5

Total	$	2,209,266	100.0	%	$	2,188,951	100.0	%

(1)

(2)

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

We need to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund capital expenditures, working capital, purchased power and natural gas costs, dividends and other requirements. Our stockholders’ equity increased $39.3 million during the nine months ended September 30, 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 are expected to be the primary source of funds for operating needs, dividends and capital expenditures for the fourth quarter of 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 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, 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

Under the credit agreement, we can borrow or request the issuance of letters of credit in any combination up to $320.0 million. As of September 30, 2009, we had $25.0 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 September 30, 2009, there were $23.9 million in letters of credit outstanding, a decrease 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.

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, 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

We are in the process of renewing this credit facility at a reduced level (not expected to exceed $100.0 million).

As of September 30, 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 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 September 30, 2009, we were in compliance with this covenant with a ratio of 4.02 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 September 30, 2009, we were in compliance with this covenant with a ratio of 52.8 percent. 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 to 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 September 30, 2009, Avista Corp. and our subsidiaries were in compliance with all of the covenants of our financing agreements.

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:

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working capital requirements,

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capital expenditures, and

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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 September 30, 2009, we had the ability to sell up to $42.0 million of receivables (based on calculations of our eligible accounts receivable) and there were not any accounts receivable sold under this revolving agreement.

The Receivables Purchase Agreement requires a receivables report to be prepared monthly, including information related to customer account delinquency ratios. The June 30, 2009 report indicated that one measurement of the delinquency ratios was in excess of the threshold specified in the Receivables Purchase Agreement, triggering an optional liquidation event. An optional liquidation event gives the receivables purchaser the right, at its option, to terminate its obligations to purchase additional receivables from ARC. Avista Corp, ARC and the third-party financial institution have executed an amendment to the Receivables Purchase Agreement which waived the occurrence of the liquidation event arising from the customer account delinquency ratio increase reflected in the June 30, 2009 report and made certain other amendments to the Receivables Purchase Agreement, including an increase in the delinquency ratio threshold for the periods to be covered by the July 31, 2009 and August 31, 2009 monthly receivables reports and the modification of certain reporting obligations. As of September 30, 2009, we were in compliance with all covenants including the delinquency ratio threshold as defined in the Receivables Purchase Agreement.

Pension Plan

As of September 30, 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 contributed $48 million to the pension plan in 2009. We expect that our contribution for 2010 will be approximately $21 million. The final determination of pension plan contributions for future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation).

Credit Ratings

The following table summarizes our credit ratings as of October 29, 2009:


	Standard & Poor’s (1)	Moody’s (2)	Fitch, Inc. (3)
Avista Corporation
Corporate/Issuer rating	BBB-	Baa3	BBB-
Senior secured debt (4)	BBB+	Baa1	BBB+
Senior unsecured debt	BBB-	Baa3	BBB
Avista Capital II (5)
Preferred Trust Securities	BB	Ba1	BBB-

Rating outlook (6)	Positive	Positive	Stable

(1)	Ratings were upgraded in February 2008.

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

(3)	Ratings were upgraded in May 2009.

(4)

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

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

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

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

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 September 2009, Avista Corp. paid a quarterly dividend of $0.21 per share on the Company’s common stock.

Avista Utilities Capital Expenditures

We expect utility capital expenditures to be approximately $210 million for 2009, and over $210 million for each of 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 and do not include potential costs of a wind generation project or projects associated with stimulus funding (see discussion below). Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

We are committed to investment in generation, transmission and distribution systems with a focus on increasing capacity and 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. On August 3, 2009, we applied to the Smart Grid Investment Grant program. The Smart Grid Investment Grant application proposed a 50 percent cost share for the deployment of smart grid enabling technologies in the Spokane area. The total project costs are estimated to be $40 million, which will be spent over a three-year period. We received notification that we had received this grant on October 27, 2009.

On August 23, 2009, Battelle Northwest submitted an application for consideration for a regional Smart Grid Demonstration Project. The Smart Grid Demonstration Project is comprised of 12 regional utilities located in five northwestern states and includes six cost share partner vendors. The proposal assumes a 50 percent cost share from the Department of Energy (DOE). Our portion of the regional demonstration project is located in Pullman, Washington and is estimated to cost a total of $38 million (DOE) cost share and cost share partner contributions. We expect to fund $12.9 million, DOE would fund $19 million and our cost share partners would fund $6.1 million. The Smart Grid Demonstration Project will spend the funds over the course of five years. Notification of award is expected in early December 2009.

In August 2009, we also submitted a proposal to the State of Washington Department of Commerce for funding under the State Energy Program (SEP), which obtains funding from the ARRA. In the first round of funding, we applied for

$2 million in SEP funding to establish a revolving loan fund to support a proposed home and business energy efficiency program. The three largest governments in eastern Washington have pledged financial contributions to the program, using a portion of funds they will receive from the ARRA under its Energy Efficiency and Conservation Block Grant (EECBG) program. Our proposal was not selected in the first round of funding, though the three government entities have continued support for our home and business energy efficiency program with their EECBG funds. We will advance our home and business efficiency program without the revolving loan fund option for customers absent federal funding at this time. We will evaluate our next steps relative to applying for federal funds. Two additional funding opportunities will be made available by the Department of Commerce in late 2009 or early 2010.

In our 2009 Electric Integrated Resource Plan, we have targeted adding 50 average megawatts of renewable energy by the end of 2012 (which equates to approximately 150 MW of wind power). Based on this goal, we are evaluating proposals from suppliers to provide us with up to 35 average megawatts (which equates to approximately 105 MW of wind power) of long-term qualified renewable energy.

In 2008, we completed the acquisition of the development rights for a wind generation site. Contingent on the results from evaluating proposals from suppliers, we could construct this generation facility of at least 15 average megawatts at an estimated cost of over $125 million. We are continuing to evaluate the timing of this project relative to the investment tax credit rules, and sales tax exemption rules in Washington. Based on the supplier proposals and analysis of various options to meet our renewable energy needs, we may accelerate the deployment of capital related to this wind generation site and/or increase the capacity. Our estimate of capital expenditures for 2010 and 2011 do not include potential costs for a wind generation project. 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 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. We are working on a stage two agreement for the project that we expect to have completed in the fourth quarter of 2009. The stage two agreement will determine our financial obligation and participation on 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 September 30, 2009, we had $25.0 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.

In April 2009, we redeemed the total amount outstanding ($61.9 million) of our 6.5 percent Junior Subordinated Debt Securities held by AVA Capital Trust III (Long-term Debt to Affiliated Trusts).

In September 2009, we issued $250.0 million of 5.125 percent First Mortgage Bonds due in 2022.

On June 18, 2009, the FERC issued a new 50-year license for five hydroelectric plants that we own and operate on the Spokane River. The new license incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the Department of Interior and the Coeur d’Alene Tribe. As part of the Settlement Agreement, we agreed to make annual payments over the life of the 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. Annual payments for protection, mitigation and enhancement measurements will total $100 million over the 50-year license term and commenced with the issuance of the new FERC license. Payments will total $12 million in 2009. We are required to make annual payments of $2 million per year beginning in 2010 and continuing through 2041. Beginning in 2042 and continuing through 2057 we are required to make annual payments of $1.5 million. The IPUC has approved the recovery of amounts paid to the Tribe, the Trust Fund or related to the licensing of Avista Corp.’s hydroelectric generating facilities. The WUTC approved deferral of the Washington 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. See “Note 11 of the Notes to Condensed Consolidated Financial Statements” for further information.

Business Risk

Our business risk has not materially changed during the nine months ended September 30, 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.

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:

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assumptions relating to weather and economic and competitive conditions,

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

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internal business plans, and

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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:

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increase the costs of generating plants,

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

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require modification of our existing generating plants,

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require existing generating plants to be curtailed or shut down,

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increase the risk of delay on construction projects,

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

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restrict the types of generating plants that can be built.

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

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

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

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

In 2008, the state of 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; these goals nominally affect Avista’s electric and natural gas operations in the state. The state of Oregon has codified goals to reduce greenhouse gas emissions to 10 percent below 1990 levels by 2020 and 75 percent below 1990 levels by 2050. Both states enacted their goals expecting that they would be met through a combination of renewable energy standards, cap-and-trade regulation, and “complementary policies,” such as energy efficiency codes for buildings and vehicle emission standards. Washington and Oregon continue their participation in the Western Climate Initiative (WCI), along with the states of Arizona, California, New Mexico, Utah and Montana, and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. The WCI was created 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 complete its recommendations. In 2009, the Governor of Washington has issued an Executive Order (09-05) directing the Department of Ecology to estimate greenhouse gas emissions by sector and source and to identify potential reduction requirements for them in preparation for the eventual imposition of state and/or federal regulations.

Washington and Oregon apply a greenhouse gas emissions performance standard to electric generation facilities used to serve loads in their respective jurisdictions. The emissions performance standard prevents utilities from entering into long-term contracts (five years or more) to purchase energy produced by plants that have emission levels higher than the latest commercially available natural gas-fired combined-cycle combustion turbine technology.

Initiative Measure 937 (I-937), which was passed into law through the General Election in Washington in November 2006, 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.

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

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

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An additional 200 MW of wind power by 2022,

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

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

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

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Hydroelectric upgrades at existing facilities will generate additional renewable energy.

Based on resource acquisition goals identified in the IRP, we are evaluating proposals from suppliers to provide us with up to 35 average megawatts (which equates to approximately 105 MW of wind power) of long-term qualified renewable energy by the end of 2012 in order to take advantage of federal and state tax incentives. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

Recent EPA Initiatives Related to Climate Change

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.

On September 30, 2009, the EPA published a proposed rule to regulate facilities emitting over 25,000 metric tons of greenhouse gases (GHG) a year under existing Clean Air Act authority. Comments on the proposed rule will be accepted for 60 days following publication in the Federal Register. Based on the rule threshold of 25,000 metric tons of GHGs a year, Colstrip 3 & 4 and Coyote Springs II will be required to report GHGs. These facilities currently report CO2 to the EPA under the Acid Rain Program and it is expected that the operators of these plants will be responsible for any additional GHG reporting. No other electrical generation facilities that we own meet the threshold requirements, including the Kettle Falls Generating Station. The rule also requires natural gas distribution system throughput be reported, assuming all natural gas is combusted and the resulting GHG emissions are greater than 25,000 metric tons. 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 September 30, 2009.

There have been no changes in the Company’s internal control over financial reporting that occurred during the third 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 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 other than the risk factor identified as “Relicensing our hydroelectric facilities located on the Spokane River at a cost-effective level with reasonable terms and conditions may not be possible.” On June 18, 2009, the FERC issued a new 50-year license for five hydroelectric plants that we own and operate on the Spokane River. See “Spokane River Relicensing” at “Note 11 of the Notes to Condensed Consolidated Financial Statements” for further information.

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 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.

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: October 30, 2009				/s/ MARK T. THIES
				Mark T. Thies
				Senior Vice President and
				Chief Financial Officer
				(Principal Financial Officer)