Edgar Filing: AVISTA CORP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2008

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

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller

reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

Yes ¨ No x

As of October 31, 2008, 54,430,678 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.	Consolidated Financial Statements

		Consolidated Statements of Income (Loss) - Three Months Ended September 30, 2008 and 2007	3

		Consolidated Statements of Income Nine Months Ended September 30, 2008 and 2007	4

		Consolidated Statements of Comprehensive Income (Loss) - Three and Nine Months Ended September 30, 2008 and 2007	5

		Consolidated Balance Sheets - September 30, 2008 and December 31, 2007	6

		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2008 and 2007	8

		Notes to Consolidated Financial Statements	9

		Report of Independent Registered Public Accounting Firm	29

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54

	Item 4.	Controls and Procedures	54

Part II.	Other Information:

	Item 1.	Legal Proceedings	55

	Item 1A.	Risk Factors	55

	Item 6.	Exhibits	55

Signature			56

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 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Forward-Looking Statements” on pages 30-31. 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.

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands, except per share amounts


	2008			2007
Operating Revenues:
Utility revenues	$	353,824		$	243,798
Non-utility energy marketing and trading revenues		6,824			6,314
Other non-utility revenues		22,037			17,550

Total operating revenues		382,685			267,662

Operating Expenses:
Utility operating expenses:
Resource costs		245,127			144,059
Other operating expenses		49,114			50,126
Depreciation and amortization		22,023			21,551
Taxes other than income taxes		15,323			15,012
Non-utility operating expenses:
Resource costs		6,206			6,259
Other operating expenses		18,081			13,865
Depreciation and amortization		1,479			1,054

Total operating expenses		357,353			251,926

Income from operations		25,332			15,736

Other Income (Expense):
Interest expense		(17,452	)		(19,547	)
Interest expense to affiliated trusts		(1,445	)		(1,836	)
Capitalized interest		970			1,326
Regulatory disallowance of unamortized debt repurchase costs		—			(3,850	)
Other income - net		7,104			2,156

Total other expense-net		(10,823	)		(21,751	)

Income (loss) before income taxes		14,509			(6,015	)
Income taxes		7,150			(2,140	)

Net income (loss)	$	7,359		$	(3,875	)

Weighted-average common shares outstanding (thousands), basic		53,773			52,834
Weighted-average common shares outstanding (thousands), diluted		54,205			52,834
Total earnings (loss) per common share, basic	$	0.14		$	(0.07	)

Total earnings (loss) per common share, diluted	$	0.13		$	(0.07	)

Dividends paid per common share	$	0.18		$	0.15

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF INCOME

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands, except per share amounts


	2008			2007
Operating Revenues:
Utility revenues	$	1,152,741		$	926,061
Non-utility energy marketing and trading revenues		19,068			55,121
Other non-utility revenues		57,493			49,672

Total operating revenues		1,229,302			1,030,854

Operating Expenses:
Utility operating expenses:
Resource costs		746,428			549,565
Other operating expenses		153,353			149,358
Depreciation and amortization		65,379			63,939
Taxes other than income taxes		55,631			54,057
Non-utility operating expenses:
Resource costs		17,661			62,372
Other operating expenses		46,426			53,173
Depreciation and amortization		3,541			3,499

Total operating expenses		1,088,419			935,963

Income from operations		140,883			94,891

Other Income (Expense):
Interest expense		(57,131	)		(60,154	)
Interest expense to affiliated trusts		(4,661	)		(5,463	)
Capitalized interest		2,720			3,700
Regulatory disallowance of unamortized debt repurchase costs		—			(3,850	)
Other income – net		9,868			9,414

Total other expense-net		(49,204	)		(56,353	)

Income before income taxes		91,679			38,538
Income taxes		35,544			14,136

Net income	$	56,135		$	24,402

Weighted-average common shares outstanding (thousands), basic		53,366			52,769
Weighted-average common shares outstanding (thousands), diluted		53,765			53,267
Total earnings per common share, basic	$	1.05		$	0.46

Total earnings per common share, diluted	$	1.04		$	0.45

Dividends paid per common share	$	0.510		$	0.445

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

Avista Corporation

For the Three Months Ended September 30

Dollars in thousands


	2008			2007
Net income (loss)	$	7,359		$	(3,875	)

Other Comprehensive Income (Loss):
Unrealized losses on interest rate swap agreements - net of taxes of $(1,557)		—			(2,892	)
Change in unfunded benefit obligation for pension plan - net of taxes of $64 and $109, respectively		119			202

Total other comprehensive income (loss)		119			(2,690	)

Comprehensive income (loss)	$	7,478		$	(6,565	)


For the Nine Months Ended September 30 Dollars in thousands

	2008			2007
Net income	$	56,135		$	24,402

Other Comprehensive Income (Loss):
Foreign currency translation adjustment		—			1,010
Reclassification adjustment for foreign currency translation adjustment included in loss on sale of contracts		—			(2,379	)
Unrealized gains (losses) on interest rate swap agreements - net of taxes of $(2,063) and $77, respectively		(3,831	)		143
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 $365 and $264, respectively		678			491
Unrealized losses on derivative commodity instruments - net of taxes of $(324)		—			(602	)
Reclassification adjustment for realized gains on derivative commodity instruments included in net income - net of taxes of $(136)		—			(253	)
Reclassification adjustment for realized losses on derivative commodity instruments included in loss on sale of contracts, net of taxes of $464		—			862

Total other comprehensive income (loss)		7,504			(728	)

Comprehensive income	$	63,639		$	23,674

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS

Avista Corporation

Dollars in thousands


	September 30, 2008		December 31, 2007
Assets:
Current Assets:
Cash and cash equivalents	$	15,030	$	11,839
Restricted cash		—		4,068
Accounts and notes receivable-less allowances of $44,557 and $42,582		93,332		105,440
Utility energy commodity derivative assets		13,455		12,078
Regulatory asset for utility derivatives		51,151		7,171
Funds held for customers		92,429		89,885
Materials and supplies, fuel stock and natural gas stored		70,542		34,985
Deferred income taxes		16,910		20,251
Income taxes receivable		29,974		30,025
Other current assets		9,346		16,443

Total current assets		392,169		332,185

Net Utility Property:
Utility plant in service		3,241,562		3,131,916
Construction work in progress		128,491		100,106

Total		3,370,053		3,232,022
Less: Accumulated depreciation and amortization		931,136		880,680

Total net utility property		2,438,917		2,351,342

Other Property and Investments:
Investment in exchange power-net		26,746		28,583
Investment in affiliated trusts		13,403		13,403
Other property and investments-net		105,870		74,171

Total other property and investments		146,019		116,157

Deferred Charges:
Regulatory assets for deferred income tax		112,087		117,461
Regulatory assets for pensions and other postretirement benefits		48,151		51,006
Other regulatory assets		41,215		43,004
Non-current utility energy commodity derivative assets		100,927		55,313
Power and natural gas deferrals		66,858		85,885
Unamortized debt expense		31,491		32,542
Other deferred charges		7,250		4,902

Total deferred charges		407,979		390,113

Total assets	$	3,385,084	$	3,189,797

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED BALANCE SHEETS (continued)

Avista Corporation

Dollars in thousands


	September 30, 2008			December 31, 2007
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable	$	102,917		$	117,546
Customer fund obligations		92,429			89,885
Deposits from counterparties		16,920			12,510
Current portion of long-term debt		108,916			427,344
Short-term borrowings		86,500			—
Interest accrued		22,188			12,578
Utility energy commodity derivative liabilities		64,606			19,249
Other current liabilities		100,651			84,537

Total current liabilities		595,127			763,649

Long-term debt		778,913			521,489

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

Other Non-Current Liabilities and Deferred Credits:
Regulatory liability for utility plant retirement costs		213,610			209,357
Non-current regulatory liability for utility derivatives		93,982			53,414
Pensions and other postretirement benefits		67,193			90,555
Deferred income taxes		464,888			440,918
Other non-current liabilities and deferred credits		79,316			83,046

Total other non-current liabilities and deferred credits		918,989			877,290

Total liabilities		2,406,432			2,275,831

Commitments and Contingencies (See Notes to Consolidated Financial Statements)
Stockholders’ Equity:
Common stock, no par value; 200,000,000 shares authorized; 54,422,099 and 52,909,013 shares outstanding		773,198			726,933
Accumulated other comprehensive loss		(12,104	)		(19,608	)
Retained earnings		217,558			206,641

Total stockholders’ equity		978,652			913,966

Total liabilities and stockholders’ equity	$	3,385,084		$	3,189,797

The Accompanying Notes are an Integral Part of These Statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

Avista Corporation

For the Nine Months Ended September 30

Dollars in thousands


	2008			2007
Operating Activities:
Net income	$	56,135		$	24,402
Non-cash items included in net income:
Depreciation and amortization		68,920			67,438
Provision (benefit) for deferred income taxes		5,748			(10,032	)
Power and natural gas cost amortizations, net of deferrals		31,421			13,879
Amortization of debt expense		3,547			4,822
Unrealized loss on energy commodity derivatives		—			24,594
Regulatory disallowance of unamortized debt repurchase costs		—			3,850
Impairment of utility generation asset		—			2,290
Loss on sale of Avista Energy assets		—			4,254
Equity-related Allowance for Funds Used During Construction (AFUDC)		(2,892	)		(3,004	)
Other		(11,256	)		(5,597	)
Changes in working capital components:
Accounts and notes receivable		9,336			173,586
Materials and supplies, fuel stock and natural gas stored		(35,557	)		1,935
Deposits with counterparties		—			78,212
Other current assets		7,723			(6,560	)
Accounts payable		(8,735	)		(206,332	)
Deposits from counterparties		4,410			(22,003	)
Other current liabilities		3,111			17,859

Net cash provided by operating activities		131,911			163,593

Investing Activities:
Utility property capital expenditures (excluding equity-related AFUDC)		(150,071	)		(148,947	)
Other capital expenditures		(2,627	)		(2,596	)
Purchase of auction rate investment securities		—			(130,000	)
Sale of auction rate investment securities		—			130,000
Increase in funds held for customers		(2,544	)		(125	)
Decrease in restricted cash		4,068			28,585
Repayments received on notes receivable		3,010			12
Purchase of subsidiary minority interest		(8,574	)		—
Cash paid for acquisition of subsidiary, net of cash received		(1,428	)		—
Proceeds received from sale of assets		7,787			492
Changes in other property and investments		(2,925	)		(3,130	)

Net cash used in investing activities		(153,304	)		(125,709	)

Financing Activities:
Increase (decrease) in short-term borrowings		86,500			(4,000	)
Proceeds from issuance of long-term debt		249,165			—
Maturity of long-term debt		(295,023	)		(12,610	)
Redemption of preferred stock		—			(26,250	)
Cash dividends paid		(27,258	)		(23,510	)
Issuance of common stock		27,397			4,032
Cash paid for settlement of interest rate swap agreements		(16,395	)		—
Long-term debt and short-term borrowing issuance costs		(2,346	)		(163	)
Increase in customer fund obligations		2,544			125
Other		—			1,440

Net cash provided by (used in) financing activities		24,584			(60,936	)

Net increase (decrease) in cash and cash equivalents		3,191			(23,052	)
Cash and cash equivalents at beginning of period		11,839			28,242

Cash and cash equivalents at end of period	$	15,030		$	5,190

Supplemental Cash Flow Information:
Cash paid during the period:
Interest	$	48,642		$	47,788
Income taxes	$	28,102		$	28,847
Non-cash financing and investing activities:
Change in liability to subsidiary minority shareholders	$	26,243		$	12,649
Issuance of subsidiary stock for acquisition of subsidiary	$	37,100			—

The Accompanying Notes are an Integral Part of These Statements.

AVISTA CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying consolidated financial statements of Avista Corporation (Avista Corp. or the Company) for the interim periods ended September 30, 2008 and 2007 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 consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. The Consolidated Statements of Income for the interim periods are not necessarily indicative of the results to be expected for the full year. These 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, 2007 (2007 Form 10-K). Please refer to the section “Acronyms and Terms” in the 2007 Form 10-K for definitions of terms such as capacity, energy and therm.

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Avista Corp. is an energy company engaged in the generation, transmission and distribution of energy as well as other energy-related businesses. Avista Utilities is an operating division of Avista Corp., comprising the regulated utility operations. Avista Utilities generates, transmits and distributes electricity in parts of eastern Washington and northern Idaho. In addition, Avista Utilities has electric generating facilities in 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 business segments including Avista Energy, Inc. (Avista Energy) and Advantage IQ, Inc. (Advantage IQ). Avista Energy was an electricity and natural gas marketing, trading and resource management business. On June 30, 2007, Avista Energy completed the sale of substantially all of its contracts and ongoing operations. See Note 3 for further information. Advantage IQ is a provider of facility information and cost management services for multi-site customers throughout North America. See Note 16 for business segment information.

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

•

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

•

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

•

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

•

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

•

regulatory disallowance of the recovery of power and natural gas costs, operating costs and capital investments,

•

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

•

changes in regulatory requirements,

•

availability of generation facilities, and

•

competition.

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

Basis of Reporting

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

AVISTA CORPORATION

Taxes Other Than Income Taxes

Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled $9.3 million for the three months ended September 30, 2008 and $9.0 million for the three months ended September 30, 2007. These taxes were $40.9 million for the nine months ended September 30, 2008 and $37.7 million for the nine months ended September 30, 2007.

Other Income-Net

Other income-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,
	2008			2007			2008			2007
Interest income	$	1,003		$	1,177		$	2,837		$	7,563
Interest on power and natural gas deferrals		820			1,059			2,960			3,287
Interest on income tax settlement		5,749			—			5,749			—
Equity-related Allowance for Funds Used During Construction		1,034			1,076			2,892			3,004
Net gain (loss) on investments		—			—			(94	)		445
Other expense		(2,224	)		(1,250	)		(5,462	)		(5,036	)
Other income		722			94			986			151

Total	$	7,104		$	2,156		$	9,868		$	9,414

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss, net of tax, consisted of the following as of September 30, 2008 and December 31, 2007 (dollars in thousands):


	September 30, 2008			December 31, 2007
Unfunded benefit obligation for pensions and other postretirement benefit plans	$	(12,104	)	$	(12,782	)
Unrealized loss on interest rate swap agreements		—			(6,826	)

Total accumulated other comprehensive loss	$	(12,104	)	$	(19,608	)

Regulatory Deferred Charges and Credits

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

•

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

•

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

•

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

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

If at some point in the future the Company determines that it no longer meets the criteria for continued application of SFAS No. 71 for all or a portion of its regulated operations, the Company could be:

•

required to write off its regulatory assets, and

•

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

AVISTA CORPORATION

The Company’s primary regulatory assets include:

•

power cost deferrals,

•

investment in exchange power,

•

regulatory asset for deferred income taxes,

•

unamortized debt expense,

•

assets offsetting net utility energy commodity derivative liabilities (see Note 6 for further information),

•

expenditures for demand side management programs,

•

expenditures for conservation programs, and

•

unfunded pensions and other postretirement benefits.

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

Regulatory liabilities include:

•

utility plant retirement costs,

•

natural gas cost deferrals,

•

settled interest rate swap agreements included as part of long-term debt, and

•

liabilities offsetting net utility energy commodity derivative assets (see Note 6 for further information).

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

Reclassifications

Cash flow activity related to the $0.1 million increase in funds held for customers was reclassified as an investing activity and the $0.1 million increase in customer fund obligations was reclassified as a financing activity, rather than as operating activities as previously presented in the Consolidated Statement of Cash Flows for the nine months ended September 30, 2007. These reclassifications had no impact on the net change in cash and cash equivalents or cash flows from operating activities for the nine months ended September 30, 2007.

NOTE 2. NEW ACCOUNTING STANDARDS

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, “Fair Value Measurements” related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the Financial Accounting Standards Board (FASB) issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. The Company will be required to adopt those provisions of SFAS No. 157 in 2009. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008 did not have a material impact on the Company’s financial condition and results of operations; however, the Company expanded disclosures with respect to fair value measurements. See Note 12 for the expanded disclosures.

Effective January 1, 2008, the Company adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option is elected would be reported in net income. The Company did not elect to use the fair value option under SFAS No. 159 for any financial assets and liabilities at implementation and as such the adoption of SFAS No. 159 did not have any impact on its financial condition and results of operations.

Effective January 1, 2008 the Company adopted FASB Staff Position (FSP) FIN 39-1, “Amendment of FASB Interpretation No. 39.” FSP FIN 39-1 amends certain paragraphs of FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts, an interpretation of APB Opinion No. 10 and FASB Statement No. 105.” This statement permits an entity to offset fair value amounts recognized for the right to reclaim or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. As of September 30, 2008 the Company did not offset any fair value cash collateral receivables against net derivative positions. As of December 31, 2007, the retrospective application of FSP FIN 39-1 had no impact on the Consolidated Balance Sheet. The fair value of cash collateral that was not offset in the Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007 was $16.9 million and $12.5 million respectively.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. This statement requires the acquiring entity in a business combination to recognize the assets

AVISTA CORPORATION

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 Company would be required to begin applying this statement to any business combinations in 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards for a noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies that a noncontrolling interest in a subsidiary is an ownership in the consolidated entity that should be reported as equity in the consolidated financial statements. The Company will be required to adopt SFAS No. 160 in 2009. The Company is evaluating the impact SFAS No. 160 will have on its financial condition and results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This statement will require disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement will also require disclosure of derivative features that are related to credit risk. The Company will be required to adopt SFAS No. 161 in 2009. The Company does not expect the adoption of SFAS No. 161 to have any impact on its financial condition and results of operations. However, the Company will have expanded disclosures with respect to derivatives and hedging activities.

NOTE 3. DISPOSITION OF AVISTA ENERGY

On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy North America (U.S.), L.P. (Shell Energy), formerly known as Coral Energy Holding, L.P., as well as to certain other subsidiaries of Shell Energy. Proceeds from the transaction included cash consideration for the net assets acquired by Shell Energy and the liquidation of the remaining net current assets of Avista Energy not sold to Shell Energy (primarily receivables, restricted cash and deposits with counterparties). The pre-tax net loss on the transaction was $4.3 million, which is included in non-utility other operating expenses in the Consolidated Statements of Income for the nine months ended September 30, 2007.

Certain assets of Avista Energy with a net book value of approximately $30 million were not sold or liquidated. These primarily include natural gas storage and deferred tax assets. The Company expects that the natural gas storage will ultimately be transferred to Avista Utilities, subject to future regulatory approval. The Company also expects that the power purchase agreement for the 270 megawatt (MW) natural-gas fired combined cycle combustion turbine plant located in Idaho (Lancaster Plant) for the period 2010 through 2026 will be transferred to Avista Utilities, subject to future regulatory approval.

In connection with the transaction, on June 30, 2007, Avista Energy and its affiliates entered into an Indemnification Agreement with Shell Energy and its affiliates. Under the Indemnification Agreement, Avista Energy and Shell Energy each agree to provide indemnification of the other and the other’s affiliates for certain events and matters described in the purchase and sale agreement and certain other transaction agreements. Such events and matters include, but are not limited to, the refund proceedings arising out of the western energy markets in 2000 and 2001 (see Note 14), existing litigation, tax liabilities, matters with respect to natural gas storage rights, and any potential issues associated with the power purchase agreement for the Lancaster Plant. In general, such indemnification is not required unless and until a party’s claims exceed $150,000 and is limited to an aggregate amount of $30 million and a term of three years (except for agreements or transactions with terms longer than three years). These limitations do not apply to certain third party claims.

Avista Energy’s obligations under the Indemnification Agreement are guaranteed by Avista Capital pursuant to a Guaranty dated June 30, 2007. This Guaranty is limited to an aggregate amount of $30 million plus certain fees and expenses. Avista Capital granted Shell Energy a security interest in 50 percent of Avista Capital’s common shares of Advantage IQ as collateral for its Guaranty. The aggregate obligations secured by this security interest will in no event exceed $25 million. Avista Capital may substitute collateral, such as cash or letters of credit, in place of the security interest in Advantage IQ’s common shares. This security interest in Advantage IQ’s common shares will terminate on December 31, 2008 except to the extent of claims actually made prior to December 31, 2008. The Guaranty will terminate April 30, 2011 except with respect to claims made prior to termination.

As of November 4, 2008, neither party has made any claims under the Indemnification Agreement or Guaranty.

AVISTA CORPORATION

NOTE 4. ADVANTAGE IQ ACQUISITION

Effective July 2, 2008, Advantage IQ completed the acquisition of Cadence Network, Inc. (Cadence Network), a privately held, Cincinnati-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The total value of the transaction was $37.1 million.

The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock. Under the transaction agreement, the previous owners of Cadence Network can exercise a right to redeem their shares of Advantage IQ common 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. Based on the estimated fair market value of Advantage IQ common stock held by the previous owners of Cadence Network, the Company had a liability of $31.1 million as of September 30, 2008 related to this potential redemption obligation.

Advantage IQ’s acquisition of Cadence Network was accounted for under the purchase method of accounting and, accordingly, the acquired assets and liabilities assumed were preliminarily recorded at their respective estimated fair values as of the date of acquisition (July 2, 2008). Significant assets recorded include the following intangible assets: goodwill of $12.8 million, client relationships of $8.6 million (estimated amortization period of 16 years) and internal use software of $3.4 million (estimated amortization period of 5 years). These intangible assets are included in other property and investments on the Consolidated Balance Sheet. Final purchase accounting is pending the completion of further review of the fair market values of relevant assets and liabilities identified as of the acquisition date. The results of operations of Cadence Network are included in the consolidated financial statements beginning in the third quarter of 2008. Pro forma disclosures reflecting the effects of the acquisition of Cadence Network are not presented, as the acquisition is not material to Avista Corp.’s consolidated financial condition or results of operations.

NOTE 5. ACCOUNTS RECEIVABLE SALE

Avista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of Avista Corp. formed for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 14, 2008, Avista Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment extended the termination date to March 13, 2009. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of those receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in other operating expenses of Avista Corp. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of Avista Corp.’s $320.0 million committed line of credit (see Note 9). As of September 30, 2008, ARC had the ability to sell up to $57.0 million of receivables and there was $54.0 million in accounts receivable sold under this revolving agreement, a decrease from the $85.0 million available and sold as of December 31, 2007.

NOTE 6. ENERGY COMMODITY DERIVATIVES

Avista Utilities utilizes derivative instruments, such as forwards, futures, swaps and options primarily to manage its exposure to commodity price risk. The Company uses a variety of techniques to manage risks for its energy resources and wholesale energy market activities. The Company has a risk management policy and control procedures to manage these risks, both qualitative and quantitative. The Company’s Risk Management Committee establishes the Company’s risk management policy and control procedures and monitors compliance. The Risk Management Committee is comprised of certain Company officers and other individuals and is overseen by the Audit Committee of the Company’s Board of Directors.

Avista Utilities engages in an ongoing process of resource optimization, which involves the economic selection from available resources to serve Avista Utilities’ load obligations and uses its existing resources to capture available economic value. Avista Utilities sells and purchases wholesale electric capacity and energy and fuel as part of the process of economically managing electric resources to balance with its load obligations. These transactions range from terms of one hour up to multiple years. Avista Utilities makes continuing projections of:

•

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

•

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

AVISTA CORPORATION

On the basis of these projections, Avista Utilities makes purchases and sales of energy and energy derivatives 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 economic, selling fuel and substituting wholesale energy 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.

As part of its resource optimization process described above, Avista Utilities hedges the economic impact of fluctuations in electric energy prices by measuring and controlling the volume of energy imbalance between projected loads and resources and through the use of derivative commodity instruments. Load/resource imbalances within a rolling 18-month planning horizon are compared against established volumetric guidelines and management determines the timing and specific actions to manage the imbalances. Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods.

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, provides 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.

Avista Utilities enters into forward contracts to purchase or sell electricity and natural gas. Under these forward contracts, Avista Utilities commits to purchase or sell a specified amount of energy for delivery at a specified time in the future. Certain of these forward contracts are considered derivative instruments. Avista Utilities also records derivative commodity assets and liabilities for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered into as part of Avista Utilities’ management of its loads and resources as discussed above. In conjunction with the issuance of SFAS No. 133, the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC) issued accounting orders authorizing Avista Utilities to offset any derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of settlement. The orders provide for Avista Utilities to not recognize the unrealized gain or loss on utility energy commodity derivative instruments in the Consolidated Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the Energy Recovery Mechanism in Washington and the Power Cost Adjustment mechanism in Idaho.

Substantially all forward contracts to purchase or sell power and natural gas are recorded as assets or liabilities at market value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for at cost 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. Utility energy commodity derivatives consisted of the following as of September 30, 2008 and December 31, 2007 (dollars in thousands):


	September 30, 2008			December 31, 2007
Current utility energy commodity derivative assets	$	13,455		$	12,078
Current utility energy commodity derivative liabilities		64,606			19,249

Net current regulatory asset	$	(51,151	)	$	(7,171	)

Non-current utility energy commodity derivative assets	$	100,927		$	55,313
Non-current utility energy commodity derivative liabilities		6,945			1,899

Net non-current regulatory liability	$	93,982		$	53,414

Non-current utility energy commodity derivative liabilities are included in other non-current liabilities and deferred credits on the Consolidated Balance Sheets.

AVISTA CORPORATION

NOTE 7. 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 $15 million in cash to the pension plan in each of 2007, 2006 and 2005. The Company contributed $28 million to the pension plan in 2008. The increase from the original planned contribution of $15 million was a result of the new funding rules under the Pension Protection Act of 2006 and the Company’s ongoing commitment to increasing the funded status of the pension plan.

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

The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The liability and expense of 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 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 who were hired prior to 2008. 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
	2008			2007			2008			2007
Three months ended September 30:
Service cost	$	2,552		$	2,740		$	149		$	160
Interest cost		5,203			4,766			469			490
Expected return on plan assets		(5,274	)		(4,802	)		(391	)		(391	)
Transition obligation recognition		—			—			126			126
Amortization of prior service cost		164			164			—			—
Net loss recognition		800			792			(43	)		57

Net periodic benefit cost	$	3,445		$	3,660		$	310		$	442

Nine months ended September 30:
Service cost	$	7,657		$	8,219		$	446		$	480
Interest cost		15,609			14,297			1,407			1,469
Expected return on plan assets		(15,822	)		(14,406	)		(1,172	)		(1,173	)
Transition obligation recognition		—			—			379			378
Amortization of prior service cost		491			492			—			—
Net loss recognition		2,559			2,334			201			169

Net periodic benefit cost	$	10,494		$	10,936		$	1,261		$	1,323

AVISTA CORPORATION

NOTE 8. INCOME TAXES

The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns in certain jurisdictions, including Idaho, Oregon, Montana and California. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of the 2004 and 2005 tax years and all issues were resolved related to these years. The IRS is currently conducting an examination of the Company’s 2006 and 2007 federal income tax returns. This examination could result in a change in the liability for uncertain tax positions. However, an estimate of the range of any such possible change cannot be made at this time. The Company does not believe that any open tax years with respect to state income taxes could result in any adjustments that would be significant to the consolidated financial statements.

In August 2005, the Treasury Department issued regulations and the IRS issued a revenue ruling that affects the tax treatment by Avista Corp. of certain indirect overhead expenses. Avista Corp. had previously made a tax election to currently deduct certain indirect overhead costs, starting with the 2002 tax return, that were capitalized for financial accounting purposes. This election allowed Avista Corp. to take tax deductions resulting in a total reduction of approximately $40 million in current tax liabilities for 2002, 2003 and 2004. These current tax benefits were deferred on the balance sheet in accordance with the provisions of SFAS No. 109 and did not affect net income.

Due to the revenue ruling and related regulations, the IRS has disallowed the tax deduction of indirect overhead expenses during their examination of the Company’s 2001, 2002 and 2003 federal income tax returns. The Company believes that the tax deductions claimed on tax returns were appropriate based on the applicable statutes and regulations in effect at the time. Avista Corp. appealed the proposed IRS adjustment in April 2006. The Company repaid a portion of the previous tax deductions through tax payments in 2005, 2006 and 2008.

The Company estimated that its liability for unrecognized tax benefits was $22.6 million as of December 31, 2007. The liability primarily related to the indirect overhead expenses described above and was included in other non-current liabilities and deferred credits on the Consolidated Balance Sheet. The balance decreased due to the settlement of the indirect overhead expense issue. The amount did not impact the 2008 tax rate, as this deferred tax adjustment was offset by an adjustment to current income taxes payable.

On September 10, 2008, the Company entered into a Settlement Agreement (“Agreement”) with the Appeals Division of the IRS that would resolve all items noted during their audit of the Company’s 2001 through 2003 tax years, including indirect overhead expenses. The Agreement has been approved by the Joint Committee on Taxation and is currently going through final IRS processing. The net result will be a refund to the Company of approximately $14.7 million, plus interest. Based upon the Agreement, the Company accrued an estimated $5.7 million of interest income in the third quarter of 2008, and this amount has been included in other income – net in the Consolidated Statements of Income.

NOTE 9. SHORT-TERM BORROWINGS

The Company has a committed line of credit agreement with various banks in the total amount of $320.0 million with an expiration date of April 5, 2011. Under the credit agreement, the Company can request the issuance of up to $320.0 million in letters of credit. The Company had $85.0 million of borrowings outstanding as of September 30, 2008 and no borrowings outstanding as of December 31, 2007. Total letters of credit outstanding were $35.1 million as of September 30, 2008 and $34.8 million as of December 31, 2007. 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.

The committed line of credit agreement contains 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, 2008, the Company was in compliance with this covenant with a ratio of 3.2 to 1. The committed line of credit agreement also has 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 the end of any fiscal quarter. As of September 30, 2008, the Company was in compliance with this covenant with a ratio of 52.6 percent. If the proposed change in organization becomes effective (see Note 15), the committed line of credit will remain at Avista Corp.

In February 2008, Advantage IQ entered into a $12.5 million three-year credit agreement with a bank. Advantage IQ has the ability to increase the credit facility to $25 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $1.5 million of borrowings outstanding under the credit agreement as of September 30, 2008.

AVISTA CORPORATION

NOTE 10. LONG-TERM DEBT

The following details the interest rate and maturity dates of long-term debt outstanding as of September 30, 2008 and December 31, 2007 (dollars in thousands):


Maturity Year	Description	Interest Rate	September 30, 2008			December 31, 2007
2008	Secured Medium-Term Notes	6.06%-6.95%	$	25,000		$	45,000
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
2018	First Mortgage Bonds (1)	5.95%		250,000			—
2018	Secured Medium-Term Notes	7.39%-7.45%		22,500			22,500
2019	First Mortgage Bonds	5.45%		90,000			90,000
2023	Secured Medium-Term Notes	7.18%-7.54%		13,500			13,500
2028	Secured Medium-Term Notes	6.37%		25,000			25,000
2032	Secured Pollution Control Bonds (2)	5.00%		66,700			66,700
2034	Secured Pollution Control Bonds (2)	5.13%		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			896,700			666,700

2008	Unsecured Senior Notes	9.75%		—			272,860
2023	Unsecured Pollution Control Bonds	6.00%		4,100			4,100

	Total unsecured long-term debt			4,100			276,960

	Other long-term debt and capital leases			3,139			5,169

	Interest rate swaps			(14,563	)		1,083

	Unamortized debt discount			(1,547	)		(1,079	)

	Total			887,829			948,833
	Current portion of long-term debt			(108,916	)		(427,344	)

	Total long-term debt		$	778,913		$	521,489

(1)

On April 3, 2008, the Company issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $249.2 million (net of issuance discount and before Avista Corp.’s expenses), together with other available funds, were used to pay the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008.

(2)	These Secured Pollution Control Bonds are subject to remarketing on December 30, 2008. These bonds are included in the current portion of long-term debt because, if the bonds cannot be successfully remarketed on that date, the Company will be required to purchase the bonds.

NOTE 11. INTEREST RATE SWAP AGREEMENTS

Periodically, 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 hedges against fluctuations in future cash flows associated with changes in interest rates in accordance with SFAS No. 133.

In March 2008, the Company cash settled two interest rate swap agreements and paid a total of $16.4 million. These settlements were deferred as regulatory items (part of long-term debt) and will be amortized as a component of interest expense over the remaining ten year terms of the interest rate swap agreements (forecasted interest payments) in accordance with regulatory accounting practices. The Company did not have any interest rate swap agreements outstanding as of September 30, 2008.

NOTE 12. FAIR VALUE

As disclosed in Note 2, on January 1, 2008, the Company adopted the provisions of SFAS No. 157 related to its financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

AVISTA CORPORATION

The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

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

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

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to the Company’s needs.

As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the Consolidated Balance Sheet as of September 30, 2008 at fair value on a recurring basis (dollars in thousands):


	Total		Counterparty Netting			Level 1		Level 2		Level 3
Assets:
Energy commodity derivatives	$	114,382	$	(41,067	)	$	—	$	25,932	$	129,517
Deferred compensation assets		8,380		—			8,380		—		—

Total	$	122,762	$	(41,067	)	$	8,380	$	25,932	$	129,517

Liabilities:
Energy commodity derivatives	$	71,550	$	(41,067	)	$	—	$	91,664	$	20,953
Deferred compensation liabilities		8,380		—			8,380		—		—

Total	$	79,930	$	(41,067	)	$	8,380	$	91,664	$	20,953

Avista Utilities enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. These contracts are entered into as part of our management of loads and resources and certain contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in respective levels and the amount of derivative assets and liabilities disclosed on the Consolidated Balance Sheets and at Note 6 is due to netting arrangements with certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of our utility derivative commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, 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 6 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 $2.0 million.

AVISTA CORPORATION

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


	Three months ended September 30, 2008			Nine months ended September 30, 2008
Balance as of beginning of the period	$	150,971		$	98,943
Total gains or losses (realized/unrealized)
Included in net income		—			—
Included in other comprehensive income		—			—
Included in regulatory assets/liabilities (1)		(21,454	)		35,556
Purchases, issuances, and settlements, net		—			(4,982	)
Transfers to other categories		—			—

Balance as of September 30, 2008	$	129,517		$	129,517

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


	Three months ended September 30, 2008			Nine months ended September 30, 2008
Balance as of beginning of period	$	20,310		$	36,506
Total gains or losses (realized/unrealized)
Included in net income		—			—
Included in other comprehensive income		—			—
Included in regulatory assets/liabilities (1)		645			(13,848	)
Purchases, issuances, and settlements, net		(2	)		(1,705	)
Transfers to other categories		—			—

Balance as of September 30, 2008	$	20,953		$	20,953

(1)

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

NOTE 13. 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,
	2008			2007			2008			2007
Numerator:
Net income (loss)	$	7,359		$	(3,875	)	$	56,135		$	24,402
Subsidiary earnings adjustment for dilutive securities		(61	)		(71	)		(212	)		(279	)

Adjusted net income (loss) for computation of diluted earnings per common share	$	7,298		$	(3,946	)	$	55,923		$	24,123

Denominator:
Weighted-average number of common shares outstanding-basic		53,773			52,834			53,366			52,769
Effect of dilutive securities:
Contingent stock awards *		267			—			197			187
Stock options *		165			—			202			311

Weighted-average number of common shares outstanding-diluted		54,205			52,834			53,765			53,267

Total earnings (loss) per common share, basic	$	0.14		$	(0.07	)	$	1.05		$	0.46

Total earnings (loss) per common share, diluted	$	0.13		$	(0.07	)	$	1.04		$	0.45

Due to the net loss for the three months ended September 30, 2007, the common stock equivalents from outstanding contingent stock awards and stock options are not included in the calculation for weighted average number of common shares outstanding for diluted loss per common share because the effect is antidilutive. If such shares were included in the calculation, the total weighted average number of common shares outstanding would be increased by 318,000 for the three months ended September 30, 2007.

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Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 291,550 for the three and nine months ended September 30, 2008, and 32,200 for the nine months ended September 30, 2007. 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 14. 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. With respect to matters discussed in this Note that affect Avista Energy (particularly the California Refund Proceeding), any potential liabilities or refunds remain at Avista Corp. and/or its subsidiaries and were not assumed by Shell Energy and/or its affiliates.

Federal Energy Regulatory Commission Inquiry

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

California Refund Proceeding

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

In 2001, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the CalPX and the CalISO. As a result, the CalPX and the CalISO failed to pay various energy sellers, including Avista Energy. Both PG&E and the CalPX declared bankruptcy in 2001. In March 2002, SCE paid its defaulted obligations to the CalPX. In April 2004, PG&E paid its defaulted obligations into an escrow fund in accordance with its bankruptcy reorganization. Funds held by the CalPX and in the PG&E escrow fund are not subject to release until the FERC issues an order directing such release in the California refund proceeding. As of September 30, 2008, 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.

AVISTA CORPORATION

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

In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 Refund Proceeding, but remanded to the FERC its decision not to consider a FPA section 309 remedy for tariff violations prior to October 2, 2000. The Ninth Circuit also granted California’s petition for review challenging the FERC’s exclusion of the energy exchange transactions as well as the FERC’s exclusion of forward market transactions from the California refund proceedings. Petitions for rehearing were filed on November 16, 2007. It is unclear at this time what impact, if any, the Court’s remand might have on Avista Energy. The second round of issues and their corresponding briefing schedules have not yet been set by the Ninth Circuit.

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

Any potential liabilities or refunds owed by or to Avista Energy in the California Refund Proceeding were retained by Avista Corp. and/or its subsidiaries and have not been transferred to Shell Energy and/or its affiliates. Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent of the Company’s liability, if any. However, based on information currently known to the Company’s management, the Company does not expect that the California refund proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. This is primarily due to the fact that FERC orders have stated that any refunds will be netted against unpaid amounts owed to the respective parties and the Company does not believe that refunds would exceed unpaid amounts owed to the Company.

Pacific Northwest Refund Proceeding

In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market sales of wholesale energy in the Pacific Northwest between December 25, 2000, and June 20, 2001, were just and reasonable. During the hearing, Avista Corp., doing business as Avista Utilities, and Avista Energy vigorously opposed claims that rates for spot market sales were unjust and unreasonable and that the imposition of refunds would be appropriate. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of refunds. These equitable factors included the fact that the participants in the Pacific Northwest market include not only utilities and other entities that are subject to FERC jurisdiction, but also a very substantial number of governmental entities that are not subject to FERC jurisdiction with respect to wholesale sales and thus could not be ordered by the FERC to make refunds based on existing law. Seven petitions for review were filed with the Ninth Circuit challenging the merits of the FERC’s decision not to order refunds and raising procedural issues.

On August 24, 2007, the Ninth Circuit issued its opinion on the consolidated petitions for review of the Pacific Northwest refund proceeding. The Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new evidence of market manipulation in the California energy market and its potential ties to the

AVISTA CORPORATION

Pacific Northwest energy market and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC’s findings must be reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential relief for transactions involving energy that was purchased in the Pacific Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. Requests for rehearing were filed on December 17, 2007.

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

California Attorney General Complaint

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

In March 2008, the FERC issued an order establishing a trial-type hearing to address “whether any individual public utility seller’s violation of the Commission’s market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.” Purchasers in the California markets will be allowed to present evidence that “any seller that violated the quarterly reporting requirement failed to disclose an increased market share sufficient to give it the ability to exercise market power and thus cause its market-based rates to be unjust and unreasonable.” In particular, the parties are directed to address whether the seller at any point reached a 20 percent generation market share threshold, and if the seller did reach a 20 percent market share, whether other factors were present to indicate that the seller did not have the ability to exercise market power. Based on information currently known to the Company’s management, the Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or cash flows.

State of Montana Proceedings

In June 2003, the Attorney General of the State of Montana (Montana AG) filed a complaint in the Montana District Court on behalf of the people of Montana and the Flathead Electric Cooperative, Inc. against numerous companies, including Avista Corp. The complaint alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. This case was subsequently moved to the United States District Court for the District of Montana; however, it has since been remanded back to the Montana District Court.

The Montana AG also petitioned the Montana Public Service Commission (MPSC) to fine public utilities $1,000 a day for each day it finds they engaged in alleged “deceptive, fraudulent, anticompetitive or abusive practices” and order refunds when consumers were forced to pay more than just and reasonable rates. In February 2004, the MPSC issued an order initiating investigation of the Montana retail electricity market for the purpose of determining whether there is evidence of unlawful manipulation of that market. The Montana AG has requested specific information from Avista Energy and Avista Corp. regarding their transactions within the state of Montana during the period from January 1, 2000 through December 31, 2001.

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Because the resolution of these proceedings 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 that these proceedings will have a material adverse effect on its financial condition, results of operations or cash flows.

Colstrip Generating Project Complaints

In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed complaints against the owners of the Colstrip Generating Project (Colstrip) in Montana District Court. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The plaintiffs alleged damages to buildings as a result of foundation settlement caused by seepage from Colstrip’s freshwater surge pond. Avista Corp.’s ownership interest in the freshwater surge pond is approximately 11 percent. The plaintiffs also alleged contamination and trespass damages resulting from leakage from several of Colstrip’s process ponds, most of which are for Units 1 & 2 ponds of which Avista Corp. has no ownership interest. In April 2008, the owners of Colstrip reached a settlement with the plaintiffs. Under the settlement, Avista Corp.’s portion of the payment to the plaintiffs was $2.1 million. Avista Corp. may be able to recover a portion of this payment through insurance. The Company filed petitions with the WUTC and the IPUC to defer any payments as a regulatory asset, in order to allow for potential future recovery through future rates. On September 12, 2008, the IPUC issued its order approving the Company’s petition; the matter is still pending before the WUTC. The Company believes it is probable that such costs will ultimately be recovered through the ratemaking process.

In March 2007, two families that own property near the holding ponds from Units 3 & 4 of Colstrip filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. The plaintiffs allege that the holding ponds and remediation activities have adversely impacted their property. They allege contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to their property. They also seek punitive damages, attorney’s fees and other relief similar to that asserted in the litigation described above. No trial date has been set. Because the resolution of this complaint remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company’s liability. However, based on information currently known to the Company’s management, the Company does not expect this complaint will have a material adverse effect on its financial condition, results of operations or cash flows.

Colstrip Royalty Claim

Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a Transportation Agreement. Avista Corp. owns a 15 percent interest in Colstrip Units 3 & 4. The Minerals Management Service (MMS) of the United States Department of the Interior issued orders to WECO to pay additional royalties concerning coal delivered to Colstrip Units 3 & 4 via the conveyor belt. The owners of Colstrip Units 3 & 4 take delivery of the coal at the beginning of the conveyor belt. The orders assert that additional royalties are owed to MMS as a result of WECO not paying royalties in connection with revenue received by WECO from the owners of Colstrip Units 3 & 4 under the Transportation Agreement during the period October 1, 1991 through December 31, 2004. WECO’s appeal to the MMS for the period through 2001 was substantially denied in March 2005; WECO appealed the orders pertaining to the periods up to 2001 to the Board of Land Appeals of the U.S. Department of the Interior, which appeal was denied on September 12, 2007. WECO also filed an appeal with the MMS pertaining to the period from 2002 to 2004. The owners of Colstrip Units 3 & 4 are monitoring the appeal process between WECO and MMS. The state of Montana also filed claims assessing additional coal production taxes on Coal Transportation Agreement revenues collected by WECO from the owners of Colstrip Units 3 & 4. Settlement of production tax claims has recently occurred between WECO and the Montana Department of Revenue. WECO and the owners of Colstrip Units 3 & 4 have agreed to a cost sharing agreement for the payment of the settlements owed to the Montana Department of Revenue for coal production taxes and for the MMS royalty claims as they are determined through litigation or settlement. Avista Corp. estimates that its maximum share of the royalties, taxes and interest alleged would be approximately $1.8 million. Based on information currently known to the Company’s management, the Company does not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. However, the Company would most likely seek recovery, through the ratemaking process, of any amounts paid.

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,

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Compensation, and Liability Act, commonly referred to as the federal “Superfund” law, which provides for joint and several liability. The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible parties, including Avista Corp., signed an Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS). The total cost of the RI/FS is estimated to be $1.2 million and will take approximately 2 1/2 years to complete. The actual cleanup, if any, will not occur until the RI/FS is complete. Based on the review of its records related to Harbor Oil, the Company does not believe it is a major contributor to this potential environmental contamination based on the de minimus volume of waste oil it delivered to the Harbor Oil site. However, there is currently not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred. As such, it is not possible to make an estimate of any liability at this time.

Lake Coeur d’Alene

In July 1998, the United States District Court for the District of Idaho issued its finding that the Coeur d’Alene Tribe of Idaho (Tribe) owns, among other things, portions of the bed and banks of Lake Coeur d’Alene (Lake) lying within the current boundaries of the Coeur d’Alene Reservation. This action was brought by the United States on behalf of the Tribe against the state of Idaho. The Company was not a party to this action. The United States District Court decision was affirmed by the Ninth Circuit. The United States Supreme Court affirmed this decision in June 2001. This ownership decision results in, among other things, the Company being liable to the Tribe for compensation for the use of reservation lands under Section 10(e) of the Federal Power Act.

The Company’s Post Falls Hydroelectric Generating Station (Post Falls), a facility constructed in 1906 with annual generation of 10 aMW, utilizes a dam on the Spokane River downstream of the Lake which controls the water level in the Lake for portions of the year (including portions of the lakebed owned by the Tribe). The Company has other hydroelectric facilities on the Spokane River downstream of Post Falls, but these facilities do not affect the water level in the Lake. The Company and the Tribe are engaged in discussions related to past and future compensation (which may include interest) for use of the portions of the bed and banks of the Lake, which are owned by the Tribe. If the parties cannot agree on the amount of compensation, the matter could result in litigation. The amount of compensation that the Company will ultimately pay and the terms of such payment will become known and estimable based on the outcome of the discussions with the Tribe and approval by the necessary governmental authorities, including the Department of Interior. The Company intends to seek recovery, through the ratemaking process, of any amounts paid.

Spokane River Relicensing

The Company owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls, which have a total present capability of 155.7 MW) are under one FERC license and are referred to as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. Since the FERC was unable to issue new license orders prior to the August 1, 2007 (and subsequent August 1, 2008) expiration of the current license, an annual license was issued for all five plants, in effect extending the current license and its conditions until August 1, 2009. The Company has no reason to believe that Spokane River Project operations will be interrupted in any manner relative to the timing of the FERC’s actions.

The Company filed a Notice of Intent to Relicense in July 2002. The formal consultation process involving planning and information gathering with stakeholder groups lasted through July 2005, when the Company filed its new license applications with the FERC. The Company requested the FERC to consider a license for Post Falls, which has a present capability of 18 MW, that is separate from the other four hydroelectric plants because Post Falls presents more complex issues that may take longer to resolve than those relating to the rest of the Spokane River Project. If granted, the new licenses would have terms of 30 to 50 years. In the license applications, the Company proposed a number of measures intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River.

Since the Company’s July 2005 filing of applications to relicense the Spokane River Project, the FERC has continued various stages of processing the applications. In May 2006, the FERC issued a notice requesting other parties to provide terms and conditions regarding the two license applications. In response to that notice, a number of parties (including the Coeur d’Alene Tribe, the state of Idaho, Washington state agencies, and the United States Department of Interior (DOI)) filed either recommended terms and conditions, pursuant to Sections 10(a) and 10(j) of the Federal Power Act (FPA), or mandatory conditions related to the Post Falls application, pursuant to Section 4(e) of the FPA. The Company’s initial estimate of the potential cost of the conditions proposed for Post Falls total between $400 million and $500 million over a 50-year period. For the rest of the Spokane River Project, which is located in Washington, the Company’s initial estimate of the cost of meeting the recommended conditions, should they be included in a final license, totaled between $175 million and $225 million over a 50-year period. These cost estimates were based on the preliminary conditions and recommendations.

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The Company requested a trial-type hearing in front of an Administrative Law Judge (ALJ) on facts related to the DOI’s mandatory conditions for Post Falls. In January 2007, the ALJ issued his ruling regarding the Company’s challenge of the facts. The Company believes that the ALJ’s findings supported, in several key areas, its analysis of the facts at hand. The ALJ’s factual findings also supported the DOI’s analysis in certain areas as well.

The DOI issued final mandatory conditions for Post Falls on May 7, 2007, which reflected the findings of the ALJ. Most significantly, the DOI dropped an earlier proposed fishery condition. However, the DOI increased obligations that the Company could incur in other areas, such as wetlands restoration.

In July 2007, the FERC issued a Final Environmental Impact Statement (FEIS) after review and consideration of comments. This is the last administrative step for the FERC before the issuance of license orders; however, the FERC cannot proceed until Clean Water Act issues as disclosed below are resolved. The Company continues to review the FEIS and related documents. While the Company believes the ultimate cost of relicensing will be less than its earlier projections as disclosed above, the Company has not finalized specific new cost estimates at this point.

The relicensing process also triggered review under the Endangered Species Act. In the FEIS, the FERC analyzed potential project impacts on listed and threatened endangered species, and determined that the proposed action and continued operation of Post Falls and the rest of the Spokane River Project is not likely to adversely affect any threatened or endangered species. The Company prepared a draft Biological Assessment in 2005. The FERC issued a Biological Assessment and formally requested concurrence from the United States Department of Fish and Wildlife Service (USFWS). After discussions with Avista, the USFWS concurred that the Project is not likely to adversely affect any listed and threatened endangered species. This concluded the required consultation pursuant to the Endangered Species Act.

The Company must receive Clean Water Act Certification (CWAC) from the states of Idaho and Washington for the Spokane River Project. Applications for such certification were filed in July 2006 with each state. The Idaho Department of Environmental Quality (IDEQ) subsequently issued its final CWAC on June 5, 2008. The Idaho CWAC was based on a settlement agreement between IDEQ, Idaho Department of Fish and Game, and Avista Corp. The Washington Department of Ecology (DOE) issued its final CWAC on June 10, 2008. The Company and two other parties appealed the Washington CWAC on a number of accounts. In addition to the appeals, the Spokane Tribe requested the FERC proceed with the Clean Water Act 401(a)(2) process, in which the FERC and the EPA would determine whether or not the Washington CWAC meets the Spokane Tribe’s water quality standards. Avista and the Tribe have met to discuss their concerns. As a result the 401(a)(2) process was concluded.

The FERC is precluded from issuing a license order until the CWACs are issued or waived by the states, or any appeals resolved. The Company cannot predict the schedule for these final phases of relicensing.

The total annual operating and capitalized costs associated with the relicensing of the Spokane River Project will become better known and estimable as the process continues. The Company will continue to seek recovery, through the ratemaking process, of all such operating and capitalized costs.

Clark Fork Settlement Agreement

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

The GSCP provides for the opening and modification of one and, potentially, both of the two existing diversion tunnels built when Cabinet Gorge was originally constructed. When river flows exceed the capacity of the powerhouse turbines, the excess flows would be diverted to the tunnels rather than released over the spillway. The Company has undertaken physical and computer modeling studies to confirm the feasibility and likely effectiveness of the tunnel solution. Analysis of the predicted total dissolved gas (TDG) performance indicates that the tunnels will not meet the performance criteria anticipated in the GSCP. In August 2007, the Gas Supersaturation Subcommittee concluded that the tunnel project does not meet the expectations of the GSCP and is not an acceptable project. As a result, the Company has met and will continue meeting with key stakeholders to review and amend the GSCP which includes developing alternatives to the construction of the tunnels. Through a collaborative process

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with key stakeholders, the Company has expended $5.0 million on the tunnel project. The Company is seeking recovery, through the ratemaking process, of the costs to study the dissolved atmospheric gas levels. The IPUC has accepted the recovery of these costs through rates. The Company’s multi-party settlement now pending before the WUTC also includes recovery of such costs.

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 particular, the EPA finalized mercury emission regulations that will affect coal-fired generation plants, including Colstrip. The new EPA regulations establish an emission trading program to take effect beginning in January 2010, with a second phase to take effect in 2018. In addition, in 2006, the Montana Department of Environmental Quality (Montana DEQ) adopted final rules for the control of mercury emissions from coal-fired plants that are more restrictive than EPA regulations. 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. In February 2008, the United States Court of Appeals for the District of Columbia overturned the EPA’s mercury emission regulations. However, this ruling is not expected to affect the Company’s current plans to comply with the more restrictive regulations adopted by the Montana DEQ as described below.

Compliance with these 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. Although the mercury reduction targets as mandated by the Montana DEQ have not been achieved, the owners of Colstrip are encouraged with the preliminary results and believe it should be possible to achieve the required emission levels with further mercury control system optimization. Preliminary estimates indicate that the Company’s share of installation capital costs would be $1.5 million and annual operating costs would increase by $2.9 million (beginning in late-2009). The Company will continue to seek recovery, through the ratemaking process, of the costs to comply with various air quality requirements.

Residential Exchange Program

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

In November 2007, the region’s private and public utilities reached agreement on a recommendation to the BPA related to the appropriate level of benefits for customers served by private utilities, including the resolution of outstanding legal issues associated with the May 3, 2007 Ninth Circuit opinions.

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

AVISTA CORPORATION

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

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 15. POTENTIAL HOLDING COMPANY FORMATION

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

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

The IPUC accepted a stipulation entered into between Avista Corp. and the IPUC Staff that sets forth a variety of conditions, which would serve to segregate the Company’s utility operations from the other businesses conducted by the holding company. The stipulation would require Avista Corp. to maintain certain common equity levels as part of its capital structure. Avista Corp. committed to increase its actual utility common equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008, which is consistent with provisions of the Company’s Washington general rate case implemented on January 1, 2006. The calculation of the utility equity component is essentially the ratio of Avista Corp.’s total common equity to total capitalization excluding, in each case, Avista Corp.’s investment in Avista Capital. The utility equity component was approximately 47 percent as of September 30, 2008. In addition, IPUC approval would be required for any dividend from Avista Corp. to the holding company that would reduce utility common equity below 25 percent of total capitalization which, for this purpose, includes long and short-term debt, capitalized lease obligations and preferred and common equity.

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

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

NOTE 16. 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 other investments and operations of various subsidiaries as well as certain other operations of Avista Capital.

In prior periods, the Company had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy. On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the

AVISTA CORPORATION

majority of the operations of this segment. This business still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant. The majority of the rights and obligations of the power purchase agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010, the Company expects these rights and obligations will be transferred to Avista Utilities, subject to future regulatory approval. These remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. The historical activities were reclassified to the Other category in accordance with the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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, 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 taxes		5,542			1,007		601			1,608			—			7,150
Net income (loss)		6,451			1,340		(432	)		908			—			7,359
Capital expenditures		59,199			498		80			578			—			59,777
For the three months ended September 30, 2007:
Operating revenues	$	243,798		$	12,193	$	11,671		$	23,864		$	—		$	267,662
Resource costs		144,059			—		6,259			6,259			—			150,318
Other operating expenses		50,126			8,145		5,720			13,865			—			63,991
Depreciation and amortization		21,551			609		445			1,054			—			22,605
Income (loss) from operations		13,050			3,439		(753	)		2,686			—			15,736
Interest expense (2)		21,406			30		132			162			(185	)		21,383
Income taxes		(3,171	)		1,215		(184	)		1,031			—			(2,140	)
Net income (loss)		(5,574	)		2,077		(378	)		1,699			—			(3,875	)
Capital expenditures		56,321			387		220			607			—			56,928
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 taxes		31,922			3,070		552			3,622			—			35,544
Net income (loss)		51,791			4,685		(341	)		4,344			—			56,135
Capital expenditures		150,071			2,452		175			2,627			—			152,698
For the nine months ended September 30, 2007:
Operating revenues	$	926,061		$	34,607	$	70,186		$	104,793		$	—		$	1,030,854
Resource costs		549,565			—		62,372			62,372			—			611,937
Other operating expenses		149,358			24,601		28,572			53,173			—			202,531
Depreciation and amortization		63,939			1,805		1,694			3,499			—			67,438
Income (loss) from operations		109,142			8,201		(22,452	)		(14,251	)		—			94,891
Interest expense (2)		65,456			183		728			911			(750	)		65,617
Income taxes		17,236			2,904		(6,004	)		(3,100	)		—			14,136
Net income (loss)		31,610			4,971		(12,179	)		(7,208	)		—			24,402
Capital expenditures		148,947			1,639		957			2,596			—			151,543
Total Assets:
As of September 30, 2008	$	3,161,066		$	150,230	$	73,788		$	224,018		$	—		$	3,385,084
As of December 31, 2007		3,009,499			108,929		71,369			180,298			—			3,189,797

(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 consolidated balance sheet of Avista Corporation and subsidiaries (the “Corporation”) as of September 30, 2008, and the related consolidated statements of income, and of comprehensive income for the three-month and nine-month periods ended September 30, 2008 and 2007, and of cash flows for the nine-month periods ended September 30, 2008 and 2007. 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 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, 2007, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP

Seattle, Washington

November 3, 2008

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,

•

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:

•

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

•

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;

•

weather conditions and their 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;

•

changes in wholesale energy prices that can affect, among other things, cash needed to purchase electricity, natural gas for our retail customers and natural gas fuel for electric generation, and the value of surplus energy sold;

•

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 that we have deferred; and the possible reluctance of regulators to grant timely and adequate rate increases in an economic slowdown;

•

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 relicense and 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;

•

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

AVISTA CORPORATION

•

blackouts or disruptions of interconnected transmission systems;

•

the potential for future 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 economic conditions in our service territory and the United States in general, including inflation or deflation;

•

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

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

Potential Holding Company Formation

In May 2006, our shareholders approved a proposal to proceed with a statutory share exchange, which would change our organization to a holding company structure. If the implementation of the holding company structure is approved by regulators on terms acceptable to us, it may be completed sometime in 2009. See further information at “Note 15 of the Notes to Consolidated Financial Statements.”

Business Segments

We have two reportable business segments as follows:

•

Avista Utilities – generation, transmission and distribution of electric energy and distribution of natural gas to retail customers, as well as wholesale purchases and sales of energy commodities. Avista Utilities is an operating division of Avista Corp. comprising our regulated utility operations.

•

Advantage IQ – facility information and cost management services for multi-site customers. The activities of this business segment are conducted by Advantage IQ, an indirect subsidiary of Avista Corp.

In prior periods, we had a reportable Energy Marketing and Resource Management segment. The activities of this business segment were conducted primarily by Avista Energy, an indirect subsidiary of Avista Corp. On June 30,

AVISTA CORPORATION

2007, Avista Energy and Avista Energy Canada completed the sale of substantially all of their contracts and ongoing operations to Shell Energy, as well as to certain other subsidiaries of Shell Energy. Completion of this transaction effectively ended the majority of the operations of this segment. This business still owns natural gas storage facilities and has operating revenues and resource costs related to the power purchase agreement for the Lancaster Plant. The Lancaster Plant is owned by an unrelated third-party and all of the output from the plant is contracted to Avista Energy through 2026. The majority of the rights and obligations of the power purchase agreement were assigned to Shell Energy through the end of 2009. Beginning in 2010, we expect these rights and obligations will be transferred to Avista Utilities, subject to future regulatory approval. These remaining activities do not represent a reportable business segment in 2008 and are included in the Other category for segment reporting purposes. The historical activities were reclassified to the Other category in accordance with the provisions of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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

Avista Energy, Advantage IQ and the various other companies are subsidiaries of Avista Capital, which is a direct, wholly owned subsidiary of Avista Corp. Our total common stockholders’ equity was $978.7 million as of September 30, 2008, of which $75.3 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,
	2008			2007			2008			2007
Avista Utilities	$	6,451		$	(5,574	)	$	51,791		$	31,610
Advantage IQ		1,340			2,077			4,685			4,971
Other		(432	)		(378	)		(341	)		(12,179	)

Net income (loss)	$	7,359		$	(3,875	)	$	56,135		$	24,402

Executive Level Summary

Overall

Our operating results and cash flows are primarily derived from:

•

regulated utility operations (Avista Utilities), and

•

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

In late 2007 and early 2008, Moody’s Investors Service and Standard & Poor’s upgraded our credit ratings, which resulted in an investment grade rating for our senior unsecured debt and corporate rating from each of these rating agencies. The upgrades reflect several steps taken over the past few years to lower our business risk profile and improve financial metrics. The most recent significant steps were the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007 and our general rate case settlement in Washington implemented on January 1, 2008.

Although we are pleased with the credit ratings upgrades, we are at the lower end of the investment grade category and will continue to work towards improving our ratings. We intend to continue to focus on improving earnings and operating cash flows, controlling costs, reducing debt and debt service costs, while working to improve our credit ratings.

Effective July 2, 2008, Advantage IQ acquired Cadence Network, a Cincinnati-based energy and expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in Advantage IQ. The total value of the transaction was $37.1 million. The acquisition of Cadence Network was funded with the issuance of Advantage IQ common stock, which is subject to redemption as described below. We are planning to monetize at least a portion of our investment in Advantage IQ during the next two to four years. The potential monetization of Advantage IQ could be completed through an initial public offering or sale of the business depending on future market conditions, growth of the business and other factors.

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. Based on the estimated fair market value of Advantage IQ common stock held by the previous owners of Cadence Network, we had a liability of $31.1 million as of September 30, 2008 related to this potential redemption obligation.

AVISTA CORPORATION

Our net income was $7.4 million for the three months ended September 30, 2008, an increase from a net loss of $3.9 million for the three months ended September 30, 2007. This increase was primarily due to increased earnings at Avista Utilities, primarily due to the implementation of a general rate increase in Washington, interest income from an income tax settlement, as well as an impairment and regulatory disallowance recorded in the third quarter of 2007. This was partially offset by decreased earnings at Advantage IQ, primarily due to our reduced ownership interest in the business and the amortization of intangible assets resulting from the Cadence Network acquisition. Our net income was $56.1 million for the nine months ended September 30, 2008, an increase from $24.4 million for the nine months ended September 30, 2007. This was primarily due to increased earnings at Avista Utilities and the $11.8 million net loss at Avista Energy for 2007.

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

Although our service territory appears to be faring better than certain other parts of the country we are not immune from the turbulence affecting the national and international economy and financial markets. We are observing stable to small declines in employment throughout our service area due to cutbacks in the construction and financial services sectors. However, agriculture, mining, health care and manufacturing sectors, our primary industries, continue to perform well, while lumber markets continue to struggle.

Avista Utilities

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

•

weather conditions,

•

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

•

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

•

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

•

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.

Our hydroelectric generation was 96 percent of normal in 2007. Our hydroelectric generation was below normal (based on a 70-year average) for six of the past eight years. Due to colder than normal temperatures and later than normal spring runoff, our hydroelectric generation was slightly below normal for the first nine months of 2008. Actual hydroelectric generation for the full year of 2008 will depend on precipitation, temperatures and other variables during the fourth quarter.

Our utility net income was $6.5 million for the three months ended September 30, 2008, an increase from a net loss of $5.6 million for the three months ended September 30, 2007 primarily due to an increase in gross margin (operating revenues less resource costs). Also contributing to the increase in net income was $5.7 million (pre-tax) of interest income, partially offset by $1.4 million (pre-tax) of interest expense, related to income tax settlements recorded during the third quarter of 2008. Also during the third quarter of 2007, we recorded a pre-tax impairment charge of $2.3 million related to a turbine and $3.8 million of unamortized debt repurchase costs were disallowed as part of our Washington general rate case settlement. The increase in gross margin was primarily due to the implementation of the general rate increase in Washington effective January 1, 2008 and lower electric resource costs recognized under the Energy Recovery Mechanism (ERM) in Washington. The lower electric resource costs were primarily due to higher than normal hydroelectric generation (primarily in July) and the resetting of the base level of power supply costs in the Washington general rate case. As a result, we recognized a benefit of $0.1 million under the ERM for the third quarter of 2008 compared to an expense of $5.2 million for the third quarter of 2007.

Our utility net income was $51.8 million for the nine months ended September 30, 2008, an increase from $31.6 million for the nine months ended September 30, 2007 primarily due to an increase in gross margin (operating revenues less resource costs). Consistent with the quarterly change, the increase in gross margin was primarily due to the implementation of the general rate increase in Washington effective January 1, 2008. The effects of the Washington general rate increase were partially offset by below normal hydroelectric generation as well as increased purchased power and fuel costs. As such, we recognized an expense of $7.3 million under the ERM for the nine months ended September 30, 2008 compared to an expense of $7.6 million for the nine months ended September 30, 2007. The increase in net income was also partially due to a decrease in interest expense and the turbine impairment and disallowance of unamortized debt repurchase costs in the third quarter of 2007 as described above.

AVISTA CORPORATION

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 $150.1 million for the nine months ended September 30, 2008. We expect utility capital expenditures to be approximately $200 million for 2008.

Advantage IQ

Advantage IQ had net income of $1.3 million for the three months ended September 30, 2008, a decrease from $2.1 million for the three months ended September 30, 2007. Advantage IQ’s net income was $4.7 million for the nine months ended September 30, 2008, a decrease from $5.0 million for the nine months ended September 30, 2007. This was primarily due to the decrease in our ownership percentage in the business with the acquisition of Cadence Network effective July 2, 2008 and an increase in amortization of intangible assets (related to the Cadence acquisition). As a result of the acquisition of Cadence Network and the lower short-term interest rates as compared to 2007 (which decreases interest revenue), net income will most likely decrease slightly for the full year of 2008 as compared to 2007. Customer growth and operating efficiencies are expected to be offset by the decrease in our ownership percentage in the business, the amortization of intangible assets and a decrease in Advantage IQ’s interest revenue.

Other Businesses

Over time as opportunities arise, we plan to dispose of assets and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that fit with our overall corporate strategy. The net loss for these operations was $0.4 million for the three months ended September 30, 2008 compared to $0.4 million for the three months ended September 30, 2007. The net loss was $0.3 million for the nine months ended September 30, 2008 compared to a net loss of $12.2 million for the nine months ended September 30, 2007. The net loss for the nine months ended September 30, 2007 was primarily due to Avista Energy.

Liquidity and Capital Resources

We need to access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. The recent events in the financial markets have resulted in companies having limited access to capital on reasonable terms and have resulted in a significant increase in borrowing rates for corporations. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.

As of November 5, 2008, we had received commitments from four banks totaling $150 million for a new 364-day bank facility at a reasonable cost. The Company is continuing to seek additional commitments from other banks. Closing, subject to completion of the necessary documentation, is expected by the end of November 2008. We are committed to maintaining adequate liquidity and will continue to utilize cash flows from operations, long-term debt and common stock issuances to fund our capital expenditures and maturing debt, and use short-term debt for these purposes on an interim basis.

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)
The Bank of New York	$	45.0
Union Bank of California, N.A.	$	45.0
Wells Fargo Bank	$	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
Goldman Sachs Credit Partners, L.P.	$	15.0
Societe Generale	$	15.0
First Commercial Bank, New York	$	10.0
Bank Hapoalim B.M., New York Branch	$	10.0

We had $85.0 million of cash borrowings and $35.1 million in letters of credit outstanding as of September 30, 2008, under our $320.0 million committed line of credit.

AVISTA CORPORATION

In March 2008, we amended our accounts receivable sales facility with Bank of America, N.A. to extend the termination date to March 2009. Under this facility, we can sell without recourse, on a revolving basis, up to $85.0 million of accounts receivable. Based upon calculations under this agreement, we had the ability to sell up to $57.0 million as of September 30, 2008. We had sold $54.0 million of accounts receivable under this facility as of September 30, 2008.

As of September 30, 2008, we had $202.9 million of available liquidity under our $320.0 million committed line of credit and $85.0 million revolving accounts receivable sales facility.

During the first nine months of 2008 debt maturities were $295.0 million, the majority being the $273 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. On April 3, 2008, we issued $250 million (net proceeds of $249.2 million before Company expenses) of 5.95 percent First Mortgage Bonds to fund a significant portion of this debt that matured.

The current portion of long-term debt includes $83.7 million of Secured Pollution Control Bonds that are subject to remarketing on December 30, 2008. If the Secured Pollution Control Bonds cannot be successfully remarketed on that date, we will be required to purchase the bonds.

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 (total net proceeds of $16.6 million) under this sales agency agreement during the third quarter of 2008. These were our first issuances under the sales agency agreement. We will continue to evaluate issuing common stock and may issue common stock under this sales agency agreement in future periods.

Due to recent market conditions and the decline in the fair value of pension plan assets, our contributions to the pension plan in 2009 could increase significantly as compared to the $28 million we contributed in 2008. The final determination of pension plan contributions for 2009 and future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We believe that we have adequate liquidity to meet our pension plan funding obligations for 2009.

Avista Utilities – Regulatory Matters

General Rate Cases

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

•

provide for recovery of operating costs and capital investments, and

•

more closely align earned returns with those allowed by regulators.

With regards to the timing and plans for future filings, the assessment of our need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include in-service dates of major capital investments and the timing of changes in major revenue and expense items. Primarily due to the significant amount of capital investments we are making in our utility infrastructure and increasing operating costs, we are planning to file general rate cases in each of our jurisdictions before the end of the first quarter of 2009. 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 2008	8.20	%	10.2	%	46	%
Idaho electric and natural gas	October 2008	8.45	%	10.2	%	48	%
Oregon natural gas	April 2008	8.21	%	10.0	%	50	%

As approved by the WUTC, on January 1, 2008, electric rates for our Washington customers increased by an average of 9.4 percent, which is designed to increase annual revenues by $30.2 million. As part of this general rate increase, the base level of power supply costs used in the ERM calculations was updated. Also, on January 1, 2008, natural gas rates increased by an average of 1.7 percent, which is designed to increase annual revenues by $3.3 million.

In September 2008, Avista and other parties entered into a settlement stipulation with respect to its general rate case that was filed with the WUTC in March 2008. Other parties to the settlement stipulation are the Staff of the WUTC, Northwest Industrial Gas Users, and the Energy Project. The recommendations of these parties to approve the settlement are not binding on the WUTC. The Industrial Customers of Northwest Utilities (ICNU) joined in portions of the settlement and has filed testimony in response to other portions of the settlement and our original filing. This settlement stipulation is subject to approval by the WUTC. The Public Counsel Section of the Washington Attorney

AVISTA CORPORATION

General’s Office (Public Counsel) did not join in the settlement stipulation and has filed testimony in response to the settlement stipulation and our original filing. The parties to the settlement stipulation have filed rebuttal testimony with respect to the testimony of ICNU and Public Counsel and evidentiary hearing before the WUTC is scheduled for November 6 and 7, 2008.

As agreed to in the settlement, base electric rates for the Company’s Washington customers would increase by an average of 9.1 percent, which is designed to increase annual revenues by $32.5 million. Base natural gas rates for the Company’s Washington customers would increase by an average of 2.4 percent, which is designed to increase annual revenues by $4.8 million. If approved by the WUTC, the new electric and natural gas rates would become effective on January 1, 2009. We expect to receive an order from the WUTC in December 2008.

The Company’s original request in March 2008 was for base electric rate increases averaging 10.3 percent, which was designed to increase annual revenues by $36.6 million. In July 2008, the Company filed an update to its demonstrated need for an electric rate increase, primarily to reflect an increase in natural gas fuel costs. Although the update justified an electric revenue requirement of $47.4 million compared to the Company’s original request of $36.6 million, the Company did not revise its original revenue increase request. In March 2008, the Company’s original request was to increase base natural gas rates by an average of 3.3 percent, which was designed to increase annual revenues by $6.6 million.

The settlement is 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. The Company’s 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.

As part of the general rate case settlement agreement that was modified and approved by the WUTC in December 2005, we agreed to increase the utility equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008. If we do not meet those targets, it could result in a reduction to base rates of 2 percent for each target. The calculation of the utility equity component is essentially the ratio of our total consolidated common equity to total capitalization excluding, in each case, our investment in Avista Capital. The utility equity component was approximately 47 percent as of September 30, 2008.

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

Our original request was for base electric rate increases averaging 16.7 percent, which was designed to increase annual revenues by $32.3 million. We also requested to increase base natural gas rates by an average of 5.8 percent, which was designed to increase annual revenues by $4.7 million.

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).

Oregon Senate Bill 408

The OPUC issued amended rules in September 2007 related to Oregon Senate Bill 408 (OSB 408). OSB 408 was enacted into law in 2005. These rules direct the utility to establish an automatic adjustment clause to account for the difference between income taxes collected in rates and taxes paid to units of government, net of adjustments, when that difference exceeds $100,000. The automatic adjustment clause may result in either rate increases or rate decreases and applies only to taxes paid and collected on or after January 1, 2006.

The rules provide for an “apportionment method” that uses a three-factor formula consisting of property, payroll and sales for regulated operations of the utility in Oregon as the numerator, and these same factors for the consolidated company as the denominator, to determine the amount of consolidated taxes paid that are properly attributed to Oregon operations. Under the rules, we determine the least of:

•

the properly attributed amount of taxes paid using the apportionment method,

•

the amount of taxes determined on a stand-alone basis for Oregon operations, and

•

total consolidated taxes paid.

We then compare this amount to taxes collected in rates to determine if a refund or surcharge is required.

AVISTA CORPORATION

In February 2008, we reached a settlement-in-principle with respect to the refund liability for 2006 that was approved by the OPUC in April 2008. The approved settlement provides for a refund to customers of $1.5 million, including interest. In addition to the 2006 settlement amount, we recorded a liability for potential refunds to customers totaling $1.8 million for 2007 and $0.5 million for the first quarter of 2008. In October 2008 we filed the tax report for 2007, showing taxes paid to be less than taxes collected by $2.0 million before interest. We also claimed that no refund should be made in connection with the 2007 tax report, asserting that such a refund would violate the “fair and reasonable” standard provided for under OPUC rules. Based on new rates implemented on April 1, 2008 through the Oregon general rate case, we believe that an appropriate level of taxes will be collected from our Oregon customers such that additional liabilities for potential refunds will not be required during the remainder of 2008. However, any final determination of refunds or surcharges to customers will ultimately be determined based on final calculations for the 2008 year as described above.

Natural Gas Decoupling

In January 2007, the WUTC approved the implementation of a natural gas decoupling mechanism. Decoupling separates the direct link between natural gas sales volume and the recovery of the fixed cost of providing service to our customers. 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 have been directly at odds with the recovery of fixed costs, which do not vary with the volume of natural gas sold. Our decoupling mechanism should allow us to recover lost margin resulting from lower usage by Washington customers due to conservation and price elasticity. However, the mechanism does not provide rate adjustments related to abnormal weather. The decoupling mechanism is a three-year “pilot” that began in January 2007. Continuation of the mechanism beyond June 2009 is subject to review and approval by the WUTC. A rate adjustment in any one year would be limited to no more than 2 percent. Our most recent decoupling rate adjustment became effective November 1, 2008. The rate adjustment is designed to recover $0.7 million from Washington residential and small commercial customers over a twelve month period. This represents an incremental rate increase of 0.3 percent, reflecting 90 percent of the lost margin due to conservation by the Company’s Washington residential and small commercial gas customers during the period July 2007 through June 2008.

Wind Generation Costs

In June 2008, we filed a petition with the WUTC and the IPUC requesting that costs (including land, turbine down payments and other preliminary costs) associated with wind generation projects be accounted for as construction work in progress, allowing for the accrual of an allowance for funds used during construction (AFUDC). In July 2008, the IPUC approved our request. The matter is still pending in Washington.

Power Cost Deferrals and Recovery Mechanisms

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

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

•

short-term wholesale market prices,

•

the level of hydroelectric generation,

•

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

•

retail loads.

The initial amount of power supply costs in excess of or below the level in retail rates, which we either incur the cost of, or receive the benefit from, is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 million. We incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. We will share annual power supply cost variances between $4.0 million and $10.0 million with customers. As such, 50 percent of the annual power supply cost variance in this range is deferred for future surcharge or rebate to customers and we incur the cost of, or receive the benefit from, the remaining 50 percent. 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	%
+/- excess over $10 million	90	%	10	%

Under the ERM, we make an annual filing on or before April 1st of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. On July 31, 2008, the WUTC issued an order, which approved the recovery of power costs incurred for 2007.

AVISTA CORPORATION

Based upon the September 2008 settlement stipulation with respect to our general rate case that was filed with the WUTC in March 2008, the ERM would be adjusted for the sharing level for the annual power supply cost variance in the $4.0 million to $10.0 million band. The adjustment would result in 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. The 50 percent customers/50 percent Company sharing would be maintained when actual power supply expenses are higher (surcharge to customers) than the amount included in base retail rates within this band. If approved by the WUTC, the revisions to the ERM would become effective on January 1, 2009. We expect to receive an order from the WUTC in December 2008. The following is a summary of how the ERM would be revised:


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	%

We have a Power Cost Adjustment (PCA) mechanism in Idaho that allows us to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, we defer 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for our Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding, July-June, twelve-month period. The PCA rate surcharge, as approved by the IPUC, is 0.610 cents per KWh (designed to recover $21.7 million) for the period October 1, 2008 through September 30, 2009.

The following table shows activity in deferred power costs for Washington and Idaho during the nine months ended September 30, 2008 (dollars in thousands):


	Washington			Idaho			Total
Deferred power costs as of December 31, 2007	$	58,524		$	21,163		$	79,687
Activity from January 1 – September 30, 2008:
Power costs deferred		5,612			9,276			14,888
Interest and other net additions		1,840			872			2,712
Recovery of deferred power costs through retail rates		(23,461	)		(6,968	)		(30,429	)

Deferred power costs as of September 30, 2008	$	42,515		$	24,343		$	66,858

Purchased Gas Adjustments

Effective October 1, 2008, natural gas rates increased 4.0 percent in Idaho. Effective November 1, 2008, natural gas rates increased 0.7 percent in Washington and decreased 4.1 percent in Oregon. Purchased gas adjustments (PGAs) are designed to pass through changes in natural gas costs to our customers with no change in gross margin (operating revenues less resource costs) or net income. In Oregon, the Company absorbs 10 percent of the difference between actual and projected gas costs for unhedged supply. In October 2008, the OPUC issued an order based upon an extensive review of the current PGA mechanism. The order reaffirmed the current mechanism and included several minor modifications that we believe will not have a significant impact on the Company’s gas purchasing and hedging strategies or net income. Total net deferred natural gas costs were a liability of $14.0 million as of September 30, 2008, a change from a net asset of $2.4 million as of December 31, 2007.

Results of Operations

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

Three months ended September 30, 2008 compared to the three months ended September 30, 2007

Utility revenues increased $110.0 million to $353.8 million as a result of increases in natural gas revenues of $64.1 million and electric revenues of $45.9 million. The increase in natural gas revenues was the result of increased wholesale revenues (due to both an increase in prices and volumes) of $66.0 million offset by decreased retail natural gas revenues (due to decreased price and volumes) of $2.4 million. The increase in electric revenues was due to increased retail revenues (primarily due to the Washington general rate increase implemented on January 1, 2008, partially offset by a decrease in use per customer) of $5.2 million, wholesale revenues of $18.4 million and sales of fuel of $22.1 million.

AVISTA CORPORATION

Other non-utility revenues increased $4.5 million to $22.0 million as a result of an increase in revenues from Advantage IQ primarily due to customer growth and the acquisition of Cadence Network, partially offset by a decrease in interest earnings on funds held for customers (due to a decrease in interest rates).

Utility resource costs increased $101.1 million due to increases in natural gas resource costs of $64.4 million and electric resource costs of $36.7 million. The increase in natural gas resource costs primarily reflects an increase in the volume and price of natural gas purchases. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case implemented on January 1, 2008, as well as increased thermal generation resource optimization (as described in Note 6).

Utility other operating expenses decreased $1.0 million primarily due to a decrease of $1.6 million in electric maintenance expenses, as well as an impairment of a turbine of $2.3 million in 2007. This was partially offset by an increase in administrative and general expenses of $0.7 million, electric sales and service of $0.7 million and electric distribution expenses of $1.0 million.

The net change in other non-utility operating expenses was an increase of $4.2 million due to:

•

an increase of $4.7 million for Advantage IQ due to expanding operations and the acquisition of Cadence Network effective July 2, 2008, partially offset by

•

a decrease of $0.5 million in the other businesses.

Non-utility depreciation and amortization increased $0.4 million primarily due to the amortization of intangible assets at Advantage IQ (related to the acquisition of Cadence Network).

Interest expense decreased $2.1 million due to the redemption of all outstanding preferred stock in September 2007 and the effect of long-term debt maturities during 2007 and 2008, which were primarily funded with proceeds from the sale and liquidation of Avista Energy’s assets and the issuance of long-term debt at lower interest rates. This was partially offset by interest expense of $1.4 million related to an income tax settlement.

Interest expense to affiliated trusts decreased $0.4 million due to a decrease in the variable interest rate.

Capitalized interest decreased $0.3 million due in part to a decrease in the effective AFUDC rate from 9.1 percent to 8.2 percent with the implementation of the Washington general rate case on January 1, 2008.

Other income-net increased $4.9 million primarily due to $5.7 million of interest income recorded on the IRS settlement agreement related to indirect overhead costs.

Income taxes increased $9.3 million primarily due to increased income before income taxes. Our effective tax rate was 49.3 percent for the third quarter of 2008. This high effective rate was primarily due to certain adjustments related to the settlement of IRS audits, as well as adjustments for the 2007 filed tax return.

Nine months ended September 30, 2008 compared to the nine months ended September 30, 2007

Utility revenues increased $226.7 million to $1,152.7 million as a result of increases in natural gas revenues of $127.8 million and electric revenues of $98.9 million. The increase in natural gas revenues was the result of increased wholesale revenues (due to an increase in prices and volumes) of $111.0 million and retail natural gas revenues (due to increased volumes) of $16.1 million. The increase in electric revenues was due to increased retail revenues (primarily due to the Washington general rate increase implemented on January 1, 2008) of $42.6 million, wholesale revenues of $28.2 million and sales of fuel of $28.9 million.

Non-utility energy marketing and trading revenues decreased $36.0 million to $19.1 million. This category of revenues decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

Other non-utility revenues increased $7.8 million to $57.5 million as a result of an increase in revenues from Advantage IQ of $7.1 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 remaining $0.7 million increase in other revenues was primarily due to increased sales at AM&D.

Utility resource costs increased $196.9 million due to increases in natural gas resource costs of $121.9 million and electric resource costs of $75.0 million. The increase in natural gas resource costs primarily reflects an increase in the volume and price of natural gas purchases and increased amortization of deferred natural gas costs. The increase in electric resource costs reflects an increase in base resource costs as set forth in the Washington general rate case implemented on January 1, 2008, as well as higher purchased power and fuel costs.

AVISTA CORPORATION

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

Non-utility resource costs decreased $44.7 million. This category of expenses decreased significantly with the sale of substantially all of Avista Energy’s contracts and ongoing operations on June 30, 2007.

The net change in other non-utility operating expenses was a decrease of $6.7 million due to:

•

a decrease of $13.1 million in the other businesses due to the sale of Avista Energy’s ongoing operations, partially offset by

•

an increase of $6.4 million for Advantage IQ due to expanding operations and the acquisition of Cadence Network in the third quarter of 2008.

Interest expense decreased $3.0 million due to the redemption of all outstanding preferred stock in September 2007 and the effect of long-term debt maturities during 2007 and 2008, which were primarily funded with proceeds from the sale and liquidation of Avista Energy’s assets and debt issuances at lower interest rates. This was partially offset by interest expense of $1.4 million related to an income tax settlement recorded during the third quarter of 2008.

Interest expense to affiliated trusts decreased $0.8 million due to a decrease in the variable interest rate.

Capitalized interest decreased $1.0 million due in part to a decrease in the effective AFUDC rate from 9.1 percent to 8.2 percent with the implementation of the Washington general rate case on January 1, 2008.

Other income-net decreased $0.4 million due to a decrease in interest income of $4.7 million. The decrease in interest income was primarily due to the disposition of Avista Energy’s ongoing operations. This decrease was offset by $5.7 million of interest income recorded on the IRS settlement agreement related to indirect overhead costs.

Income taxes increased $21.4 million primarily due to increased income before income taxes. Our effective tax rate was 38.8 percent for the nine months ended September 30, 2008 compared to 36.7 percent for the nine months ended September 30, 2007. This increase in the effective tax rate was primarily due to certain adjustments related to the settlement of IRS audits, as well as adjustments for the 2007 filed tax return recorded during the third quarter of 2008.

Avista Utilities

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Net income for the utility was $6.5 million for the three months ended September 30, 2008 compared to a net loss of $5.6 million for the three months ended September 30, 2007. Utility income from operations was $22.2 million for the three months ended September 30, 2008 compared to $13.1 million for the three months ended September 30, 2007. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs).

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
	2008		2007		2008		2007		2008		2007
Operating revenues	$	217,995	$	172,043	$	135,829	$	71,755	$	353,824	$	243,798
Resource costs		123,386		86,702		121,741		57,357		245,127		144,059

Gross margin	$	94,609	$	85,341	$	14,088	$	14,398	$	108,697	$	99,739

Utility operating revenues increased $110.0 million and utility resource costs increased $101.1 million, which resulted in an increase of $9.0 million in gross margin. The gross margin on electric sales increased $9.3 million and the gross margin on natural gas sales decreased $0.3 million. The increase in our electric gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2008 and a benefit of $0.1 million under the ERM in the third quarter of 2008, compared to an expense of $5.2 million in the third quarter of 2007. The slight decrease in natural gas gross margin was primarily due to a decrease in use per customer, partially offset by the Washington general rate increase implemented on January 1, 2008.

AVISTA CORPORATION

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
	2008		2007		2008	2007
Residential	$	54,701	$	55,462	764	785
Commercial		63,307		58,629	828	826
Industrial		26,159		25,028	536	545
Public street and highway lighting		1,482		1,372	6	6

Total retail		145,649		140,491	2,134	2,162
Wholesale		42,063		23,664	495	303
Sales of fuel		25,510		3,459	—	—
Other		4,773		4,429	—	—

Total	$	217,995	$	172,043	2,629	2,465

Retail electric revenues increased $5.2 million due to:

•

an increase in revenue per MWh (increased revenues $7.0 million) primarily due to the Washington general rate increase implemented on January 1, 2008, partially offset by

•

a decrease in total MWhs sold (decreased revenues $1.8 million) primarily due a decrease in use per customer.

Wholesale electric revenues increased $18.4 million due to an increase in sales prices (increased revenues $2.1 million) and an increase in sales volumes (increased revenues $16.3 million).

When electric wholesale market prices are below the cost of operating our natural gas-fired thermal generating units, we sell the natural gas purchased for generation in the wholesale market as sales of fuel. Sales of fuel increased $22.1 million due to increased thermal generation resource optimization activities.

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
	2008		2007		2008	2007
Residential	$	20,766	$	21,950	13,467	13,946
Commercial		13,849		15,363	11,148	11,949
Interruptible		1,240		939	1,321	922
Industrial		1,221		1,235	1,160	1,080

Total retail		37,076		39,487	27,096	27,897
Wholesale		95,965		29,941	117,473	54,892
Transportation		1,358		1,504	34,094	31,654
Other		1,430		823	17	13

Total	$	135,829	$	71,755	178,680	114,456

The $2.4 million decrease in retail natural gas revenues was due to a decrease in volumes (decreased revenues $1.1 million), and lower retail rates (decreased revenues $1.3 million). The decrease in retail rates reflects purchased gas adjustments implemented in the fourth quarter of 2007, partially offset by the Washington general rate increase implemented on January 1, 2008. The increase in our wholesale revenues of $66.0 million was due to an increase in prices (increased revenues $14.9 million) and an increase in volumes (increased revenues $51.1 million). Wholesale sales reflect the balancing of loads and resources and the sale of resources in excess of load requirements as part of the natural gas procurement process. 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
	2008	2007	2008	2007
Residential	310,474	306,259	276,485	272,189
Commercial	39,069	38,525	32,793	32,256
Interruptible	—	—	42	43
Industrial	1,393	1,389	259	264
Public street and highway lighting	437	426	—	—

Total retail customers	351,373	346,599	309,579	304,752

AVISTA CORPORATION

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


	2008			2007
Electric resource costs:
Power purchased	$	48,287		$	45,444
Power cost amortizations (deferrals), net		8,239			(7,913	)
Fuel for generation		37,104			37,875
Other fuel costs		22,254			4,065
Other regulatory amortizations, net		1,223			3,098
Other electric resource costs		6,279			4,133

Total electric resource costs		123,386			86,702

Natural gas resource costs:
Natural gas purchased		121,859			57,989
Natural gas deferrals, net of amortizations		(670	)		(1,605	)
Other regulatory amortizations, net		552			973

Total natural gas resource costs		121,741			57,357

Total resource costs	$	245,127		$	144,059

Power purchased increased $2.8 million due in part to an increase in the price of wholesale power (increased costs $9.2 million). The increase was offset by a decrease in the volume of power purchases (decreased costs $6.4 million) primarily due to increased hydroelectric generation.

Net amortization of deferred power costs was $8.2 million for the third quarter of 2008 compared to net deferrals of $7.9 million for the third quarter of 2007. During the third quarter of 2008, we recovered (collected as revenue) $7.2 million of previously deferred power costs in Washington and $2.2 million in Idaho. During the third quarter of 2008, we reduced our deferral of power costs by $1.3 million in Washington, as power supply costs were less than the amount included in base retail rates. During the third quarter of 2008, we deferred $2.4 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation decreased $0.8 million due to a decrease in thermal generation volumes (particularly Coyote Springs 2) and a decrease in fuel prices (particularly natural gas).

Other fuel costs increased $18.2 million. This represents fuel that was purchased for generation, but was later sold as part of the resource optimization process when conditions indicated that it was not economic to use the fuel in generation. The associated revenues are reflected as sales of fuel. Other fuel costs were less than the revenues we received from selling the natural gas. We account for this difference under the ERM in Washington and the PCA in Idaho. The increase in other fuel costs was primarily due to increased thermal generation resource optimization activities and increased fuel prices.

The expense for natural gas purchased increased $63.9 million due to an increase in natural gas prices and 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 and an increase in wholesale sales volumes. During the third quarter of 2008, we deferred $0.7 million of natural gas costs compared to $1.6 million for the third quarter of 2007. This change reflects an increase in natural gas prices and the deferral for future recovery from customers.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Net income for the utility was $51.8 million for the nine months ended September 30, 2008 compared to $31.6 million for the nine months ended September 30, 2007. Utility income from operations was $132.0 million for the nine months ended September 30, 2008 compared to $109.1 million for the nine months ended September 30, 2007. This increase in income from operations was primarily due to increased gross margin (operating revenues less resource costs). This was partially offset by an increase in other utility operating expenses, 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
	2008		2007		2008		2007		2008		2007
Operating revenues	$	624,904	$	526,020	$	527,837	$	400,041	$	1,152,741	$	926,061
Resource costs		305,628		230,667		440,800		318,898		746,428		549,565

Gross margin	$	319,276	$	295,353	$	87,037	$	81,143	$	406,313	$	376,496

AVISTA CORPORATION

Utility operating revenues increased $226.7 million and utility resource costs increased $196.9 million, which resulted in an increase of $29.8 million in gross margin. The gross margin on electric sales increased $23.9 million and the gross margin on natural gas sales increased $6.0 million. The increase in our electric and natural gas gross margin was primarily due to the implementation of general rate increases in Washington effective January 1, 2008. The increase was also partially due to colder weather in 2008 during the heating season and customer growth.

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
	2008		2007		2008	2007
Residential	$	198,717	$	177,138	2,696	2,626
Commercial		182,705		166,469	2,378	2,329
Industrial		75,664		71,211	1,565	1,564
Public street and highway lighting		4,434		4,145	19	19

Total retail		461,520		418,963	6,658	6,538
Wholesale		110,958		82,762	1,506	1,322
Sales of fuel		40,498		11,608	—	—
Other		11,928		12,687	—	—

Total	$	624,904	$	526,020	8,164	7,860

Retail electric revenues increased $42.6 million due to an increase in:

•

total MWhs sold (increased revenues $8.4 million) primarily due to customer growth and an increase in use per customer (primarily due to colder weather), and

•

revenue per MWh (increased revenues $34.2 million) primarily due to the Washington general rate increase implemented on January 1, 2008 and the reduction in the BPA residential exchange credit.

Wholesale electric revenues increased $28.2 million due to an increase in sales prices (increased revenues $14.6 million), and an increase in sales volumes (increased revenues $13.6 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 increased $28.9 million due to increased thermal generation resource optimization activities.

Other electric revenues decreased $0.8 million primarily due to a decrease in transmission revenues.

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
	2008		2007		2008	2007
Residential	$	184,809	$	173,068	139,203	124,471
Commercial		103,654		99,268	86,729	79,707
Interruptible		3,738		3,795	3,936	3,728
Industrial		4,511		4,493	4,312	4,054

Total retail		296,712		280,624	234,180	211,960
Wholesale		222,259		111,232	253,636	176,552
Transportation		4,945		5,080	110,542	109,419
Other		3,921		3,105	409	316

Total	$	527,837	$	400,041	598,767	498,247

The $16.1 million increase in retail natural gas revenues was due to an increase in volumes (increased revenues $28.2 million), partially offset by lower retail rates (decreased revenues $12.1 million). We sold more retail natural gas in the first nine months of 2008 primarily due to colder weather during the heating season and customer growth. The decrease in retail rates reflects the purchased gas adjustments implemented in the fourth quarter of 2007, partially offset by the Washington general rate increase implemented on January 1, 2008. The increase in our wholesale revenues of $111.0 million was due to an increase in prices (increased revenues $43.5 million) and an increase in volumes (increased revenues $67.5 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. Variances between the revenues and costs of the sale of resources in excess of load requirements are accounted for through the PGA mechanisms.

AVISTA CORPORATION

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
	2008	2007	2008	2007
Residential	310,889	305,790	277,423	272,615
Commercial	39,056	38,400	32,876	32,247
Interruptible	—	—	39	41
Industrial	1,388	1,376	257	261
Public street and highway lighting	432	425	—	—

Total retail customers	351,765	345,991	310,595	305,164

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


	2008		2007
Electric resource costs:
Power purchased	$	139,443	$	113,435
Power cost amortizations, net of deferrals		15,540		7,116
Fuel for generation		92,630		84,246
Other fuel costs		37,605		14,984
Other regulatory amortizations, net		7,697		914
Other electric resource costs		12,713		9,972

Total electric resource costs		305,628		230,667

Natural gas resource costs:
Natural gas purchased		419,215		306,149
Natural gas amortizations, net of deferrals		15,977		7,431
Other regulatory amortizations, net		5,608		5,318

Total natural gas resource costs		440,800		318,898

Total resource costs	$	746,428	$	549,565

Power purchased increased $26.0 million due in part to an increase in wholesale prices (increased costs $19.9 million). The increase was also due to an increase in the volume of power purchases (increased costs $6.1 million) primarily due to an increase in retail sales volumes (due to colder weather and customer growth).

Net amortization of deferred power costs was $15.5 million for the nine months ended September 30, 2008 compared to $7.1 million for the nine months ended September 30, 2007. During the nine months ended September 30, 2008, we recovered (collected as revenue) $23.5 million of previously deferred power costs in Washington and $7.0 million in Idaho. During the nine months ended September 30, 2008, we deferred $5.6 million of power costs in Washington and $9.3 million of power costs in Idaho, as power supply costs exceeded the amount included in base retail rates.

Fuel for generation increased $8.4 million due to an increase in thermal generation volumes (particularly Coyote Springs 2) and an increase in fuel prices (particularly natural gas).

Other fuel costs increased $22.6 million. This represents fuel that was purchased for generation, but was later sold when conditions indicated that it was not economic to use the fuel in generation as part of the resource optimization process. The associated revenues are reflected as sales of fuel. Other fuel costs were less than the revenues we received from selling the natural gas. We account for this difference under the ERM in Washington and the PCA in Idaho. The increase in other fuel costs was primarily due to increased thermal generation resource optimization activities and increased fuel prices.

Other regulatory amortizations increased $6.8 million primarily due to the reduction in the BPA residential exchange credit.

The expense for natural gas purchased increased $113.1 million due to an increase in total therms purchased and the price of natural gas. The increase in total therms purchased was due to an increase in wholesale sales as part of the balancing of loads and resources as part of the natural gas procurement process and an increase in retail sales volumes. During the nine months ended September 30, 2008, we amortized $16.0 million of deferred natural gas costs compared to $7.4 million for the nine months ended September 30, 2007.

AVISTA CORPORATION

Advantage IQ

Effective July 2, 2008, Advantage IQ acquired Cadence Network. Beginning in the third quarter of 2008, results from Advantage IQ include Cadence Network and reflect our reduced ownership percentage in the business.

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Net income for Advantage IQ was $1.3 million for the three months ended September 30, 2008 compared to $2.1 million for the three months ended September 30, 2007. Operating revenues increased $4.6 million and operating expenses increased $5.2 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base and the acquisition of Cadence Network, partially offset by a decrease in interest revenue on funds held for customers (due to lower interest rates). As of September 30, 2008, Advantage IQ had 528 customers representing 415,000 billed sites in North America, an increase from 403 customers and 199,000 billed sites as of December 31, 2007. The September 30, 2008 amounts include customers and sites of Cadence Network. The increase in operating expenses primarily reflects increased labor and other operational costs from Cadence Network.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Net income for Advantage IQ was $4.7 million for the nine months ended September 30, 2008 compared to $5.0 million for the nine months ended September 30, 2007. Operating revenues increased $7.1 million and operating expenses increased $6.9 million. The increase in operating revenues was primarily due to the expansion of Advantage IQ’s customer base and the third quarter acquisition of Cadence Network, partially offset by a decrease in interest revenue on funds held for customers (due to a decrease in interest rates). The increase in operating expenses primarily reflects increased labor and other operational costs necessary to serve an expanding customer base, as well as the third quarter acquisition of Cadence Network (including the amortization of intangible assets). In the first nine months of 2008, Advantage IQ processed bills totaling $12.2 billion, an increase of $2.9 billion, or 31 percent, as compared to the first nine months of 2007.

Other Businesses

Three months ended September 30, 2008 compared to three months ended September 30, 2007

The net loss from these operations was $0.4 million for the three months ended September 30, 2008 and September 30, 2007. Operating revenues increased $0.4 million and operating expenses decreased $0.6 million. The remaining non-utility energy marketing and trading revenues and non-utility resource 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. Beginning in 2010 through 2026, the rights and obligations of the power purchase agreement for the Lancaster Plant will be contracted to Avista Energy. We expect that these rights and obligations will be transferred to our regulated utility, subject to future approval by the WUTC and the IPUC.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Net loss from these operations was $0.3 million for the nine months ended September 30, 2008 compared to a net loss of $12.2 million for the nine months ended September 30, 2007. Operating revenues decreased $35.4 million and operating expenses decreased $58.3 million. The net loss for 2007 and the decrease in operating revenues and expenses was primarily due to Avista Energy.

New Accounting Standards

Effective January 1, 2008, we adopted the majority of the provisions of SFAS No. 157, “Fair Value Measurements,” related to our financial assets and liabilities and nonfinancial assets and liabilities measured at fair value on a recurring basis. In February 2008, the FASB issued Staff Position No. 157-2, which deferred the effective date for certain portions of SFAS No. 157 related to nonrecurring measurements of nonfinancial assets and liabilities. We will be required to adopt those provisions of SFAS No. 157 in 2009. The adoption of the provisions of SFAS No. 157 that became effective on January 1, 2008 did not have a material impact on our financial condition and results of operations; however, we expanded our disclosures with respect to fair value measurements. See “Note 12 of the Notes to Consolidated Financial Statements” for further information.

Effective January 1, 2008, we adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option is elected would be reported in net income. As we did not elect to use the fair value option under SFAS No. 159 for any financial assets and liabilities at implementation, the adoption of SFAS No. 159 did not have any impact on our financial condition and results of operations.

AVISTA CORPORATION

Effective January 1, 2008 we adopted FASB Staff Position (FSP) FIN 39-1, “Amendment of FASB Interpretation No. 39”. FSP FIN 39-1 amends certain paragraphs of FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts, an interpretation of APB Opinion No. 10 and FASB Statement No. 105”. This statement permits us to offset fair value amounts recognized for the right to reclaim or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. As of September 30, 2008 we did not offset any fair value cash collateral receivables against net derivative positions. As of December 31, 2007, the retrospective application of FSP FIN 39-1 had no impact on our Consolidated Balance Sheet. The fair value of cash collateral that was not offset in the Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007 was $16.9 million and $12.5 million respectively.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations.” This statement replaces SFAS No. 141 and addresses the accounting for all transactions or other events in which an entity obtains control of one or more businesses. We will be required to begin applying this statement to any business combinations in 2009.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to establish accounting and reporting standards from noncontrolling (minority) interest in a subsidiary and for the deconsolidation of a subsidiary. We will be required to adopt SFAS No. 160 in 2009. We are evaluating the impact SFAS No. 160 will have on our financial condition and results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This statement will require disclosure of the fair value of derivative instruments and their gains and losses in a tabular format. The statement will also require disclosure of derivative features that are related to credit risk. We will be required to adopt SFAS No. 161 in 2009. We do not expect the adoption of SFAS No. 161 to have any impact on our financial condition and results of operations. However, we will have expanded disclosures with respect to derivatives and hedging activities.

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect amounts reported in the consolidated financial statements. Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on our consolidated financial statements and thus actual results could differ from the amounts reported and disclosed herein. Our critical accounting policies that require the use of estimates and assumptions were discussed in detail in the 2007 Form 10-K and have not changed materially from that discussion.

Liquidity and Capital Resources

Review of Cash Flow Statement

Overall In April 2008, we issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $249.2 million (net of issuance discount and before Avista Corp.’s expenses), together with other available funds, were used to fund debt maturities of $295.0 million (the majority being the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008). During the nine months ended September 30, 2008, positive cash flows from operating activities of $131.9 million and an $86.5 million increase in short-term borrowings were used to fund the majority of our remaining cash requirements. These cash requirements included utility capital expenditures of $150.1 million, the cash settlement of interest rate swap agreements of $16.4 million and dividends of $27.3 million.

Operating Activities Net cash provided by operating activities was $131.9 million for the nine months ended September 30, 2008 compared to $163.6 million for the nine months ended September 30, 2007. Net cash used by working capital components was $19.7 million for the nine months ended September 30, 2008, compared to net cash provided of $36.7 million for the nine months ended September 30, 2007. The net cash used during the nine months ended September 30, 2008 primarily reflects 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).

The net cash provided during the nine months ended September 30, 2007 primarily reflects positive cash flows from:

•

accounts receivable (representing net cash received from our customers),

•

deposits with counterparties (representing the return from counterparties of cash posted as collateral at Avista Energy).

AVISTA CORPORATION

This cash provided was partially offset by negative cash flows from accounts payable (representing net cash paid to our vendors) and deposits from counterparties (representing cash returned that was held as collateral funds from counterparties at Avista Utilities).

Significant changes in non-cash items also included the unrealized loss of $24.6 million on energy trading activities at Avista Energy for 2007. There was also a change in deferred income taxes to an expense of $5.7 million for the nine months ended September 30, 2008 from a benefit of $10.0 million for the nine months ended September 30, 2007. Income tax payments decreased to $28.1 million for the nine months ended September 30, 2008 compared to $28.8 million for the nine months ended September 30, 2007.

Investing Activities Net cash used in investing activities was $153.3 million for the nine months ended September 30, 2008, an increase compared to $125.7 million for the nine months ended September 30, 2007. This increase was primarily due to a change in restricted cash. We liquidated $28.6 million of restricted cash in the first nine months of 2007 representing the return of cash collateralizing energy contracts at Avista Energy and interest rate swap agreements at Avista Corp.

The purchase of subsidiary minority interest of $8.6 million primarily represents the redemption of common stock from employees of Advantage IQ. Advantage IQ’s employee stock incentive plan provides an annual window at which time holders of common stock can put their shares back to Advantage IQ providing the shares are held for a minimum of six months. Stock is reacquired at fair market value upon the date of reacquisition.

Financing Activities Net cash provided by financing activities was $24.6 million for the nine months ended September 30, 2008 compared to net cash used of $60.9 million for the nine months ended September 30, 2007. 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 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. Cash dividends paid increased to $27.3 million (or 51 cents per share) for the nine months ended September 30, 2008 from $23.5 million (or 44.5 cents per share) for the nine months ended September 30, 2007. 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.

During the first nine months of 2007, our short-term borrowings decreased $4.0 million, which reflected a decrease in the amount of debt outstanding under Avista Corp.’s committed line of credit. Debt maturities were $12.6 million for the nine months ended September 30, 2007 and we redeemed the remaining $26.3 million of our preferred stock outstanding as required.

AVISTA CORPORATION

Overall Liquidity

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

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

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

We periodically file for rate adjustments for recovery of operating costs and capital investments to provide the opportunity to align our earned returns with those allowed by regulators. Effective January 1, 2008, the WUTC authorized an increase in our rates in Washington designed to increase annual electric revenues by $30.2 million and annual natural gas revenues by $3.3 million. Effective October 1, 2008, the IPUC authorized an increase in our rates in Idaho designed to increase annual electric revenues by $23.2 million and annual natural gas revenues by $3.9 million. See further details in the section “Avista Utilities - Regulatory Matters.”

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

•

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

•

low availability of streamflows for hydroelectric generation,

•

unplanned outages at generating facilities, and

•

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

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

•

$85.0 million revolving accounts receivable sales facility, and

•

$320.0 million committed line of credit.

As of September 30, 2008, we had $202.9 million of available liquidity under our $320.0 million committed line of credit and $85.0 million revolving accounts receivable sales facility.

Our utility has regulatory mechanisms in place that provide for the ultimate 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.

Credit and Nonperformance Risk

Our contracts for the purchase and sale of energy commodities often require collateral (in the form of cash or letters of credit) or other credit enhancements, or reductions or terminations of a portion of the contract through cash settlement in the event of a downgrade in our credit ratings or adverse changes in market prices. For example, in addition to limiting our ability to conduct transactions, if our credit ratings were lowered to below investment grade and energy prices decreased by 15 percent in the first year and 20 percent in subsequent years, we estimate, based on our positions outstanding at September 30, 2008, that we would have had to post additional collateral of approximately $125 million.

Our utility held cash deposits from other parties in the amount of $16.9 million as of September 30, 2008, an increase from $12.5 million as of December 31, 2007. These amounts are subject to return if conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of collateral. If these amounts are returned, it would most likely be funded through borrowings under our $320.0 million committed line of credit or sales of accounts receivable under our $85.0 million revolving accounts receivable sales financing facility.

AVISTA CORPORATION

Capital Resources

Our consolidated capital structure, including the current portion of long-term debt and short-term borrowings, consisted of the following as of September 30, 2008 and December 31, 2007 (dollars in thousands):


	September 30, 2008				December 31, 2007
	Amount		Percent of total		Amount		Percent of total
Current portion of long-term debt	$	108,916	5.2	%	$	427,344	21.6	%
Short-term borrowings		86,500	4.2			—	—
Long-term debt to affiliated trusts		113,403	5.5			113,403	5.8
Long-term debt		778,913	37.7			521,489	26.4

Total debt		1,087,732	52.6			1,062,236	53.8
Stockholders’ equity		978,652	47.4			913,966	46.2

Total	$	2,066,384	100.0	%	$	1,976,202	100.0	%

We need to finance capital expenditures and obtain additional working capital from time to time. The cash requirements needed to service our indebtedness, both short-term and long-term, reduces the amount of cash flow available to fund capital expenditures, working capital, purchased power and natural gas costs, dividends and other requirements. Our stockholders’ equity increased $64.7 million during the nine months ended September 30, 2008 primarily due to net income, other comprehensive income and the issuance of common stock under the sales agency agreement and other plans, partially offset by dividends.

We generally fund capital expenditures with a combination of internally generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates depending on a variety of factors. Cash provided by our utility operating activities is expected to be the primary source of funds for operating needs, dividends and capital expenditures for the fourth quarter of 2008. Borrowings under our $320.0 million committed line of credit may supplement these funds, on an interim basis, to the extent necessary.

During the nine months ended September 30, 2008 debt maturities were $295.0 million, the majority being the $273 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008. On April 3, 2008, we issued $250 million (net proceeds of $249.2 million before Company expenses) of 5.95 percent First Mortgage Bonds to fund a significant portion of this debt that matured.

We have a $320.0 million committed line of credit agreement with various banks with an expiration date of April 5, 2011. Under the agreement, we can request the issuance of up to $320.0 million in letters of credit. As of September 30, 2008, we had $85.0 million of borrowings outstanding under this committed line of credit. There were not any borrowings outstanding as of December 31, 2007. As of September 30, 2008, there were $35.1 million in letters of credit outstanding, an increase from $34.8 million as of December 31, 2007. 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.

Our committed line of credit agreement contains 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, 2008, we were in compliance with this covenant with a ratio of 3.2 to 1. The committed line of credit agreement also has a covenant which does not permit our ratio of “consolidated total debt” to “consolidated total capitalization” to be greater than 70 percent at the end of any fiscal quarter. As of September 30, 2008, we were in compliance with this covenant with a ratio of 52.6 percent. If the proposed change in organization to a holding company structure becomes effective, the committed line of credit agreement will remain at Avista Corp. (Avista Utilities). See “Note 15 of the Notes to Consolidated Financial Statements” for further information on the proposed change in organization to a holding company structure.

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 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, 2008, Avista Corp. and our subsidiaries were in compliance with all of the covenants of our financing agreements.

AVISTA CORPORATION

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

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

•

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

•

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

•

deposit of cash

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

In December 2005, the WUTC issued an order approving the settlement agreement reached in our Washington general rate case with certain conditions. We agreed to increase the utility equity component to 35 percent by the end of 2007 and to 38 percent by the end of 2008. As further discussed at “Note 15 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation that we entered with the IPUC Staff that sets forth a variety of conditions related to the proposed implementation of our holding company structure. One of the conditions provides for the same utility equity components that are required in our Washington general rate case implemented in January 2006. If we do not meet those targets, it could result in a reduction in base rates of 2 percent for each target in each of Washington and Idaho. The utility equity component was approximately 47 percent as of September 30, 2008.

Advantage IQ Credit Agreement

In February 2008, Advantage IQ entered into a $12.5 million three-year credit agreement with Bank of America, N.A. Advantage IQ has the ability to increase the credit facility to $25 million under the same agreement. The credit agreement is secured by substantially all of Advantage IQ’s assets. Advantage IQ had $1.5 million of borrowings outstanding under the credit agreement as of September 30, 2008.

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 14, 2008, 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 17, 2008 to March 13, 2009.

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

•

working capital requirements,

•

capital expenditures, and

•

other general corporate needs.

Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.0 million of our receivables. ARC is obligated to pay fees that approximate the purchaser’s cost of issuing commercial paper equal in value to the interests in receivables sold. The Receivables Purchase Agreement has financial covenants, which are substantially the same as those of our $320.0 million committed line of credit. As of September 30, 2008, we had the ability to sell up to $57.0 million of receivables and there was $54.0 million in accounts receivable sold under this revolving agreement.

AVISTA CORPORATION

Credit Ratings

The following table summarizes our credit ratings as of October 31, 2008:


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

(1)	Ratings were upgraded in February 2008.

(2)	Ratings were upgraded in December 2007.

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

(4)

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

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

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

Pension Plan

As of September 30, 2008, our pension plan had assets with a fair value that was less than the benefit obligation under the plan. We contributed $15 million to the pension plan in both 2006 and 2007. We contributed $28 million to the pension plan in 2008. The increase from our original planned contribution of $15 million was a result of the new funding rules under the Pension Protection Act of 2006 and our ongoing commitment to increasing the funded status of the plan. Due to recent market conditions and the decline in the fair value of pension plan assets, our contributions to the pension plan in 2009 could increase significantly as compared to 2008. The final determination of pension plan contributions for 2009 and future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We believe that we have adequate liquidity to meet our pension plan funding obligations for 2009.

Dividends

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

•

our results of operations, cash flows and financial condition,

•

the success of our business strategies, and

•

general economic and competitive conditions.

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

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

In September 2008, Avista Corp. paid a quarterly dividend of $0.18 per share on its common stock, an increase of 9 percent or $0.015 per share, over the previous quarterly dividend.

As further discussed at “Note 15 of the Notes to the Consolidated Financial Statements,” the IPUC accepted a stipulation that we entered with the IPUC Staff that sets forth a variety of conditions if and when we implement a holding company structure. One of the conditions would require IPUC approval of any dividend to the holding

AVISTA CORPORATION

company that would reduce utility common equity below 25 percent. We entered into a similar agreement in Washington. This agreement would require WUTC approval of any dividend to the holding company that would reduce utility common equity below 30 percent. The utility equity component was approximately 47 percent as of September 30, 2008.

Avista Utilities Capital Expenditures

We expect utility capital expenditures to be approximately $200 million for 2008, and over $200 million in each of 2009 and 2010. In addition to ongoing needs for our distribution and transmission systems, significant projects include upgrades to generating facilities. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from our estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.

In the second quarter of 2008, we completed the acquisition of a wind generation site. We expect to construct a 50 MW generation facility at an estimated cost of over $125 million with the majority of the costs expected to be incurred between 2011 and 2013. This amount is not included in our estimates of utility capital expenditures disclosed above. 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 project development and planning activities for the development of a proposed 3,000 MW transmission project that would extend from British Columbia, Canada to Northern California. Other participants include Pacific Gas and Electric Company, PacifiCorp, and British Columbia Transmission Corporation. We have executed an agreement (stage one agreement) with the other participants in order to perform preliminary studies and assessments for the project, including electrical system studies and resource mapping of possible transmission line corridors. Under the stage one agreement, we have committed to contribute $0.4 million, or 12 percent of the total stage one costs of the project.

Contractual Obligations

Our future contractual obligations have not changed materially from the amounts disclosed in the 2007 Form 10-K with the following exceptions:

As of September 30, 2008, we had $85.0 million of borrowings outstanding under our $320.0 million committed line of credit. There were not any borrowings outstanding as of December 31, 2007.

There was $54.0 million of accounts receivable sold under our revolving accounts receivable sales financing facility as of September 30, 2008, a decrease from $85.0 million as of December 31, 2007. In March 2008, the termination date of this facility was extended from March 17, 2008 to March 13, 2009.

We contributed $28 million to the pension plan in 2008. Our estimated contribution in each of 2009, 2010, 2011 and 2012 is expected to be at least $18 million. Our prior estimate was $15 million for each year. The contribution for 2008 exceeded our minimum required contribution. Due to recent market conditions and the decline in the fair value of pension plan assets, our contributions to the pension plan in 2009 could increase significantly as compared to 2008. The final determination of pension plan contributions for 2009 and future periods is subject to multiple variables, most of which are beyond our control, including further changes to the fair value of pension plan assets and changes in actuarial assumptions (in particular the discount rate used in determining the projected benefit obligation). We believe that we have adequate liquidity to meet our pension plan funding obligations for 2009.

On April 3, 2008, we issued $250.0 million of 5.95 percent First Mortgage Bonds due in 2018. The net proceeds from the issuance of $249.2 million (net of issuance discount and before our expenses), together with other available funds, were used to pay the $272.9 million of 9.75 percent Unsecured Senior Notes that matured on June 1, 2008.

Business Risk

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

•

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

•

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

AVISTA CORPORATION

•

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

•

regulatory disallowance of the recovery of power and natural gas costs, operating costs and capital investments,

•

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

•

changes in regulatory requirements,

•

availability of generation facilities, and

•

competition.

Also, like other utilities, our facilities and operations are exposed to natural disasters and terrorism risks or other malicious acts. See further reference to risks and uncertainties under “Forward-Looking Statements.”

Our business risk has not materially changed during the nine months ended September 30, 2008. Please refer to the 2007 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 a risk management policy and control procedures to manage these risks, both qualitative and quantitative. Please refer to the 2007 Form 10-K for discussion of risk management policies and procedures.

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 all 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.

Environmental laws and regulations may have the effect of:

•

increasing the costs of capital projects,

•

increasing the lead time for the construction of new capital projects,

•

requiring modification of our existing utility plant,

•

requiring existing capital assets to be curtailed or shut down,

•

increasing the risk of delay on construction projects,

•

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

•

restricting the types of capital projects that can be built.

As such, compliance with such environmental laws and regulations could result in increases to capital expenditures and operating expenses, as well as reductions in net generation. However, we intend to seek recovery of incurred costs through the ratemaking process.

Long-term global climate changes could have a significant effect on our business. 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. 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.

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

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

In February 2007, the Governors of Arizona, California, New Mexico, Oregon and Washington started the Western Climate Initiative (WCI) for the purpose of developing regional strategies to address climate change. The Governors of Utah and Montana, and the Premiers of British Columbia, Manitoba, Ontario and Quebec subsequently joined the WCI. In August 2007, the WCI partners set an overall regional goal for reducing greenhouse gas emissions to 15

AVISTA CORPORATION

percent below 2005 levels by 2020. In September 2008, the WCI partners announced recommendations for the design of a regional market-based cap-and-trade program to help achieve this reduction goal. The program will require emitters to cut their pollution by setting a limit (cap) on emissions and then allowing the market to identify the least-cost ways to achieve the limit.

The greenhouse gas bill passed into law in the state of Washington during 2007 places significant restrictions on greenhouse gas emissions from any new generation plants built in the state of Washington. Furthermore, utilities are prevented from entering into contracts to purchase energy produced by plants in other states that do not meet the same restrictions. Currently, the only type of thermal generating plants that meet these restrictions are combined-cycle natural gas-fired generation turbines. This greenhouse gas bill sets goals to reduce emissions in the state of Washington to 1990 levels by 2020; to 25 percent below 1990 levels by 2035; and to 50 percent below 1990 levels by 2050.

Initiative Measure 937 (I-937) was passed into law through the General Election in Washington in November 2006. I-937 requires certain investor-owned, cooperative, and government-owned electric utilities (including Avista Corp.) 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 September 2007, includes the acquisition of additional renewable resources such that, if the IRP is implemented, we would be compliant with the requirement by the various milestone dates. The IRP outlines a preferred resource strategy that calls for 350 MW of natural gas generation, 300 MW of wind generation, 87 MW of conservation, 38 MW of hydroelectric generation plant upgrades and 35 MW of other renewable generation by 2017. The amount of renewable resources in our future IRPs could change if the cost effectiveness of those resources changes.

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

For other environmental issues and other contingencies see “Note 14 of the Notes to 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 6 of the Notes to Consolidated Financial Statements” and “Note 12 of the Notes to 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, 2008.

AVISTA CORPORATION

There have been no changes in the Company’s internal control over financial reporting that occurred during the third quarter of 2008 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 14 of the Notes to Consolidated Financial Statements” in “Part I. Financial Information Item 1. Consolidated Financial Statements.”

Item 1A.

Risk Factors

Please refer to the 2007 Form 10-K for disclosure of risk factors that could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Quarterly Report on Form 10-Q), and elsewhere. These risk factors have not materially changed from the disclosures provided in the 2007 Form 10-K.

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

Item 6.

Exhibits



12		Computation of ratio of earnings to fixed charges and preferred dividend requirements*

15		Letter Re: Unaudited Interim Financial Information*

31.1		Certification of Chief Executive Officer*

31.2		Certification of Chief Financial Officer*

32		Certification of Corporate Officers (Furnished Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)**

*	Filed herewith.

**	Furnished herewith.

AVISTA CORPORATION

SIGNATURE

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


				AVISTA CORPORATION (Registrant)

Date: November 5, 2008				/s/ Mark T. Thies
				Mark T. Thies
				Senior Vice President and
				Chief Financial Officer
				(Principal Financial Officer)